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, 2021

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 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
The Southern Company	Series 2021B 1.875% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2081	SO 81	NYSE
Alabama Power Company	5.00% Series Class A Preferred Stock	ALP PR Q	NYSE
Georgia Power Company	Series 2017A 5.00% Junior Subordinated Notes due 2077	GPJA	NYSE
Southern Power Company	Series 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, 2021
The Southern Company	Par Value $5 Per Share	1,059,803,931
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	102
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	162
Item 4.	Controls and Procedures	162
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	163
Item 1A.	Risk Factors	163
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	163
	Signatures	166

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DEFINITIONS

Term	Meaning
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
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
Bechtel	Bechtel Power Corporation, the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4
Bechtel Agreement	The 2017 construction completion agreement between the Vogtle Owners and Bechtel
CCR	Coal combustion residuals
CCR Rule	Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015
Chattanooga Gas	Chattanooga Gas Company, a wholly-owned subsidiary of Southern Company Gas
COD	Commercial operation date
Contractor Settlement Agreement	The December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the Vogtle 3 and 4 Agreement
COVID-19	The novel coronavirus disease declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention in March 2020
CWIP	Construction work in progress
Dalton	City of Dalton, Georgia, an incorporated municipality in the State of Georgia, acting by and through its Board of Water, Light, and Sinking Fund Commissioners
Dalton Pipeline	A pipeline facility in Georgia in which Southern Company Gas has a 50% undivided ownership interest
DOE	U.S. Department of Energy
ECCR	Georgia Power's Environmental Compliance Cost Recovery tariff
ECO Plan	Mississippi Power's environmental compliance overview plan
ELG Rules	The EPA's steam electric effluent limitations guidelines (ELG) rule (finalized in 2015) and the ELG reconsideration rule (finalized in October 2020)
Eligible Project Costs	Certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the loan guarantee program established under Title XVII of the Energy Policy Act of 2005
EPA	U.S. Environmental Protection Agency
EPC Contractor	Westinghouse and its affiliate, WECTEC Global Project Services Inc.; the former engineering, procurement, and construction contractor for Plant Vogtle Units 3 and 4
FERC	Federal Energy Regulatory Commission
FFB	Federal Financing Bank
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.
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, 2020, as applicable
GAAP	U.S. generally accepted accounting principles
Georgia Power	Georgia Power Company

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DEFINITIONS

(continued)

Term	Meaning
GRAM	Atlanta Gas Light's Georgia Rate Adjustment Mechanism
Guarantee Settlement Agreement	The June 9, 2017 settlement agreement between the Vogtle Owners and Toshiba related to certain payment obligations of the EPC Contractor guaranteed by Toshiba
Gulf Power	Gulf Power Company, until January 1, 2019 a wholly-owned subsidiary of Southern Company; effective January 1, 2021, Gulf Power Company merged with and into Florida Power and Light Company, with Florida Power and Light Company remaining as the surviving company
Heating Degree Days	A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Heating Season	The period from November through March when Southern Company Gas' natural gas usage and operating revenues are generally higher
HLBV	Hypothetical liquidation at book value
IGCC	Integrated coal gasification combined cycle, the technology originally approved for Mississippi Power's Kemper County energy facility
IIC	Intercompany Interchange Contract
IRP	Integrated resource plan
ITAAC	Inspections, Tests, Analyses, and Acceptance Criteria, standards established by the NRC
ITC	Investment tax credit
JEA	Jacksonville Electric Authority
Jefferson Island	Jefferson Island Storage and Hub, L.L.C, which owns a natural gas storage facility in Louisiana consisting of two salt dome caverns; a subsidiary of Southern Company Gas through December 1, 2020
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
Mississippi Power Rate Case Settlement Agreement	Settlement agreement between Mississippi Power and the Mississippi Public Utilities Staff approved by the Mississippi PSC in March 2020 related to Mississippi Power's base rate case filed in 2019
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
Nicor Gas	Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas
NRC	U.S. Nuclear Regulatory Commission
NYMEX	New York Mercantile Exchange, Inc.
OCI	Other comprehensive income
PennEast Pipeline	PennEast Pipeline Company, LLC, a joint venture 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
PowerSouth	PowerSouth Energy Cooperative
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 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.
SAVE	Steps to Advance Virginia's Energy, an infrastructure replacement program at Virginia Natural Gas
SCS	Southern Company Services, Inc., the Southern Company system service company and a wholly-owned subsidiary of Southern Company
SEC	U.S. Securities and Exchange Commission
SEGCO	Southern Electric Generating Company, 50% owned by each of Alabama Power and Georgia Power
Sequent	Sequent Energy Management, L.P. and Sequent Energy Canada Corp., wholly-owned subsidiaries of Southern Company Gas through June 30, 2021
SNG	Southern Natural Gas Company, L.L.C., a pipeline system in which Southern Company Gas has a 50% ownership interest
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, SEGCO, 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 Marketer), 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 and battery energy storage 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

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DEFINITIONS

(continued)

Term	Meaning
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
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
Williams Field Services Group	Williams Field Services Group, LLC

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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, statements concerning the potential and expected effects of the COVID-19 pandemic, regulated rates, the strategic goals for the business, customer and sales growth, economic conditions, cost recovery and other rate actions, projected equity ratios, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, financing activities, completion dates and costs of construction projects, matters related to the abandonment of the Kemper IGCC, completion of announced 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" of the Form 10-K;

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

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

•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 Plant Barry Unit 8, due to current and future challenges which include, but are not limited to, changes in labor costs, availability, and productivity; challenges with management of contractors or vendors; subcontractor performance; adverse weather conditions; shortages, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; delays due to judicial or regulatory action; nonperformance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems or any remediation related thereto; design and other licensing-based compliance matters, including, for nuclear units, inspections and the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related investigations, reviews, and approvals by the NRC necessary to support NRC authorization to load fuel; challenges with start-up activities, including major equipment failure, or system integration; and/or operational performance; and challenges related to the COVID-19 pandemic;

•the ability to overcome or mitigate the current challenges at Plant Vogtle Units 3 and 4, as described in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" in Item 1 herein, that could further impact the cost and schedule for the project;

•legal proceedings and regulatory approvals and actions related to construction projects, such as Plant Vogtle Units 3 and 4 and Plant Barry Unit 8, including PSC approvals and FERC and NRC actions;

•under certain specified circumstances, a decision by holders of more than 10% of the ownership interests of Plant Vogtle Units 3 and 4 not to proceed with construction 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, including the pace and extent of development of low- to no-carbon energy technologies and negative carbon concepts;

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

•state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions 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, political unrest, 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,
	2021		2020		2021		2020
	(in millions)				(in millions)
Operating Revenues:
Retail electric revenues	$	4,551	$	4,243	$	11,492	$	10,503
Wholesale electric revenues	731		584		1,822		1,473
Other electric revenues	179		164		525		484
Natural gas revenues (includes alternative revenue programs of    $(1), $(1), $3, and $6, respectively)	623		477		2,994		2,362
Other revenues	154		152		513		436
Total operating revenues	6,238		5,620		17,346		15,258
Operating Expenses:
Fuel	1,234		933		2,930		2,190
Purchased power	288		230		712		611
Cost of natural gas	129		71		943		654
Cost of other sales	71		72		255		201
Other operations and maintenance	1,446		1,286		4,257		3,785
Depreciation and amortization	896		889		2,658		2,619
Taxes other than income taxes	312		304		969		932
Estimated loss on Plant Vogtle Units 3 and 4	264		—		772		149
(Gain) loss on dispositions, net	(125)		—		(179)		(39)
Total operating expenses	4,515		3,785		13,317		11,102
Operating Income	1,723		1,835		4,029		4,156
Other Income and (Expense):
Allowance for equity funds used during construction	49		38		140		106
Earnings from equity method investments	30		33		35		105
Interest expense, net of amounts capitalized	(451)		(443)		(1,352)		(1,343)
Impairment of leveraged leases	—		—		(7)		(154)
Other income (expense), net	131		113		297		319
Total other income and (expense)	(241)		(259)		(887)		(967)
Earnings Before Income Taxes	1,482		1,576		3,142		3,189
Income taxes	372		293		550		443
Consolidated Net Income	1,110		1,283		2,592		2,746
Dividends on preferred stock of subsidiaries	4		4		11		11
Net income (loss) attributable to noncontrolling interests	5		28		(27)		3
Consolidated Net Income Attributable to    Southern Company	$	1,101	$	1,251	$	2,608	$	2,732
Common Stock Data:
Earnings per share -
Basic	$	1.04	$	1.18	$	2.46	$	2.58
Diluted	$	1.03	$	1.18	$	2.44	$	2.57
Average number of shares of common stock outstanding (in millions)
Basic	1,061		1,058		1,060		1,058
Diluted	1,068		1,064		1,067		1,064

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,
	2021		2020		2021		2020
	(in millions)				(in millions)
Consolidated Net Income	$	1,110	$	1,283	$	2,592	$	2,746
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of    $1, $17, $(4), and $(9), respectively	1		49		(15)		(26)
Reclassification adjustment for amounts included in net income,    net of tax of $10, $(11), $27, and $(1), respectively	31		(32)		81		(3)
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income,    net of tax of $1, $1, $4, and $3, respectively	4		3		10		6
Total other comprehensive income (loss)	36		20		76		(23)
Comprehensive Income	1,146		1,303		2,668		2,723
Dividends on preferred stock of subsidiaries	4		4		11		11
Comprehensive income (loss) attributable to noncontrolling interests	5		28		(27)		3
Consolidated Comprehensive Income Attributable to    Southern Company	$	1,137	$	1,271	$	2,684	$	2,709

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,
	2021		2020
	(in millions)
Operating Activities:
Consolidated net income	$	2,592	$	2,746
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	2,944		2,903
Deferred income taxes	89		(196)
Utilization of federal investment tax credits	256		319
Pension, postretirement, and other employee benefits	(218)		(190)
Settlement of asset retirement obligations	(341)		(315)
Stock based compensation expense	134		99
Estimated loss on Plant Vogtle Units 3 and 4	772		149
Storm damage accruals	166		171
Impairment charges	91		154
(Gain) loss on dispositions, net	(171)		(36)
Retail fuel cost under recovery – long-term	(209)		—
Other, net	(7)		(14)
Changes in certain current assets and liabilities —
-Receivables	2		125
-Materials and supplies	(91)		(141)
-Natural gas cost under recovery	(432)		—
-Other current assets	(160)		(119)
-Accounts payable	(45)		(428)
-Accrued taxes	288		289
-Accrued compensation	(93)		(183)
-Accrued interest	(110)		(52)
-Retail fuel cost over recovery	(150)		158
-Customer refunds	(58)		(226)
-Other current liabilities	(168)		7
Net cash provided from operating activities	5,081		5,220
Investing Activities:
Business acquisitions, net of cash acquired	(345)		(81)
Property additions	(5,222)		(5,365)
Nuclear decommissioning trust fund purchases	(1,301)		(714)
Nuclear decommissioning trust fund sales	1,297		708
Proceeds from dispositions	160		987
Cost of removal, net of salvage	(282)		(233)
Payments pursuant to LTSAs	(145)		(139)
Other investing activities	(12)		(55)
Net cash used for investing activities	(5,850)		(4,892)
Financing Activities:
Decrease in notes payable, net	(203)		(1,534)
Proceeds —
Long-term debt	6,793		7,543
Common stock	62		63
Short-term borrowings	325		615
Redemptions and repurchases —
Long-term debt	(3,060)		(2,472)
Short-term borrowings	(25)		(840)
Capital contributions from noncontrolling interests	415		173
Distributions to noncontrolling interests	(204)		(164)
Payment of common stock dividends	(2,077)		(2,008)
Other financing activities	(224)		(299)
Net cash provided from financing activities	1,802		1,077
Net Change in Cash, Cash Equivalents, and Restricted Cash	1,033		1,405
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	1,068		1,978
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	2,101	$	3,383
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $68 and $61 capitalized for 2021 and 2020, respectively)	$	1,417	$	1,346
Income taxes, net	92		66
Noncash transactions —
Accrued property additions at end of period	915		917
Contributions from noncontrolling interests	89		9
Contributions of wind turbine equipment	82		17
Right-of-use assets obtained under leases	92		166

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, 2021		At December 31, 2020
	(in millions)
Current Assets:
Cash and cash equivalents	$	2,078	$	1,065
Receivables —
Customer accounts	1,831		1,753
Energy marketing	—		516
Unbilled revenues	535		672
Other accounts and notes	611		512
Accumulated provision for uncollectible accounts	(72)		(118)
Materials and supplies	1,504		1,478
Fossil fuel for generation	386		550
Natural gas for sale	368		460
Prepaid expenses	329		276
Assets from risk management activities, net of collateral	365		147
Regulatory assets – asset retirement obligations	233		214
Natural gas cost under recovery	432		—
Other regulatory assets	792		810
Other current assets	282		282
Total current assets	9,674		8,617
Property, Plant, and Equipment:
In service	114,166		110,516
Less: Accumulated depreciation	33,723		32,397
Plant in service, net of depreciation	80,443		78,119
Nuclear fuel, at amortized cost	805		818
Construction work in progress	9,611		8,697
Total property, plant, and equipment	90,859		87,634
Other Property and Investments:
Goodwill	5,280		5,280
Nuclear decommissioning trusts, at fair value	2,446		2,303
Equity investments in unconsolidated subsidiaries	1,278		1,362
Other intangible assets, net of amortization of $296 and $328, respectively	455		487
Leveraged leases	575		556
Miscellaneous property and investments	586		398
Total other property and investments	10,620		10,386
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,724		1,802
Deferred charges related to income taxes	815		796
Unamortized loss on reacquired debt	263		280
Regulatory assets – asset retirement obligations, deferred	5,418		4,934
Other regulatory assets, deferred	6,902		7,198
Other deferred charges and assets	1,586		1,288
Total deferred charges and other assets	16,708		16,298
Total Assets	$	127,861	$	122,935

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, 2021		At December 31, 2020
	(in millions)
Current Liabilities:
Securities due within one year	$	3,286	$	3,507
Notes payable	707		609
Energy marketing trade payables	—		494
Accounts payable	2,229		2,312
Customer deposits	493		487
Accrued taxes —
Accrued income taxes	149		130
Other accrued taxes	797		699
Accrued interest	404		513
Accrued compensation	908		1,025
Asset retirement obligations	690		585
Operating lease obligations	246		241
Other regulatory liabilities	555		509
Other current liabilities	795		968
Total current liabilities	11,259		12,079
Long-term Debt	48,843		45,073
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	8,916		8,175
Deferred credits related to income taxes	5,485		5,767
Accumulated deferred ITCs	2,230		2,235
Employee benefit obligations	1,849		2,213
Operating lease obligations, deferred	1,495		1,611
Asset retirement obligations, deferred	10,919		10,099
Accrued environmental remediation	203		216
Other cost of removal obligations	2,164		2,211
Other regulatory liabilities, deferred	351		251
Other deferred credits and liabilities	637		480
Total deferred credits and other liabilities	34,249		33,258
Total Liabilities	94,351		90,410
Redeemable Preferred Stock of Subsidiaries	291		291
Total Stockholders' Equity (See accompanying statements)	33,219		32,234
Total Liabilities and Stockholders' Equity	$	127,861	$	122,935

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, 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)
Capital 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)
Capital 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)
Capital 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

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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, 2020	1,058	(1)	$	5,268	$	11,834	$	(46)	$	11,311	$	(395)	$	4,262	$	32,234
Consolidated net income (loss)	—	—	—		—		—		1,135		—		(32)		1,103
Other comprehensive income	—	—	—		—		—		—		28		—		28
Stock issued	2	—	5		9		—		—		—		—		14
Stock-based compensation	—	—	—		9		—		—		—		—		9
Cash dividends of $0.64 per share	—	—	—		—		—		(678)		—		—		(678)
Capital contributions from    noncontrolling interests	—	—	—		—		—		—		—		403		403
Distributions to noncontrolling interests	—	—	—		—		—		—		—		(46)		(46)
Other	—	—	—		2		—		—		—		(1)		1
Balance at March 31, 2021	1,060	(1)	5,273		11,854		(46)		11,768		(367)		4,586		33,068
Consolidated net income	—	—	—		—		—		372		—		—		372
Other comprehensive income	—	—	—		—		—		—		12		—		12
Stock issued	—	—	1		9		—		—		—		—		10
Stock-based compensation	—	—	—		22		—		—		—		—		22
Cash dividends of $0.66 per share	—	—	—		—		—		(699)		—		—		(699)
Capital contributions from    noncontrolling interests	—	—	—		—		—		—		—		29		29
Distributions to noncontrolling interests	—	—	—		—		—		—		—		(68)		(68)
Other	—	—	—		1		(2)		1		—		—		—
Balance at June 30, 2021	1,060	(1)	5,274		11,886		(48)		11,442		(355)		4,547		32,746
Consolidated net income	—	—	—		—		—		1,101		—		5		1,106
Other comprehensive income	—	—	—		—		—		—		36		—		36
Stock issued	1	—	4		34		—		—		—		—		38
Stock-based compensation	—	—	—		22		—		—		—		—		22
Cash dividends of $0.66 per share	—	—	—		—		—		(700)		—		—		(700)
Capital contributions from    noncontrolling interests	—	—	—		—		—		—		—		72		72
Distributions to noncontrolling interests	—	—	—		—		—		—		—		(94)		(94)
Other	—	—	—		(10)		2		1		—		—		(7)
Balance at September 30, 2021	1,061	(1)	$	5,278	$	11,932	$	(46)	$	11,844	$	(319)	$	4,530	$	33,219

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,
	2021		2020		2021		2020
	(in millions)				(in millions)
Operating Revenues:
Retail revenues	$	1,651	$	1,575	$	4,357	$	4,003
Wholesale revenues, non-affiliates	107		73		285		184
Wholesale revenues, affiliates	53		11		109		36
Other revenues	93		70		268		222
Total operating revenues	1,904		1,729		5,019		4,445
Operating Expenses:
Fuel	373		306		927		721
Purchased power, non-affiliates	76		64		173		153
Purchased power, affiliates	45		44		114		93
Other operations and maintenance	401		387		1,175		1,078
Depreciation and amortization	214		205		640		606
Taxes other than income taxes	99		103		303		311
Total operating expenses	1,208		1,109		3,332		2,962
Operating Income	696		620		1,687		1,483
Other Income and (Expense):
Allowance for equity funds used during construction	14		12		38		34
Interest expense, net of amounts capitalized	(84)		(84)		(252)		(255)
Other income (expense), net	29		30		93		78
Total other income and (expense)	(41)		(42)		(121)		(143)
Earnings Before Income Taxes	655		578		1,566		1,340
Income taxes	152		130		366		307
Net Income	503		448		1,200		1,033
Dividends on Preferred Stock	4		4		11		11
Net Income After Dividends on Preferred Stock	$	499	$	444	$	1,189	$	1,022

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Net Income	$	503	$	448	$	1,200	$	1,033
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $1, $—, $1, and $—, respectively	4		—		3		—
Reclassification adjustment for amounts included in net income,    net of tax of $—, $—, $1, and $1, respectively	1		1		3		3
Total other comprehensive income (loss)	5		1		6		3
Comprehensive Income	$	508	$	449	$	1,206	$	1,036

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,
	2021		2020
	(in millions)
Operating Activities:
Net income	$	1,200	$	1,033
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	748		731
Deferred income taxes	104		71
Pension, postretirement, and other employee benefits	(74)		(71)
Settlement of asset retirement obligations	(152)		(157)
Other, net	(51)		33
Changes in certain current assets and liabilities —
-Receivables	(128)		(130)
-Fossil fuel stock	91		4
-Prepayments	(24)		(32)
-Materials and supplies	(13)		(55)
-Retail fuel cost under recovery	(79)		—
-Other current assets	(19)		(35)
-Accounts payable	(230)		(248)
-Accrued taxes	178		142
-Accrued compensation	(37)		(55)
-Retail fuel cost over recovery	(18)		74
-Other current liabilities	(77)		(76)
Net cash provided from operating activities	1,419		1,229
Investing Activities:
Property additions	(1,235)		(1,460)
Nuclear decommissioning trust fund purchases	(536)		(213)
Nuclear decommissioning trust fund sales	536		213
Cost of removal, net of salvage	(93)		(68)
Change in construction payables	12		(46)
Other investing activities	(19)		(17)
Net cash used for investing activities	(1,335)		(1,591)
Financing Activities:
Proceeds —
Senior notes	600		600
Pollution control revenue bonds	—		87
Redemptions —
Senior notes	(200)		—
Pollution control revenue bonds	—		(87)
Other long-term debt	(206)		—
Capital contributions from parent company	630		649
Payment of common stock dividends	(738)		(718)
Other financing activities	(30)		(26)
Net cash provided from financing activities	56		505
Net Change in Cash, Cash Equivalents, and Restricted Cash	140		143
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	530		894
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	670	$	1,037
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $11 capitalized for both 2021 and 2020)	$	246	$	249
Income taxes, net	183		203
Noncash transactions —
Accrued property additions at end of period	178		154
Right-of-use assets obtained under leases	2		65

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, 2021		At December 31, 2020
	(in millions)
Current Assets:
Cash and cash equivalents	$	670	$	530
Receivables —
Customer accounts	497		429
Unbilled revenues	151		152
Affiliated	53		31
Other accounts and notes	101		66
Accumulated provision for uncollectible accounts	(18)		(43)
Fossil fuel stock	144		235
Materials and supplies	556		546
Prepaid expenses	65		42
Other regulatory assets	289		226
Other current assets	107		33
Total current assets	2,615		2,247
Property, Plant, and Equipment:
In service	32,787		31,816
Less: Accumulated provision for depreciation	10,298		10,009
Plant in service, net of depreciation	22,489		21,807
Nuclear fuel, at amortized cost	241		270
Construction work in progress	1,129		866
Total property, plant, and equipment	23,859		22,943
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,259		1,157
Equity investments in unconsolidated subsidiaries	57		63
Miscellaneous property and investments	129		131
Total other property and investments	1,445		1,351
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	119		151
Deferred charges related to income taxes	238		235
Regulatory assets – asset retirement obligations	1,580		1,441
Other regulatory assets, deferred	2,100		2,162
Other deferred charges and assets	348		273
Total deferred charges and other assets	4,385		4,262
Total Assets	$	32,304	$	30,803

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, 2021		At December 31, 2020
	(in millions)
Current Liabilities:
Securities due within one year	$	616	$	311
Accounts payable —
Affiliated	299		316
Other	370		545
Customer deposits	106		104
Accrued taxes	331		152
Accrued interest	79		90
Accrued compensation	191		212
Asset retirement obligations	308		254
Other regulatory liabilities	72		108
Other current liabilities	122		107
Total current liabilities	2,494		2,199
Long-term Debt	8,443		8,558
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,425		3,273
Deferred credits related to income taxes	1,973		2,016
Accumulated deferred ITCs	89		94
Employee benefit obligations	136		214
Operating lease obligations	69		119
Asset retirement obligations, deferred	4,015		3,720
Other cost of removal obligations	261		335
Other regulatory liabilities, deferred	139		124
Other deferred credits and liabilities	66		50
Total deferred credits and other liabilities	10,173		9,945
Total Liabilities	21,110		20,702
Redeemable Preferred Stock	291		291
Common Stockholder's Equity (See accompanying statements)	10,903		9,810
Total Liabilities and Stockholder's Equity	$	32,304	$	30,803

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, 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
Balance at December 31, 2020	31	$	1,222	$	5,413	$	3,194	$	(19)	$	9,810
Net income after dividends on    preferred stock	—	—		—		359		—		359
Capital contributions from parent company	—	—		602		—		—		602
Other comprehensive income	—	—		—		—		1		1
Cash dividends on common stock	—	—		—		(246)		—		(246)
Balance at March 31, 2021	31	1,222		6,015		3,307		(18)		10,526
Net income after dividends on    preferred stock	—	—		—		331		—		331
Capital contributions from parent company	—	—		26		—		—		26
Other comprehensive income	—	—		—		—		1		1
Cash dividends on common stock	—	—		—		(246)		—		(246)
Other	—	—		—		(1)		—		(1)
Balance at June 30, 2021	31	1,222		6,041		3,391		(17)		10,637
Net income after dividends on    preferred stock	—	—		—		499		—		499
Capital contributions from parent company	—	—		9		—		—		9
Other comprehensive income	—	—		—		—		5		5
Cash dividends on common stock	—	—		—		(246)		—		(246)
Other	—	—		—		—		(1)		(1)
Balance at September 30, 2021	31	$	1,222	$	6,050	$	3,644	$	(13)	$	10,903

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,
	2021		2020		2021		2020
	(in millions)				(in millions)
Operating Revenues:
Retail revenues	$	2,652	$	2,435	$	6,465	$	5,870
Wholesale revenues	63		34		143		85
Other revenues	141		148		442		416
Total operating revenues	2,856		2,617		7,050		6,371
Operating Expenses:
Fuel	432		368		1,088		826
Purchased power, non-affiliates	173		146		461		409
Purchased power, affiliates	288		142		573		393
Other operations and maintenance	544		483		1,558		1,411
Depreciation and amortization	345		358		1,025		1,064
Taxes other than income taxes	130		123		365		344
Estimated loss on Plant Vogtle Units 3 and 4	264		—		772		149
Total operating expenses	2,176		1,620		5,842		4,596
Operating Income	680		997		1,208		1,775
Other Income and (Expense):
Allowance for equity funds used during construction	33		22		94		63
Interest expense, net of amounts capitalized	(106)		(106)		(315)		(322)
Other income (expense), net	42		32		124		93
Total other income and (expense)	(31)		(52)		(97)		(166)
Earnings Before Income Taxes	649		945		1,111		1,609
Income taxes	113		172		81		198
Net Income	$	536	$	773	$	1,030	$	1,411

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Net Income	$	536	$	773	$	1,030	$	1,411
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of    $—, $—, $—, and $(1), respectively	—		—		—		(2)
Reclassification adjustment for amounts included in net income,    net of tax of $1, $—, $2, and $2, respectively	2		2		5		4
Total other comprehensive income (loss)	2		2		5		2
Comprehensive Income	$	538	$	775	$	1,035	$	1,413

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,
	2021		2020
	(in millions)
Operating Activities:
Net income	$	1,030	$	1,411
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	1,164		1,206
Deferred income taxes	(299)		(167)
Allowance for equity funds used during construction	(94)		(63)
Pension, postretirement, and other employee benefits	(112)		(98)
Settlement of asset retirement obligations	(154)		(130)
Storm damage accruals	160		160
Retail fuel cost under recovery – long-term	(203)		—
Estimated loss on Plant Vogtle Units 3 and 4	772		149
Other, net	88		11
Changes in certain current assets and liabilities —
-Receivables	(85)		(168)
-Fossil fuel stock	77		4
-Materials and supplies	(60)		(74)
-Other current assets	(51)		(69)
-Accounts payable	164		25
-Accrued taxes	154		44
-Retail fuel cost over recovery	(113)		84
-Customer refunds	(5)		(162)
-Other current liabilities	(83)		(38)
Net cash provided from operating activities	2,350		2,125
Investing Activities:
Property additions	(2,411)		(2,519)
Nuclear decommissioning trust fund purchases	(766)		(500)
Nuclear decommissioning trust fund sales	761		495
Cost of removal, net of salvage	(99)		(93)
Change in construction payables, net of joint owner portion	(68)		(14)
Payments pursuant to LTSAs	(38)		(44)
Contributions in aid of construction	71		18
Proceeds from dispositions	4		143
Other investing activities	(26)		(12)
Net cash used for investing activities	(2,572)		(2,526)
Financing Activities:
Decrease in notes payable, net	(60)		(115)
Proceeds —
Senior notes	750		1,500
Pollution control revenue bonds	122		53
FFB loan	371		519
Short-term borrowings	—		250
Redemptions and repurchases —
Senior notes	(325)		(950)
Pollution control revenue bonds	(69)		(148)
Short-term borrowings	—		(375)
FFB loan	(75)		(55)
Capital contributions from parent company	1,054		1,379
Payment of common stock dividends	(1,237)		(1,156)
Other financing activities	(26)		(35)
Net cash provided from financing activities	505		867
Net Change in Cash, Cash Equivalents, and Restricted Cash	283		466
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	9		52
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	292	$	518
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $47 and $34 capitalized for 2021 and 2020, respectively)	$	325	$	316
Income taxes, net	237		311
Noncash transactions —
Accrued property additions at end of period	477		523
Right-of-use assets obtained under operating leases	(3)		30

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, 2021		At December 31, 2020
	(in millions)
Current Assets:
Cash and cash equivalents	$	292	$	9
Receivables —
Customer accounts	689		621
Unbilled revenues	258		233
Joint owner accounts	106		123
Affiliated	41		21
Other accounts and notes	46		67
Accumulated provision for uncollectible accounts	(2)		(26)
Fossil fuel stock	201		278
Materials and supplies	647		592
Regulatory assets – storm damage	102		213
Regulatory assets – asset retirement obligations	191		166
Other regulatory assets	243		248
Other current assets	255		143
Total current assets	3,069		2,688
Property, Plant, and Equipment:
In service	40,831		39,682
Less: Accumulated provision for depreciation	12,743		12,251
Plant in service, net of depreciation	28,088		27,431
Nuclear fuel, at amortized cost	564		548
Construction work in progress	7,337		6,857
Total property, plant, and equipment	35,989		34,836
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,187		1,145
Equity investments in unconsolidated subsidiaries	50		51
Miscellaneous property and investments	66		63
Total other property and investments	1,303		1,259
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,193		1,308
Deferred charges related to income taxes	544		527
Regulatory assets – asset retirement obligations, deferred	3,607		3,291
Other regulatory assets, deferred	2,515		2,692
Other deferred charges and assets	712		479
Total deferred charges and other assets	8,571		8,297
Total Assets	$	48,932	$	47,080

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, 2021		At December 31, 2020
	(in millions)
Current Liabilities:
Securities due within one year	$	672	$	542
Notes payable	—		60
Accounts payable —
Affiliated	719		597
Other	761		753
Customer deposits	263		276
Accrued taxes	457		407
Accrued interest	98		130
Accrued compensation	207		233
Operating lease obligations	153		151
Asset retirement obligations	333		287
Over recovered fuel clause revenues	—		113
Other regulatory liabilities	360		228
Other current liabilities	198		254
Total current liabilities	4,221		4,031
Long-term Debt	13,064		12,428
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,222		3,272
Deferred credits related to income taxes	2,386		2,588
Accumulated deferred ITCs	321		273
Employee benefit obligations	461		586
Operating lease obligations, deferred	1,008		1,156
Asset retirement obligations, deferred	6,432		5,978
Other deferred credits and liabilities	456		267
Total deferred credits and other liabilities	14,286		14,120
Total Liabilities	31,571		30,579
Common Stockholder's Equity (See accompanying statements)	17,361		16,501
Total Liabilities and Stockholder's Equity	$	48,932	$	47,080

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, 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
Balance at December 31, 2020	9	$	398	$	12,361	$	3,789	$	(47)	$	16,501
Net income	—	—		—		351		—		351
Capital contributions from parent company	—	—		332		—		—		332
Other comprehensive income	—	—		—		—		2		2
Cash dividends on common stock	—	—		—		(412)		—		(412)
Balance at March 31, 2021	9	398		12,693		3,728		(45)		16,774
Net income	—	—		—		143		—		143
Capital contributions from parent company	—	—		40		—		—		40
Other comprehensive income	—	—		—		—		1		1
Cash dividends on common stock	—	—		—		(412)		—		(412)
Balance at June 30, 2021	9	398		12,733		3,459		(44)		16,546
Net income	—	—		—		536		—		536
Capital contributions from parent company	—	—		690		—		—		690
Other comprehensive income	—	—		—		—		2		2
Cash dividends on common stock	—	—		—		(413)		—		(413)
Balance at September 30, 2021	9	$	398	$	13,423	$	3,582	$	(42)	$	17,361

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,
	2021		2020		2021		2020
	(in millions)				(in millions)
Operating Revenues:
Retail revenues	$	248	$	232	$	670	$	630
Wholesale revenues, non-affiliates	60		61		178		164
Wholesale revenues, affiliates	62		36		120		82
Other revenues	8		7		20		19
Total operating revenues	378		336		988		895
Operating Expenses:
Fuel	139		103		330		266
Purchased power	6		6		21		18
Other operations and maintenance	85		62		230		202
Depreciation and amortization	46		47		138		135
Taxes other than income taxes	33		31		96		90
Total operating expenses	309		249		815		711
Operating Income	69		87		173		184
Other Income and (Expense):
Interest expense, net of amounts capitalized	(16)		(14)		(45)		(45)
Other income (expense), net	7		6		27		19
Total other income and (expense)	(9)		(8)		(18)		(26)
Earnings Before Income Taxes	60		79		155		158
Income taxes	10		12		22		20
Net Income	$	50	$	67	$	133	$	138

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Net Income	$	50	$	67	$	133	$	138
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	$	50	$	67	$	134	$	139

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,
	2021		2020
	(in millions)
Operating Activities:
Net income	$	133	$	138
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	161		142
Settlement of asset retirement obligations	(18)		(16)
Other, net	(20)		(11)
Changes in certain current assets and liabilities —
-Receivables	(19)		(3)
-Other current assets	(9)		(7)
-Accounts payable	(12)		(54)
-Accrued taxes	(20)		15
-Retail fuel cost over recovery	(19)		—
-Other current liabilities	(18)		(18)
Net cash provided from operating activities	159		186
Investing Activities:
Property additions	(135)		(174)
Construction payables	(11)		7
Payments pursuant to LTSAs	(21)		(20)
Other investing activities	(15)		(13)
Net cash used for investing activities	(182)		(200)
Financing Activities:
Decrease in notes payable, net	(25)		—
Proceeds —
Senior notes	525		—
Short-term borrowings	—		40
Pollution control revenue bonds	—		34
Other long-term debt	—		100
Redemptions —
Senior notes	—		(275)
Short-term borrowings	—		(40)
Pollution control revenue bonds	—		(41)
Other revenue bonds	(270)		—
Other long-term debt	(75)		—
Capital contributions from parent company	103		80
Return of capital to parent company	—		(74)
Payment of common stock dividends	(118)		(37)
Other financing activities	(10)		(1)
Net cash provided from (used for) financing activities	130		(214)
Net Change in Cash, Cash Equivalents, and Restricted Cash	107		(228)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	39		286
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	146	$	58
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest	$	53	$	49
Income taxes, net	11		9
Noncash transactions — Accrued property additions at end of period	23		42

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, 2021		At December 31, 2020
	(in millions)
Current Assets:
Cash and cash equivalents	$	146	$	39
Receivables —
Customer accounts, net	46		34
Unbilled revenues	39		38
Affiliated	45		32
Other accounts and notes	27		32
Fossil fuel stock	27		24
Materials and supplies	71		65
Assets from risk management activities, net of collateral	66		1
Other regulatory assets	54		60
Other current assets	11		19
Total current assets	532		344
Property, Plant, and Equipment:
In service	5,078		5,011
Less: Accumulated provision for depreciation	1,568		1,545
Plant in service, net of depreciation	3,510		3,466
Construction work in progress	117		146
Total property, plant, and equipment	3,627		3,612
Other Property and Investments	180		151
Deferred Charges and Other Assets:
Deferred charges related to income taxes	31		32
Regulatory assets – asset retirement obligations	231		201
Other regulatory assets, deferred	371		388
Accumulated deferred income taxes	119		129
Other deferred charges and assets	100		55
Total deferred charges and other assets	852		805
Total Assets	$	5,191	$	4,912

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, 2021		At December 31, 2020
	(in millions)
Current Liabilities:
Securities due within one year	$	76	$	406
Notes payable	—		25
Accounts payable —
Affiliated	88		63
Other	61		109
Accrued taxes	94		114
Accrued interest	7		15
Accrued compensation	31		34
Asset retirement obligations	19		27
Over recovered regulatory clause liabilities	7		34
Other regulatory liabilities	104		49
Other current liabilities	50		40
Total current liabilities	537		916
Long-term Debt	1,509		1,013
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	464		447
Deferred credits related to income taxes	276		287
Employee benefit obligations	94		113
Asset retirement obligations, deferred	175		150
Other cost of removal obligations	194		194
Other regulatory liabilities, deferred	48		15
Other deferred credits and liabilities	31		35
Total deferred credits and other liabilities	1,282		1,241
Total Liabilities	3,328		3,170
Common Stockholder's Equity (See accompanying statements)	1,863		1,742
Total Liabilities and Stockholder's Equity	$	5,191	$	4,912

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 Deficit)		Accumulated Other Comprehensive Income (Loss)		Total
	(in millions)
Balance at December 31, 2019	1	$	38	$	4,449	$	(2,832)	$	(3)	$	1,652
Net income	—	—		—		32		—		32
Capital contributions from parent company	—	—		76		—		—		76
Return of capital to parent company	—	—		(37)		—		—		(37)
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
Balance at December 31, 2020	1	$	38	$	4,460	$	(2,754)	$	(2)	$	1,742
Net income	—	—		—		45		—		45
Capital contributions from parent company	—	—		100		—		—		100
Cash dividends on common stock	—	—		—		(39)		—		(39)
Balance at March 31, 2021	1	38		4,560		(2,748)		(2)		1,848
Net income	—	—		—		38		—		38
Capital contributions from parent company	—	—		2		—		—		2
Cash dividends on common stock	—	—		—		(39)		—		(39)
Other	—	—		—		(1)		1		—
Balance at June 30, 2021	1	38		4,562		(2,750)		(1)		1,849
Net income	—	—		—		50		—		50
Capital contributions from parent company	—	—		3		—		—		3
Cash dividends on common stock	—	—		—		(39)		—		(39)
Balance at September 30, 2021	1	$	38	$	4,565	$	(2,739)	$	(1)	$	1,863

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,
	2021		2020		2021		2020
	(in millions)				(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	503	$	418	$	1,231	$	1,047
Wholesale revenues, affiliates	167		101		361		279
Other revenues	9		4		18		11
Total operating revenues	679		523		1,610		1,337
Operating Expenses:
Fuel	259		137		540		346
Purchased power	41		19		86		52
Other operations and maintenance	94		89		308		245
Depreciation and amortization	132		129		383		367
Taxes other than income taxes	12		10		35		29
Loss on sales-type lease	15		—		15		—
(Gain) loss on dispositions, net	—		—		(39)		(39)
Total operating expenses	553		384		1,328		1,000
Operating Income	126		139		282		337
Other Income and (Expense):
Interest expense, net of amounts capitalized	(36)		(36)		(111)		(114)
Other income (expense), net	2		13		10		19
Total other income and (expense)	(34)		(23)		(101)		(95)
Earnings Before Income Taxes	92		116		181		242
Income taxes (benefit)	9		14		(3)		27
Net Income	83		102		184		215
Net income (loss) attributable to noncontrolling interests	5		28		(27)		3
Net Income Attributable to Southern Power	$	78	$	74	$	211	$	212

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Net Income	$	83	$	102	$	184	$	215
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of    $(7), $15, $(16), and $(2), respectively	(21)		44		(48)		(6)
Reclassification adjustment for amounts included in net income,    net of tax of $9, $(13), $22, and $(8), respectively	27		(36)		66		(24)
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income,    net of tax of $—, $—, $1, and $—, respectively	1		—		2		2
Total other comprehensive income (loss)	7		8		20		(28)
Comprehensive Income	90		110		204		187
Comprehensive income (loss) attributable to noncontrolling interests	5		28		(27)		3
Comprehensive Income Attributable to Southern Power	$	85	$	82	$	231	$	184

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 CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2021		2020
	(in millions)
Operating Activities:
Net income	$	184	$	215
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	402		386
Deferred income taxes	(16)		(59)
Utilization of federal investment tax credits	237		318
Amortization of investment tax credits	(44)		(44)
(Gain) loss on dispositions, net	(39)		(39)
Other, net	14		(16)
Changes in certain current assets and liabilities —
-Receivables	(117)		(28)
-Prepaid income taxes	63		74
-Other current assets	(5)		(17)
-Accounts payable	55		(12)
-Accrued taxes	15		21
-Other current liabilities	1		(25)
Net cash provided from operating activities	750		774
Investing Activities:
Business acquisitions, net of cash acquired	(345)		(81)
Property additions	(355)		(135)
Proceeds from dispositions	22		663
Change in construction payables	(22)		(12)
Payments pursuant to LTSAs	(61)		(61)
Other investing activities	8		50
Net cash provided from (used for) investing activities	(753)		424
Financing Activities:
Decrease in notes payable, net	(148)		(449)
Proceeds — Senior notes	400		—
Redemptions —
Short-term borrowings	—		(100)
Senior notes	—		(300)
Return of capital to parent company	(271)		—
Capital contributions from noncontrolling interests	415		173
Distributions to noncontrolling interests	(204)		(164)
Purchase of membership interests from noncontrolling interests	—		(60)
Payment of common stock dividends	(153)		(151)
Other financing activities	(6)		(9)
Net cash provided from (used for) financing activities	33		(1,060)
Net Change in Cash, Cash Equivalents, and Restricted Cash	30		138
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	183		279
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	213	$	417
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $5 and $10 capitalized for 2021 and 2020, respectively)	$	118	$	123
Income taxes, net	(235)		(278)
Noncash transactions —
Contributions from noncontrolling interests	89		9
Contributions of wind turbine equipment	82		17
Accrued property additions at end of period	53		44
Right-of-use assets obtained under operating leases	66		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, 2021		At December 31, 2020
	(in millions)
Current Assets:
Cash and cash equivalents	$	192	$	182
Receivables —
Customer accounts, net	178		125
Affiliated	68		37
Other	53		27
Materials and supplies	103		157
Prepaid income taxes	15		11
Other current assets	56		36
Total current assets	665		575
Property, Plant, and Equipment:
In service	14,399		13,904
Less: Accumulated provision for depreciation	3,122		2,842
Plant in service, net of depreciation	11,277		11,062
Construction work in progress	274		127
Total property, plant, and equipment	11,551		11,189
Other Property and Investments:
Intangible assets, net of amortization of $104 and $89, respectively	288		302
Equity investments in unconsolidated subsidiaries	83		19
Net investment in sales-type lease	91		—
Total other property and investments	462		321
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	475		415
Prepaid LTSAs	191		155
Accumulated deferred income taxes	—		262
Income taxes receivable, non-current	33		25
Other deferred charges and assets	234		293
Total deferred charges and other assets	933		1,150
Total Assets	$	13,611	$	13,235

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, 2021		At December 31, 2020
	(in millions)
Current Liabilities:
Securities due within one year	$	994	$	299
Notes payable	27		175
Accounts payable —
Affiliated	110		65
Other	91		92
Accrued taxes —
Accrued income taxes	8		8
Other accrued taxes	27		22
Accrued interest	26		32
Other current liabilities	125		132
Total current liabilities	1,408		825
Long-term Debt	3,021		3,393
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	156		123
Accumulated deferred ITCs	1,629		1,672
Operating lease obligations	489		426
Other deferred credits and liabilities	201		165
Total deferred credits and other liabilities	2,475		2,386
Total Liabilities	6,904		6,604
Total Stockholders' Equity (See accompanying statements)	6,707		6,631
Total Liabilities and Stockholders' Equity	$	13,611	$	13,235

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, 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

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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, 2020	$	914	$	1,522	$	(67)	$	2,369	$	4,262	$	6,631
Net income (loss)	—		97		—		97		(32)		65
Return of capital to parent company	(271)		—		—		(271)		—		(271)
Other comprehensive income	—		—		16		16		—		16
Cash dividends on common stock	—		(51)		—		(51)		—		(51)
Capital contributions from    noncontrolling interests	—		—		—		—		403		403
Distributions to noncontrolling interests	—		—		—		—		(46)		(46)
Other	(2)		1		(1)		(2)		(1)		(3)
Balance at March 31, 2021	641		1,569		(52)		2,158		4,586		6,744
Net income	—		36		—		36		—		36
Other comprehensive income (loss)	—		—		(3)		(3)		—		(3)
Cash dividends on common stock	—		(51)		—		(51)		—		(51)
Capital contributions from    noncontrolling interests	—		—		—		—		29		29
Distributions to noncontrolling interests	—		—		—		—		(68)		(68)
Other	2		—		1		3		—		3
Balance at June 30, 2021	643		1,554		(54)		2,143		4,547		6,690
Net income	—		78		—		78		5		83
Other comprehensive income	—		—		7		7		—		7
Cash dividends on common stock	—		(51)		—		(51)		—		(51)
Capital contributions from    noncontrolling interests	—		—		—		—		73		73
Distributions to noncontrolling interests	—		—		—		—		(95)		(95)
Balance at September 30, 2021	$	643	$	1,581	$	(47)	$	2,177	$	4,530	$	6,707

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

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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,
	2021		2020		2021		2020
	(in millions)				(in millions)
Operating Revenues:
Natural gas revenues (includes revenue taxes of    $12, $10, $89, and $79, respectively)	$	624	$	478	$	2,991	$	2,356
Alternative revenue programs	(1)		(1)		3		6
Total operating revenues	623		477		2,994		2,362
Operating Expenses:
Cost of natural gas	129		71		943		654
Other operations and maintenance	238		217		776		694
Depreciation and amortization	133		125		396		368
Taxes other than income taxes	36		35		166		154
(Gain) loss on dispositions, net	(121)		—		(127)		2
Total operating expenses	415		448		2,154		1,872
Operating Income	208		29		840		490
Other Income and (Expense):
Earnings from equity method investments	25		33		14		106
Interest expense, net of amounts capitalized	(57)		(57)		(175)		(171)
Other income (expense), net	13		12		(66)		33
Total other income and (expense)	(19)		(12)		(227)		(32)
Earnings Before Income Taxes	189		17		613		458
Income taxes	133		3		224		98
Net Income	$	56	$	14	$	389	$	360

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Net Income	$	56	$	14	$	389	$	360
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of    $8, $1, $11, and $(6), respectively	23		4		32		(17)
Reclassification adjustment for amounts included in net income,    net of tax of $—, $—, $1, and $2, respectively	(2)		1		1		7
Total other comprehensive income (loss)	21		5		33		(10)
Comprehensive Income	$	77	$	19	$	422	$	350

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,
	2021		2020
	(in millions)
Operating Activities:
Net income	$	389	$	360
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	396		368
Deferred income taxes	289		(1)
Mark-to-market adjustments	147		104
Impairment of PennEast Pipeline investment	84		—
(Gain) loss on dispositions, net	(127)		2
Natural gas cost under recovery – long-term	(79)		—
Other, net	32		(21)
Changes in certain current assets and liabilities —
-Receivables	311		403
-Prepaid income taxes	(148)		(19)
-Natural gas cost under recovery	(432)		—
-Other current assets	(78)		(1)
-Accounts payable	30		(75)
-Other current liabilities	(57)		2
Net cash provided from operating activities	757		1,122
Investing Activities:
Property additions	(1,045)		(1,045)
Cost of removal, net of salvage	(74)		(60)
Investment in unconsolidated subsidiaries	(3)		(79)
Proceeds from dispositions	126		178
Other investing activities	30		33
Net cash used for investing activities	(966)		(973)
Financing Activities:
Increase (decrease) in notes payable, net	38		(500)
Proceeds —
Short-term borrowings	300		—
First mortgage bonds	100		150
Senior notes	450		500
Redemptions —
Senior notes	(300)		—
Medium-term notes	(30)		—
Capital contributions from parent company	63		215
Payment of common stock dividends	(397)		(399)
Other financing activities	(2)		(3)
Net cash provided from (used for) financing activities	222		(37)
Net Change in Cash, Cash Equivalents, and Restricted Cash	13		112
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	19		49
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	32	$	161
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $6 and $5 capitalized for 2021 and 2020, respectively)	$	173	$	162
Income taxes, net	85		45
Noncash transactions — Accrued property additions at end of period	146		146

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, 2021		At December 31, 2020
	(in millions)
Current Assets:
Cash and cash equivalents	$	29	$	17
Receivables —
Energy marketing	—		516
Customer accounts	249		353
Unbilled revenues	70		219
Affiliated	1		4
Other accounts and notes	39		51
Accumulated provision for uncollectible accounts	(37)		(40)
Natural gas for sale	368		460
Prepaid expenses	181		48
Assets from risk management activities, net of collateral	75		118
Natural gas cost under recovery	432		—
Other regulatory assets	137		102
Other current assets	44		38
Total current assets	1,588		1,886
Property, Plant, and Equipment:
In service	18,527		17,611
Less: Accumulated depreciation	5,004		4,821
Plant in service, net of depreciation	13,523		12,790
Construction work in progress	691		648
Total property, plant, and equipment	14,214		13,438
Other Property and Investments:
Goodwill	5,015		5,015
Equity investments in unconsolidated subsidiaries	1,174		1,290
Other intangible assets, net of amortization of $142 and $195, respectively	40		51
Miscellaneous property and investments	20		19
Total other property and investments	6,249		6,375
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	72		81
Other regulatory assets, deferred	634		615
Other deferred charges and assets	201		235
Total deferred charges and other assets	907		931
Total Assets	$	22,958	$	22,630

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, 2021		At December 31, 2020
	(in millions)
Current Liabilities:
Securities due within one year	$	47	$	333
Notes payable	662		324
Energy marketing trade payables	—		494
Accounts payable —
Affiliated	42		56
Other	399		373
Customer deposits	106		90
Accrued taxes	79		83
Accrued interest	68		58
Accrued compensation	87		106
Temporary LIFO liquidation	18		—
Other regulatory liabilities	18		122
Other current liabilities	154		150
Total current liabilities	1,680		2,189
Long-term Debt	6,766		6,293
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,571		1,265
Deferred credits related to income taxes	822		847
Employee benefit obligations	260		283
Operating lease obligations	60		67
Other cost of removal obligations	1,675		1,649
Accrued environmental remediation	203		216
Other deferred credits and liabilities	45		54
Total deferred credits and other liabilities	4,636		4,381
Total Liabilities	13,082		12,863
Common Stockholder's Equity (See accompanying statements)	9,876		9,767
Total Liabilities and Stockholder's Equity	$	22,958	$	22,630

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, 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
Balance at December 31, 2020	$	9,930	$	(141)	$	(22)	$	9,767
Net income	—		398		—		398
Capital contributions from parent company	57		—		—		57
Other comprehensive income	—		—		4		4
Cash dividends on common stock	—		(132)		—		(132)
Balance at March 31, 2021	9,987		125		(18)		10,094
Net loss	—		(65)		—		(65)
Capital contributions from parent company	25		—		—		25
Other comprehensive income	—		—		8		8
Cash dividends on common stock	—		(133)		—		(133)
Balance at June 30, 2021	10,012		(73)		(10)		9,929
Net income	—		56		—		56
Capital contributions from parent company	2		—		—		2
Other comprehensive income	—		—		21		21
Cash dividends on common stock	—		(132)		—		(132)
Balance at September 30, 2021	$	10,014	$	(149)	$	11	$	9,876

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	60
D	Revenue from Contracts with Customers and Lease Income	63
E	Consolidated Entities and Equity Method Investments	70
F	Financing	72
G	Income Taxes	74
H	Retirement Benefits	75
I	Fair Value Measurements	78
J	Derivatives	83
K	Acquisitions and Dispositions	95
L	Segment and Related Information	98

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 at December 31, 2020 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, 2021 and 2020. 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, 2021 and December 31, 2020 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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

Other intangible assets were as follows:

	At September 30, 2021						At December 31, 2020
	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	$	(148)	$	64	$	212	$	(135)	$	77
Trade names	64		(36)		28		64		(31)		33
Storage and transportation contracts(*)	—		—		—		64		(64)		—
PPA fair value adjustments	390		(104)		286		390		(89)		301
Other	10		(8)		2		10		(9)		1
Total other intangible assets subject to amortization	$	676	$	(296)	$	380	$	740	$	(328)	$	412
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—		75		75		—		75
Total other intangible assets	$	751	$	(296)	$	455	$	815	$	(328)	$	487
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	390	$	(104)	$	286	$	390	$	(89)	$	301
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	156	$	(128)	$	28	$	156	$	(119)	$	37
Trade names	26		(14)		12		26		(12)		14
Wholesale gas services
Storage and transportation contracts(*)	—		—		—		64		(64)		—
Total other intangible assets subject to amortization	$	182	$	(142)	$	40	$	246	$	(195)	$	51

(*)See Note (K) under "Southern Company Gas" for information regarding the sale of Sequent.

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(UNAUDITED)

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Nine Months Ended
	September 30, 2021
	(in millions)
Southern Company(a)	$	11	$	33
Southern Power(b)	5		15
Southern Company Gas(c)	4		11

(a)Includes $5 million and $15 million for the three and nine months ended September 30, 2021, respectively, recorded as a reduction to operating revenues.

(b)Recorded as a reduction to operating revenues.

(c)Relates to gas marketing services.

Cash, Cash Equivalents, and Restricted Cash

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amount shown in the condensed statements of cash flows for the applicable Registrants:

	Southern Company				Southern Power		Southern Company Gas
	September 30, 2021		December 31, 2020		September 30, 2021		September 30, 2021		December 31, 2020
	(in millions)				(in millions)		(in millions)
Cash and cash equivalents	$	2,078	$	1,065	$	192	$	29	$	17
Restricted cash(a):
Other current assets	3		2		—		3		2
Other deferred charges and assets	21		—		21		—		—
Total cash, cash equivalents, and restricted cash(b)	$	2,101	$	1,068	$	213	$	32	$	19

(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 may not add due to rounding.

Natural Gas for Sale

With the exception of Nicor Gas, Southern Company Gas records natural gas inventories on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated.

Southern Company Gas recorded no material adjustments to natural gas inventories for any period presented. Nicor Gas' inventory decrement at September 30, 2021 is expected to be restored prior to year end.

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(UNAUDITED)

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, Georgia Power, and Mississippi Power during the first nine months of 2021 are shown in the following table. There were no material changes in AROs for the other Registrants during the first nine months of 2021.

	Southern Company		Alabama Power		Georgia Power		Mississippi Power
	(in millions)
Balance at December 31, 2020	$	10,684	$	3,974	$	6,265	$	176
Liabilities incurred	17		—		3		—
Liabilities settled	(341)		(152)		(154)		(18)
Accretion	304		116		176		6
Cash flow revisions	945		385		475		30
Balance at September 30, 2021	$	11,609	$	4,323	$	6,765	$	194

In August 2021, Alabama Power recorded an increase of approximately $385 million to its AROs related to the CCR Rule and the related state rule based on updated estimates for post-closure costs at its ash ponds and inflation rates.

In September 2021, Georgia Power recorded an increase of approximately $435 million to its AROs related to the CCR Rule and the related state rule based on updated estimates for inflation rates and the timing of closure activities.

In September 2021, Mississippi Power recorded an increase of approximately $30 million to its AROs related to the CCR Rule based on updated estimates for the timing of closure activities, post-closure costs at one of its ash ponds, and inflation rates.

The traditional electric operating companies have periodically updated, and expect to continue periodically updating, their related cost estimates and ARO liabilities for each CCR unit as additional information related to these assumptions becomes available. Some of these updates have been, and future updates may 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) under "Georgia Power – Rate Plan" for additional information. The ultimate outcome of these matters cannot be determined at this time.

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(UNAUDITED)

(B) REGULATORY MATTERS

See Note 2 to the financial statements in Item 8 of the Form 10-K for additional information relating to regulatory matters.

The recovery balances for certain retail regulatory clauses of the traditional electric operating companies and Southern Company Gas at September 30, 2021 and December 31, 2020 were as follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2021		December 31, 2020
		(in millions)
Alabama Power
Rate CNP Compliance	Other regulatory liabilities, current	$	—	$	28
	Other regulatory liabilities, deferred	24		—
Rate CNP PPA	Other regulatory assets, deferred	88		58
Retail Energy Cost Recovery	Other regulatory liabilities, current	—		18
	Other regulatory assets, current	79		—
	Other regulatory assets, deferred	6		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	36		77
Georgia Power
Fuel Cost Recovery	Over recovered fuel clause revenues	$	—	$	113
	Other deferred charges and assets	203		—
Mississippi Power
Fuel Cost Recovery	Over recovered regulatory clause liabilities	$	5	$	24
Ad Valorem Tax	Other regulatory assets, current	12		11
	Other regulatory assets, deferred	39		41
Property Damage Reserve	Other regulatory liabilities, deferred	—		4
	Other regulatory assets, deferred	16		—
Southern Company Gas
Natural Gas Cost Recovery(*)	Other regulatory liabilities	$	—	$	88
	Natural gas cost under recovery	432		—
	Other regulatory assets, deferred	79		—

(*)The significant change during the nine months ended September 30, 2021 was primarily driven by an increase in the cost of gas purchased in February 2021 resulting from Winter Storm Uri.

Alabama Power

Certificate of Convenience and Necessity

Energy Alabama, Gasp, Inc., and the Sierra Club filed requests for reconsideration and rehearing with the Alabama PSC regarding the certificate of convenience and necessity (CCN) issued to Alabama Power in August 2020, which authorized, among other things, the construction of Plant Barry Unit 8 and the acquisition of the Central Alabama Generating Station. In December 2020, the Alabama PSC issued an order denying the requests. On January 7, 2021, Energy Alabama and Gasp, Inc. filed a judicial appeal regarding both the Alabama PSC's August 2020 CCN order and the December 2020 order denying reconsideration and rehearing. On March 9, 2021, the Circuit Court of Montgomery County, Alabama granted a motion by Alabama Power to intervene in the appeal. On August 27, 2021, the court affirmed both the August 2020 and December 2020 Alabama PSC orders. On October 7, 2021, Energy Alabama and Gasp, Inc. filed an unopposed motion for voluntary dismissal of their direct appeal previously

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filed on January 7, 2021. This matter is now concluded. At September 30, 2021, expenditures associated with the construction of Plant Barry Unit 8 included in CWIP totaled approximately $222 million.

Plant Greene County

Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 5 under "Joint Ownership Agreements" in Item 8 of the Form 10-K for additional information.

On September 9, 2021, the Mississippi PSC issued an order confirming the conclusion of its review of Mississippi Power's 2021 IRP with no deficiencies identified. Mississippi Power's 2021 IRP includes a schedule to retire Mississippi Power's 40% ownership interest in Plant Greene County Units 1 and 2 in December 2025 and 2026, respectively, consistent with each unit's remaining useful life. The Plant Greene County unit retirements identified by Mississippi Power require the completion of transmission and system reliability improvements, as well as agreement by Alabama Power. Alabama Power will continue to monitor the status of the transmission and system reliability improvements. Currently, Alabama Power plans to retire Plant Greene County Units 1 and 2 at the dates indicated. The ultimate outcome of this matter cannot be determined at this time.

Rate NDR

Based on an order from the Alabama PSC, when Alabama Power's NDR balance falls below $50 million, a reserve establishment charge will be activated and the ongoing reserve maintenance charge will be concurrently suspended until the NDR balance reaches $75 million. At September 30, 2021, Alabama Power's NDR balance was $36 million. Effective with October 2021 billings, the reserve maintenance charge component of Rate NDR was suspended and the reserve establishment charge was activated. Alabama Power expects to collect approximately $4 million in the fourth quarter 2021 and $16 million annually under Rate NDR until the NDR balance is restored to $75 million.

Calhoun Generating Station Acquisition

On September 23, 2021, Alabama Power entered into an agreement to acquire all of the equity interests in Calhoun Power Company, LLC, which owns and operates a 743-MW winter peak, simple-cycle, combustion turbine generation facility in Calhoun County, Alabama (Calhoun Generating Station). The total purchase price associated with the acquisition is approximately $180 million, subject to working capital adjustments. The completion of the acquisition is subject to the satisfaction and waiver of certain conditions, including, among other customary conditions, approval by the Alabama PSC and the FERC, as well as the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act. Alabama Power expects to complete the transaction by September 30, 2022.

On October 28, 2021, Alabama Power filed a petition for a CCN with the Alabama PSC to procure additional generating capacity through the acquisition of the Calhoun Generating Station.

Upon certification, Alabama Power expects to recover costs associated with the Calhoun Generating Station through its existing rate structure, primarily Rate CNP New Plant, Rate CNP Compliance, Rate ECR, and Rate RSE.

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

Georgia Power

Rate Plan

Effective January 1, 2021, Georgia Power reduced its amortization of costs associated with CCR AROs by approximately $90 million as approved by the Georgia PSC in conjunction with Georgia Power's annual compliance filings.

In February 2020, the Georgia PSC denied a motion for reconsideration filed by the Sierra Club regarding the Georgia PSC's decision in the 2019 ARP allowing Georgia Power to recover compliance costs for CCR AROs, and, in December 2020, the Superior Court of Fulton County affirmed the decision of the Georgia PSC. On October 25,

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(UNAUDITED)

2021, the Georgia Court of Appeals affirmed the Superior Court of Fulton County's December 2020 order. On November 3, 2021, the Sierra Club filed a motion for reconsideration with the Georgia Court of Appeals. The ultimate outcome of this matter cannot be determined at this time.

In accordance with the terms of the 2019 ARP, on October 1, 2021, Georgia Power filed the following tariff adjustments to become effective January 1, 2022 pending approval by the Georgia PSC:

•increase traditional base tariffs by approximately $192 million;

•decrease the ECCR tariff by approximately $12 million;

•decrease Demand-Side Management tariffs by approximately $25 million; and

•increase Municipal Franchise Fee tariffs by approximately $2 million.

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

See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.

Plant Vogtle Unit 3 and Common Facilities Rate Proceeding

On June 15, 2021, Georgia Power filed an application with the Georgia PSC to adjust retail base rates to include the portion of costs related to its investment in Plant Vogtle Unit 3 and the common facilities shared between Plant Vogtle Units 3 and 4 (Common Facilities) previously deemed prudent by the Georgia PSC ($2.38 billion), as well as the related costs of operation. On November 2, 2021, the Georgia PSC voted to approve Georgia Power's application as filed, with the following modifications pursuant to a stipulated agreement between Georgia Power and the staff of the Georgia PSC. Georgia Power will include in rate base $2.1 billion of the $2.38 billion previously deemed prudent by the Georgia PSC and will recover the related depreciation expense through retail base rates. Financing costs on the remaining portion of the total Unit 3 and the Common Facilities construction costs will continue to be recovered through the NCCR tariff or deferred. Georgia Power will defer as a regulatory asset the remaining depreciation expense (approximately $38 million annually) until Unit 4 costs are placed in retail base rates. In addition, the stipulated agreement clarified that following the prudency review, the remaining amount to be placed in retail base rates will be net of the proceeds from the Guarantee Settlement Agreement and will not be used to offset imprudent costs, if any.

The related increase in annual retail base rates of approximately $302 million also includes recovery of all projected operations and maintenance expenses for Unit 3 and the Common Facilities and other related costs of operation, partially offset by the related production tax credits, and will become effective the month after Unit 3 is placed in service. This increase will be partially offset by a decrease in the NCCR tariff of approximately $78 million expected to be effective January 1, 2022.

See "Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

Deferral of Incremental COVID-19 Costs

Since June 2021, Georgia Power has continued a review of bad debt amounts deferred under the Georgia PSC-approved methodology, including consideration of actual amounts repaid by customers from arrears and installment plans after the disconnection moratorium period ended in July 2020. As a result, Georgia Power has reduced the balance of deferred incremental costs by a total of approximately $23 million through September 30, 2021. At September 30, 2021, the incremental costs deferred totaled approximately $20 million, including approximately $1 million of incremental bad debt costs and $19 million of other incremental costs. The period over which these costs will be recovered is expected to be determined in Georgia Power's next base rate case. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. On October 12, 2021, Georgia Power filed a notification and plan with the Georgia PSC to implement an interim fuel rider and increase

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(UNAUDITED)

fuel rates by 15% effective January 1, 2022, which is expected to increase annual billings by approximately $252 million. The Georgia PSC has 30 days from the filing to approve the plan; however, if the Georgia PSC elects to take no action, the new rates become effective as requested. Georgia Power is currently scheduled to file its next fuel case by February 28, 2023. The ultimate outcome of this matter cannot be determined at this time.

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 connection with the EPC Contractor's bankruptcy filing in March 2017, 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, including contingency, through September 2022 and June 2023, respectively, is as follows:

	(in millions)
Base project capital cost forecast(a)(b)	$	9,342
Construction contingency estimate	137
Total project capital cost forecast(a)(b)	9,479
Net investment at September 30, 2021(b)	(8,159)
Remaining estimate to complete	$	1,320

(a)    Includes approximately $570 million of costs that are not shared with the other Vogtle Owners. Excludes financing costs expected to be capitalized through AFUDC of approximately $318 million, of which $169 million had been accrued through September 30, 2021.

(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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(UNAUDITED)

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.2 billion, of which $2.8 billion had been incurred through September 30, 2021.

As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers and related test results, and workforce statistics. Southern Nuclear establishes aggressive target values for monthly construction production and system turnover activities. Southern Nuclear's site work plans continue to reflect this approach in support of safely completing Units 3 and 4, while achieving the required construction quality.

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 tested positive for COVID-19, showed symptoms consistent with COVID-19, were being tested for COVID-19, or were in close contact with such persons; requiring self-quarantine; and adopting additional precautionary measures. Since March 2020, the number of active cases at the site has fluctuated and impacted productivity levels and pace of activity completion. Through June 2021, the site experienced an overall decline in the number of active cases since the peak in January 2021. During the third quarter 2021, the site experienced a similar peak in August 2021; however, the number of active cases since this peak has declined. The lower productivity levels and slower pace of activity completion experienced since March 2020 contributed to a backlog to the aggressive site work plan established at the beginning of 2020. Georgia Power estimates the productivity impacts of the COVID-19 pandemic have consumed approximately three to four months of schedule margin previously embedded in the site work plan for Unit 3 and Unit 4. In addition, the project continued to face challenges including, but not limited to, higher than expected absenteeism; overall construction and subcontractor labor productivity; system turnover and testing activities; and electrical equipment and commodity installation. As a result of these factors, in January 2021, Southern Nuclear further extended certain milestone dates, including the start of hot functional testing and fuel load for Unit 3, from those established in October 2020.

Following the January 2021 milestone extensions, Southern Nuclear has been performing additional construction remediation work necessary to ensure quality and design standards are met as system turnovers are completed to support hot functional testing, which was completed in July 2021, and fuel load for Unit 3. As a result of challenges including, but not limited to, construction productivity, construction remediation work, the pace of system turnovers, spent fuel pool repairs, and the timeframe and duration for hot functional and other testing, at the end of the second quarter 2021, Southern Nuclear further extended certain milestone dates, including the fuel load for Unit 3, from those established in January 2021. Through the third quarter 2021, the project continued to face challenges including, but not limited to, construction productivity, construction remediation work, and the pace of system turnovers. As a result of these continued challenges, at the end of the third quarter 2021, Southern Nuclear further extended certain milestone dates, including fuel load for Unit 3, from those established at the end of the second quarter 2021. The site work plan currently targets fuel load for Unit 3 in the first quarter 2022 and an in-service date of May 2022 and primarily depends on significant improvements in overall construction productivity and production levels, the volume of construction remediation work, the pace of system and area turnovers, and the progression of startup and other testing. As the site work plan includes minimal margin to these milestone dates, an in-service date in the third quarter 2022 for Unit 3 is projected, although any further delays could result in a later in-service date.

As the result of productivity challenges, at the end of the second quarter 2021, Southern Nuclear also further extended milestone dates for Unit 4 from those established in January 2021. These productivity challenges continued into the third quarter 2021 and some craft and support resources were diverted temporarily to support construction efforts on Unit 3. As a result of these factors, at the end of the third quarter 2021, Southern Nuclear further extended the milestone dates for Unit 4 from those established at the end of the second quarter 2021. The site work plan targets an in-service date of March 2023 for Unit 4 and primarily depends on overall construction productivity and production levels significantly improving as well as appropriate levels of craft laborers, particularly electricians and pipefitters, being added and maintained. As the site work plan includes minimal margin

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(UNAUDITED)

to the milestone dates, an in-service date in the second quarter 2023 for Unit 4 is projected, although any further delays could result in a later in-service date.

As of March 31, 2021, approximately $84 million of the construction contingency established in the fourth quarter 2020 was assigned to the base capital cost forecast for costs primarily associated with the schedule extension for Unit 3 to December 2021, construction productivity, support resources, and construction remediation work. Georgia Power increased its total capital cost forecast as of March 31, 2021 by adding $48 million to the remaining construction contingency. As of June 30, 2021, all of the remaining construction contingency previously established and an additional $341 million was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units 3 and 4, construction remediation work for Unit 3, and construction productivity and support resources for Units 3 and 4. Georgia Power also increased its total capital cost forecast as of June 30, 2021 by adding $119 million to replenish construction contingency. As a result of the factors discussed above, during the third quarter 2021, all of the remaining construction contingency previously established in the second quarter 2021 and an additional $127 million was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units 3 and 4, construction productivity and support resources for Units 3 and 4, and construction remediation work for Unit 3. Georgia Power also increased its total capital cost forecast as of September 30, 2021 by adding $137 million to replenish construction contingency.

After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded pre-tax charges to income in the first quarter 2021, the second quarter 2021, and the third quarter 2021 of $48 million ($36 million after tax), $460 million ($343 million after tax), and $264 million ($197 million after tax), respectively, for the increases in the total project capital cost forecast. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.

In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction and testing 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 $160 million and $200 million and is included in the total project capital cost forecast.

As construction, including subcontract work, continues and testing and system turnover activities increase, ongoing or future 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), including the spent fuel pools, any of which may require additional labor and/or materials; or other issues could continue or arise and change the projected schedule and estimated cost.

There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to ensure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. In connection with the additional construction remediation work described above, Southern Nuclear reviewed the project's construction quality programs and, where needed, is implementing improvement plans consistent with these processes. In June 2021, the NRC began a special inspection to review the root cause of this additional construction remediation work and the corresponding corrective action plans. On August 26, 2021, the NRC issued an inspection report with initial findings. Southern Nuclear had already identified and self-reported many of the issues in this report to the NRC and implemented corrective-action plans to resolve these issues. Southern Nuclear responded to the NRC's initial findings on October 5, 2021 and expects a final report from the NRC by November 24, 2021. Findings resulting from this or other inspections could require additional remediation

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and/or further NRC oversight. In addition, certain license amendment requests have been filed and approved or are pending before the NRC. On March 15, 2021, the NRC denied the Blue Ridge Environmental Defense League's (BREDL) December 2020 motion to reopen proceedings on BREDL's petition challenging a requested license amendment, which has been issued by the NRC staff.

The site work plan currently targets fuel load for Unit 3 in the first quarter 2022. 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, have arisen or may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues, including inspections and ITAACs, are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the in-service date beyond the third quarter 2022 for Unit 3 or the second quarter 2023 for Unit 4 is currently estimated to result in additional base capital costs for Georgia Power of approximately $25 million per month for Unit 3 and approximately $15 million per month for Unit 4, as well as the related AFUDC and any additional related construction or testing costs. 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).

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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.

Georgia Power and the other Vogtle Owners do not agree on either the starting dollar amount for the determination of cost increases subject to the cost-sharing and tender provisions of the Global Amendments or the extent to which COVID-19-related costs impact the calculation. Based on the definition in the Global Amendments, Georgia Power believes the starting dollar amount is $18.38 billion and does not believe estimated project costs have reached a level where cost-sharing would be triggered. However, the other Vogtle Owners have asserted the cost increases through September 30, 2021 have reached the cost-sharing thresholds and could be sufficient to trigger the tender provisions under the Global Amendments, which could require Georgia Power to record additional pre-tax charges to income of up to approximately $350 million. On October 29, 2021, Georgia Power and the other Vogtle Owners entered into an agreement to clarify the process for the tender provisions of the Global Amendments, which will provide additional time to resolve these matters.

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, 2021, Georgia Power had recovered approximately $2.7 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

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$7.3 billion) and not requested for rate recovery. On October 1, 2021, Georgia Power filed a request to decrease the NCCR tariff by $78 million annually, effective January 1, 2022, pending approval by the Georgia PSC.

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 $0.3 billion 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 a prudence proceeding on cost recovery will occur following Unit 4 fuel load, 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 alternate rate plan) 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 effective the first month after Unit 3 reaches commercial operation, retail base rates would be adjusted to include the costs related to Unit 3 and common facilities 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 $150 million in 2020 and are estimated to have negative earnings impacts of approximately $270 million, $260 million, and $135 million in 2021, 2022, and 2023, respectively. In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.

The Georgia PSC has approved 24 VCM reports covering periods through December 31, 2020, including total construction capital costs incurred through December 31, 2020 of $7.3 billion (net of $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). In the August 24, 2021 order approving the twenty-fourth VCM report, the Georgia PSC also approved a stipulation addressing the following matters: (i) beginning with its twenty-fifth VCM report, Georgia Power will continue to report to the Georgia PSC all costs incurred during the period for review and will request for approval costs up to the $7.3 billion determined to be reasonable in the Georgia PSC's seventeenth VCM order and (ii) Georgia Power will not seek rate recovery of the $0.7 billion increase to the base capital cost forecast included in the nineteenth VCM report and charged to income by Georgia Power in the second quarter 2018. In addition, the stipulation

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confirms Georgia Power may request verification and approval of costs above $7.3 billion for inclusion in rate base at a later time, but no earlier than the prudence review contemplated by the seventeenth VCM order described previously. Georgia Power filed its twenty-fifth VCM report with the Georgia PSC on August 31, 2021, which reflects the revised capital cost forecast as of June 30, 2021 of $9.2 billion (net of $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). See "Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" herein for information on Georgia Power's request to adjust retail base rates to include a portion of costs related to its investment in Plant Vogtle Unit 3 and Common Facilities.

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

Mississippi Power

Performance Evaluation Plan

On June 8, 2021, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2021, resulting in an annual increase in revenues of approximately $16 million, or 1.8%, which became effective with the first billing cycle of April 2021 in accordance with the PEP rate schedule.

Integrated Resource Plan

In December 2020, the Mississippi PSC issued an order in the Reserve Margin Plan docket requiring Mississippi Power to incorporate into its 2021 IRP a schedule reflecting the retirement of 950 MWs of fossil-steam generation by year-end 2027 to reduce Mississippi Power's excess reserve margin. On September 9, 2021, the Mississippi PSC issued an order confirming the conclusion of its review of Mississippi Power's 2021 IRP with no deficiencies identified. The 2021 IRP includes a schedule to retire Plant Watson Unit 4 (268 MWs) and Mississippi Power's 40% ownership interest in Plant Greene County Units 1 and 2 (103 MWs each) in December 2023, 2025, and 2026, respectively, consistent with each unit's remaining useful life in the most recent approved depreciation studies. In addition, the schedule reflects the early retirement of Mississippi Power's 50% undivided ownership interest in Plant Daniel Units 1 and 2 (502 MWs) by the end of 2027. The Plant Greene County unit retirements require the completion by Alabama Power of transmission and system reliability improvements, as well as agreement by Alabama Power.

The remaining net book value of Plant Daniel Units 1 and 2 was approximately $520 million at September 30, 2021 and Mississippi Power is continuing to depreciate these units using the current approved rates through the end of 2027. Mississippi Power expects to reclassify the net book value remaining at retirement, which is expected to total approximately $390 million, to a regulatory asset to be amortized over a period to be determined by the Mississippi PSC in future proceedings, consistent with the December 2020 order. The Plant Watson and Greene County units are expected to be fully depreciated upon retirement. The ultimate outcome of these matters cannot be determined at this time.

Environmental Compliance Overview Plan

On June 8, 2021, the Mississippi PSC approved Mississippi Power's ECO Plan filing for 2021, resulting in an annual decrease in revenues of approximately $9 million, primarily due to a change in the amortization periods of certain regulatory assets and liabilities. The rate decrease became effective with the first billing cycle of July 2021.

Ad Valorem Tax Adjustment

On April 6, 2021, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment filing for 2021, which requested an annual increase in revenues of approximately $28 million, including approximately $19 million of ad valorem taxes previously recovered through PEP in accordance with the Mississippi Power Rate Case Settlement Agreement. The rate increase became effective with the first billing cycle of May 2021.

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System Restoration Rider

On October 14, 2021, the Mississippi PSC issued an accounting order giving Mississippi Power the authority to reclassify the retail costs associated with Hurricanes Zeta and Ida to a regulatory asset to be recovered through PEP over a period to be determined in Mississippi Power's 2022 PEP proceeding. At September 30, 2021, these costs totaled approximately $49 million.

On October 25, 2021, Mississippi Power made its annual System Restoration Rider filing with the Mississippi PSC, which requested an annual increase in retail revenues of approximately $9 million primarily for an increase in the property damage reserve accrual. The requested increase is expected to become effective with the first billing cycle following approval by the Mississippi PSC. The filing excludes recovery of the costs associated with Hurricanes Zeta and Ida.

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

Southern Company Gas

Infrastructure Replacement Programs and Capital Projects

Capital expenditures incurred under specific infrastructure replacement programs during the first nine months of 2021 were as follows:

Utility	Program	Nine Months Ended September 30, 2021
		(in millions)
Nicor Gas	Investing in Illinois	$	307
Virginia Natural Gas	Steps to Advance Virginia's Energy	36
Total		$	343

Atlanta Gas Light

On April 28, 2021, Atlanta Gas Light filed its first Integrated Capacity and Delivery Plan (i-CDP) with the Georgia PSC, which includes a series of ongoing and proposed pipeline safety, reliability, and growth programs for the next 10 years (2022 through 2031), as well as the required capital investments and related costs to implement the programs. The i-CDP reflects capital investments totaling approximately $0.5 billion to $0.6 billion annually.

Recovery of the related revenue requirements will be included in either subsequent annual GRAM filings or the new System Reinforcement Rider for authorized large pressure improvement and system reliability projects. On October 14, 2021, Atlanta Gas Light and the staff of the Georgia PSC filed a joint stipulation agreement, under which, for the years 2022 through 2024, Atlanta Gas Light would incrementally reduce its combined GRAM and System Reinforcement Rider request by 10% through Atlanta Gas Light's GRAM mechanism, or $5 million for 2022 based on the initial July 21, 2021 GRAM filing. The stipulation agreement also would provide for $1.7 billion of total capital investment for the years 2022 through 2024. The Georgia PSC is scheduled to vote on this matter later in November 2021. The ultimate outcome of this matter cannot be determined at this time. See "Rate Proceedings – Atlanta Gas Light" herein for additional information.

Virginia Natural Gas

On April 6, 2021, the Virginia Commission approved a motion filed by Virginia Natural Gas to withdraw the application for its 9.5-mile interconnect project due to a change in the capacity needs of one of the project's customers. No further action is necessary and this matter is now concluded.

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Rate Proceedings

Virginia Natural Gas

On September 14, 2021, the Virginia Commission approved a stipulation agreement related to Virginia Natural Gas' June 2020 general rate case filing, which allows for a $43 million increase in annual base rate revenues, including $14 million related to the recovery of investments under the SAVE program, based on a ROE of 9.5% and an equity ratio of 51.9%. Interim rate adjustments became effective as of November 1, 2020, subject to refund, based on Virginia Natural Gas' original request for an increase of approximately $50 million. Refunds to customers related to the difference between the approved rates and the interim rates will be completed during the fourth quarter 2021.

Atlanta Gas Light

On July 21, 2021, Atlanta Gas Light filed its annual GRAM filing with the Georgia PSC. The filing requested an annual base rate increase of $49 million based on the projected 12-month period beginning January 1, 2022. Later in November 2021, Atlanta Gas Light expects to file an amended GRAM filing in accordance with the reduction agreed to in the October 14, 2021 joint stipulation agreement, as discussed previously under "Infrastructure Replacement Programs and Capital Projects – Atlanta Gas Light" herein. Resolution of the GRAM filing is expected by December 31, 2021, with the new rates to become effective January 1, 2022. The ultimate outcome of this matter cannot be determined at this time.

Deferral of Incremental COVID-19 Costs

Nicor Gas

On March 18, 2021, the Illinois Commission approved a phased-in schedule for disconnections related to non-payment. Nicor Gas began certain disconnections in late April 2021 and resumed normal disconnections in June 2021.

Virginia Natural Gas

On June 30, 2021, the declared state of emergency in Virginia expired, ending the suspension of disconnections related to non-payment. Virginia Natural Gas began certain disconnections in July 2021 and late payment fees resumed in October 2021.

(C) CONTINGENCIES

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

General Litigation Matters

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

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

Southern Company

In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits 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

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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.

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. In August 2019, the court granted a motion filed by the plaintiff in July 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust.

The plaintiffs in each of these cases seek to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiffs also seek certain changes to Southern Company's corporate governance and internal processes. In 2018, the court in each case entered an order staying each lawsuit until 30 days after the settlement of a securities class action filed in January 2017 against Southern Company, certain of its current and former officers, and certain former Mississippi Power officers. In September 2020, the plaintiffs in each case filed a status report noting the settlement of the securities class action and informing the court that the parties had scheduled mediation, which occurred in November 2020. In September 2021, the parties executed a term sheet memorializing a settlement-in-principle of both pending derivative lawsuits. The parties are negotiating a global stipulation of settlement that will apply to both lawsuits and will be subject to approval by the federal court. If approved, the terms of the settlement-in-principle are not expected to have a material impact on Southern Company's financial statements.

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. In March 2020, the Georgia Court of Appeals vacated the Superior Court of Fulton County's February 2019 order granting conditional class certification and 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 and the plaintiffs renewed their motion for class certification. On March 16, 2021, the Superior Court of Fulton County granted class certification and Georgia Power's motion for summary judgment. On March 22, 2021, the plaintiffs filed a notice of appeal, and, on April 2, 2021, Georgia Power filed a notice of cross appeal on the issue of class certification. The amount of any possible losses cannot be estimated at this time because, among other factors, it is unknown whether any losses would be subject to recovery from any municipalities.

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

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damages including punitive damages, a medical monitoring fund, and injunctive relief. In September 2020, Georgia Power filed a motion to dismiss. On October 8, 2021, three additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages. The amount of any possible losses from these matters cannot be estimated at this time.

Mississippi Power

In 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi. 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 each filed a motion to dismiss the amended complaint, which occurred in May 2020 and March 2020, respectively. Also in March 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. In July 2020, the plaintiffs filed a motion for leave to file a third amended complaint, which included the same federal claims as the proposed second amended complaint, as well as several additional state law claims based on the allegation that Mississippi Power failed to disclose the annual percentage rate of interest applicable to refunds. In November 2020, the court denied each of the plaintiffs' pending motions and entered final judgment in favor of Mississippi Power. On January 22, 2021, the court denied further motions by the plaintiffs to vacate the judgment and to file a revised second amended complaint. On February 19, 2021, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fifth Circuit. An adverse outcome in this proceeding could have a material impact on Mississippi Power's financial statements.

See Note 3 to the financial statements under "Other Matters – 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 remediation costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.

Georgia Power's environmental remediation liability was $19 million and $15 million at September 30, 2021 and December 31, 2020, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.

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Southern Company Gas' environmental remediation liability was $255 million and $245 million at September 30, 2021 and December 31, 2020, respectively, based on the estimated cost of environmental investigation and remediation associated with known former manufactured gas plant operating sites.

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

Other Matters

Southern Company Gas

PennEast Pipeline Project

On June 29, 2021, the U.S. Supreme Court ruled in favor of PennEast Pipeline regarding its federal eminent domain authority over lands in which a state has property rights interests.

Southern Company Gas tests its equity method investments for impairment whenever events or changes in circumstances indicate that the investment may be impaired. Following the U.S. Supreme Court ruling, during the second quarter 2021, Southern Company Gas management reassessed the project construction timing, including the anticipated timing for receipt of the FERC certificate and all remaining state and local permits for both Phase 1 (the construction of 68 miles of pipe entirely within Pennsylvania) and Phase 2 (the construction of the remaining 50 miles in Pennsylvania and New Jersey), as well as potential challenges thereto, and performed an impairment analysis. The outcome of the analysis resulted in a pre-tax impairment charge of $82 million ($58 million after tax).

On September 27, 2021, PennEast Pipeline announced that further development of the project is no longer supported, and, as a result, all further development of the project has ceased. During the third quarter 2021, Southern Company Gas recorded a pre-tax charge of $2 million ($2 million after tax) related to its share of the project level impairment, as well as $7 million of additional tax expense, resulting in total pre-tax charges of $84 million ($67 million after tax) during 2021 related to the project.

See Note (E) under "Southern Company Gas" for additional information.

SNG

As a 50% equity investor in SNG, Southern Company Gas is required to make additional capital contributions as necessary pursuant to the terms of its operating agreement with SNG. Southern Company Gas previously committed to fund up to $150 million as a contingent capital contribution if SNG was unable to refinance or otherwise satisfy $300 million of debt maturing in June 2021. On April 29, 2021, SNG successfully refinanced the debt obligation. See Note (E) under "Southern Company Gas" for additional information.

(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, 2021 and 2020:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2021
Operating revenues
Retail electric revenues
Residential	$	1,974	$	750	$	1,138	$	86	$	—	$	—
Commercial	1,432		471		882		79		—		—
Industrial	902		394		428		80		—		—
Other	24		4		18		2		—		—
Total retail electric revenues	4,332		1,619		2,466		247		—		—
Natural gas distribution revenues
Residential	218		—		—		—		—		218
Commercial	55		—		—		—		—		55
Transportation	239		—		—		—		—		239
Industrial	6		—		—		—		—		6
Other	31		—		—		—		—		31
Total natural gas distribution revenues	549		—		—		—		—		549
Wholesale electric revenues
PPA energy revenues	359		61		41		2		261		—
PPA capacity revenues	125		14		14		1		97		—
Non-PPA revenues	63		54		3		120		134		—
Total wholesale electric revenues	547		129		58		123		492		—
Other natural gas revenues
Gas marketing services	45		—		—		—		—		45
Other natural gas revenues	11		—		—		—		—		11
Total natural gas revenues	56		—		—		—		—		56
Other revenues	248		53		112		8		9		—
Total revenue from contracts with customers	5,732		1,801		2,636		378		501		605
Other revenue sources(a)	506		103		220		—		178		18
Total operating revenues	$	6,238	$	1,904	$	2,856	$	378	$	679	$	623

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(UNAUDITED)

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Nine Months Ended September 30, 2021
Operating revenues
Retail electric revenues
Residential	$	4,910	$	1,931	$	2,765	$	214	$	—	$	—
Commercial	3,727		1,229		2,293		205		—		—
Industrial	2,299		1,048		1,034		217		—		—
Other	70		13		51		6		—		—
Total retail electric revenues	11,006		4,221		6,143		642		—		—
Natural gas distribution revenues
Residential	1,143		—		—		—		—		1,143
Commercial	298		—		—		—		—		298
Transportation	775		—		—		—		—		775
Industrial	29		—		—		—		—		29
Other	187		—		—		—		—		187
Total natural gas distribution revenues	2,432		—		—		—		—		2,432
Wholesale electric revenues
PPA energy revenues	782		143		71		9		575		—
PPA capacity revenues	375		86		41		4		247		—
Non-PPA revenues	181		108		14		283		273		—
Total wholesale electric revenues	1,338		337		126		296		1,095		—
Other natural gas revenues
Wholesale gas services	2,168		—		—		—		—		2,168
Gas marketing services	303		—		—		—		—		303
Other natural gas revenues	27		—		—		—		—		27
Total natural gas revenues	2,498		—		—		—		—		2,498
Other revenues	792		150		362		22		18		—
Total revenue from contracts with customers	18,066		4,708		6,631		960		1,113		4,930
Other revenue sources(a)	2,979		311		419		28		497		1,763
Other adjustments(b)	(3,699)		—		—		—		—		(3,699)
Total operating revenues	$	17,346	$	5,019	$	7,050	$	988	$	1,610	$	2,994

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(UNAUDITED)

	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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(UNAUDITED)

	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

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

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

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(UNAUDITED)

Contract Balances

The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers at September 30, 2021 and December 31, 2020:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Accounts Receivable
At September 30, 2021	$	2,343	$	712	$	904	$	90	$	170	$	329
At December 31, 2020	2,614		632		806		77		112		788
Contract Assets
At September 30, 2021	$	165	$	5	$	103	$	—	$	1	$	—
At December 31, 2020	158		2		71		—		—		—
Contract Liabilities
At September 30, 2021	$	65	$	6	$	39	$	1	$	2	$	—
At December 31, 2020	61		6		27		1		1		1

At September 30, 2021 and December 31, 2020, 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 unregulated service agreements. Southern Company's unregulated distributed generation business had $55 million and $81 million of contract assets and $19 million and $27 million of contract liabilities at September 30, 2021 and December 31, 2020, respectively, for outstanding performance obligations.

Revenues recognized by Southern Company in the three and nine months ended September 30, 2021, which were included in contract liabilities at December 31, 2020, were $5 million and $25 million, respectively, and immaterial for all other 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. Revenues from contracts with customers related to these performance obligations remaining at September 30, 2021 are expected to be recognized as follows:

	2021 (remaining)		2022		2023		2024		2025		Thereafter
	(in millions)
Southern Company	$	156	$	543	$	347	$	327	$	307	$	2,667
Alabama Power	13		32		24		7		5		—
Georgia Power	22		64		43		23		21		41
Southern Power	70		323		281		297		281		2,644

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(UNAUDITED)

Revenue expected to be recognized for performance obligations remaining at September 30, 2021 was immaterial for Mississippi Power.

Lease Income

Lease income for the three and nine months ended September 30, 2021 and 2020 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, 2021
Lease income - interest income on sales-type leases	$	4	$	—	$	—	$	4	$	—	$	—
Lease income - operating leases	56		21		11		—		21		9
Variable lease income	143		—		—		—		151		—
Total lease income	$	203	$	21	$	11	$	4	$	172	$	9
For the Nine Months Ended September 30, 2021
Lease income - interest income on sales-type leases	$	11	$	—	$	—	$	10	$	—	$	—
Lease income - operating leases	168		62		31		1		64		26
Variable lease income	355		—		—		—		379		—
Total lease income	$	534	$	62	$	31	$	11	$	443	$	26
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

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

Lease Receivables

Mississippi Power

Mississippi Power completed construction of additional leased assets under an existing sales-type lease during the second quarter 2021. Upon completion of construction, the book value was transferred from CWIP to lease receivables. At September 30, 2021, the lease receivable related to the additional leased assets totaled $39 million and is primarily included in other property and investments. The transfer represents a noncash investing transaction for purposes of the statements of cash flows.

Southern Power

During the third quarter 2021, Southern Power completed construction of a portion of the Garland battery energy storage facility assets and recorded a $15 million loss upon commencement of the related PPA, which Southern

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(UNAUDITED)

Power accounts for as a sales-type lease. The lease has an initial term of 20 years. Upon commencement of the lease, the $113 million book value of the assets was derecognized from CWIP and a lease receivable was recorded. At September 30, 2021, the current portion of the lease receivable of $8 million is included in other current assets and the long-term portion of $91 million is included in net investment in sales-type lease on the balance sheet. The transfer represented a noncash investing transaction for purposes of the statement of cash flows. The undiscounted cash flows expected to be received by Southern Power for assets under the lease are as follows:

	At September 30, 2021
	(in millions)
2021 (remaining)	$	2
2022	8
2023	8
2024	8
2025	8
2026	8
Thereafter	115
Total undiscounted cash flows	$	157
Net investment in sales-type lease(*)	99
Difference between undiscounted cash flows and discounted cash flows	$	58

(*)Included in other current assets and other property and investments on the balance sheet.

See Note (K) under "Southern Power" for additional information on the Garland battery energy storage facility.

(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, 2021 and December 31, 2020, SP Solar had total assets of $6.2 billion and $6.1 billion, respectively, total liabilities of $364 million and $387 million, respectively, and noncontrolling interests of $1.1 billion. Cash distributions from SP Solar are allocated 67% to Southern Power and 33% to Global Atlantic in accordance with their partnership interest percentage. Under the terms of the limited partnership agreement, distributions without limited partner consent are limited to available cash and SP Solar is obligated to distribute all such available cash to its partners each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves.

At September 30, 2021 and December 31, 2020, SP Wind had total assets of $2.3 billion and $2.4 billion, respectively, total liabilities of $157 million and $138 million, respectively, and noncontrolling interests of $42 million and $43 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.

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(UNAUDITED)

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, 2021 and December 31, 2020, the other VIEs had total assets of $1.9 billion and $1.1 billion, respectively, total liabilities of $263 million and $110 million, respectively, and noncontrolling interests of $902 million and $454 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, 2021 and December 31, 2020, Southern Power had equity method investments in wind and battery energy storage projects totaling $83 million and $19 million, respectively. Earnings (loss) from these investments were immaterial for all periods presented.

Southern Company Gas

Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments at September 30, 2021 and December 31, 2020 and related earnings (loss) from those investments for the three and nine months ended September 30, 2021 and 2020 were as follows:

Investment Balance	September 30, 2021		December 31, 2020
	(in millions)
SNG	$	1,130	$	1,167
PennEast Pipeline(*)	11		91
Other	33		32
Total	$	1,174	$	1,290

(*)Investment balance at September 30, 2021 reflects pre-tax impairment charges totaling $84 million recorded during 2021. See Note (C) under "Other Matters – Southern Company Gas" for additional information, including the September 2021 cancellation of the project.

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(UNAUDITED)

	Three Months Ended September 30,				Nine Months Ended September 30,
Earnings (Loss) from Equity Method Investments	2021		2020		2021		2020
	(in millions)
SNG	$	27	$	30	$	93	$	95
PennEast Pipeline(a)(b)	(2)		2		(81)		5
Other(a)(c)	—		1		2		6
Total	$	25	$	33	$	14	$	106

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

(b)Includes pre-tax impairment charges totaling $2 million and $84 million for the three and nine months ended September 30, 2021, respectively. See Note (C) under "Other Matters – Southern Company Gas" for additional information, including the September 2021 cancellation of the project.

(c)On March 24, 2020, Southern Company Gas completed the sale of its interests in Atlantic Coast Pipeline and Pivotal LNG. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.

(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, 2021, committed credit arrangements with banks were as follows:

	Expires
Company	2022		2023		2024		2026		Total		Unused		Due within One Year
	(in millions)
Southern Company parent	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—
Alabama Power	—		—		550		700		1,250		1,250		—
Georgia Power	—		—		—		1,750		1,750		1,726		—
Mississippi Power	—		125		150		—		275		250		—
Southern Power(a)	—		—		—		600		600		568		—
Southern Company Gas(b)	250		—		—		1,500		1,750		1,747		250
SEGCO	30		—		—		—		30		30		30
Southern Company	$	280	$	125	$	700	$	6,550	$	7,655	$	7,570	$	280

(a)Does not include Southern Power Company's $75 million and $60 million continuing letter of credit facilities for standby letters of credit expiring in 2023, of which $23 million and $1 million, respectively, was unused at September 30, 2021. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.

(b)Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $800 million of the arrangement expiring in 2026 and all $250 million of the arrangement expiring in 2022. Southern Company Gas' committed credit arrangement expiring in 2026 also includes $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to the multi-year credit arrangement expiring in 2026, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.

As reflected in the table above, in May 2021, Southern Company, Alabama Power, Georgia Power, and Southern Power each amended and restated certain of its multi-year credit arrangements, which, among other things, extended the maturity dates from 2024 to 2026. Alabama Power also decreased the borrowing capacity under its credit arrangement now maturing in 2026 from $800 million to $700 million. Also in May 2021, Southern Company Gas Capital, along with Nicor Gas, amended and restated their multi-year credit arrangement to extend the maturity date from 2024 to 2026 and decrease the aggregate borrowing capacity from $1.75 billion to $1.5 billion. In addition,

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(UNAUDITED)

Southern Company Gas Capital entered into a new $250 million credit arrangement, which is guaranteed by Southern Company Gas, that matures in 2022. In June 2021, Mississippi Power amended and restated certain of its multi-year credit arrangements aggregating $150 million, which, among other things, extended the maturity dates from 2022 to 2024. In August 2021, Alabama Power amended and restated one of its multi-year credit arrangements, which, among other things, extended the maturity date from 2022 to 2024 and increased the borrowing capacity from $525 million to $550 million.

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, Nicor Gas, 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, 2021, 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, 2021 was approximately $1.6 billion (comprised of approximately $854 million at Alabama Power, $672 million at Georgia Power, and $34 million at Mississippi Power). In addition, at September 30, 2021, Georgia Power and Mississippi Power had approximately $262 million and $50 million, respectively, 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 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 equity units and Note 12 to the financial statements in Item 8 of the Form 10-K for information on stock-based compensation plans. Shares used to compute diluted earnings per share were as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020
	(in millions)
As reported shares	1,061	1,058	1,060	1,058
Effect of stock-based compensation	7	6	7	6
Diluted shares	1,068	1,064	1,067	1,064

For all periods presented, an immaterial number of stock-based compensation awards was not included in the diluted earnings per share calculation because the awards were anti-dilutive.

An immaterial number of shares related to the equity units issued in 2019 was included in the calculations 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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(UNAUDITED)

(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 $1.2 billion at September 30, 2021 compared to $1.4 billion at December 31, 2020.

The federal ITC and PTC carryforwards begin expiring in 2036 and 2032, respectively, but are expected to be fully utilized by 2024. The utilization of each Registrant's estimated tax credit and state net operating loss carryforwards and related valuation allowances could be impacted by numerous factors, including the acquisition of additional renewable projects, the purchase of rights to additional PTCs of Plant Vogtle Units 3 and 4 pursuant to certain joint ownership agreements, changes in taxable income projections, and potential income tax rate changes. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.

Valuation Allowances

Details of significant changes in valuation allowances for the applicable Registrants are provided below:

	Southern Company		Georgia Power
	(in millions)
Federal	$	20	$	—
State (net of federal benefit)	92		28
Balance at December 31, 2020	$	112	$	28
Federal	$	20	$	—
State (net of federal benefit)	122		58
Balance at September 30, 2021	$	142	$	58

The increase in valuation allowances, net of federal benefit, for Southern Company and Georgia Power during 2021 was primarily due to Georgia Power's projected inability to utilize certain state tax credit carryforwards.

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 17.5% for the nine months ended September 30, 2021 compared to 13.9% for the corresponding period in 2020. The effective tax rate increase was primarily related to changes in state apportionment rates as a result of the sale of Sequent, an increase in the valuation allowance on certain state tax credit carryforwards, and the tax impact of the second quarter 2020 charge to earnings associated with a leveraged lease investment. See "Valuation Allowances" herein, Note (K) under "Southern Company Gas," and Note 3 to the financial statements in Item 8 of the Form 10-K under "Other Matters – Southern Company" for additional information.

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(UNAUDITED)

Georgia Power

Georgia Power's effective tax rate was 7.3% for the nine months ended September 30, 2021 compared to 12.3% for the corresponding period in 2020. The effective tax rate decrease was primarily due to higher charges to earnings in 2021 associated with the construction of Plant Vogtle Units 3 and 4, partially offset by an increase in the valuation allowance on certain state tax credit carryforwards. See "Valuation Allowances" herein and Note (B) under "Georgia Power – Nuclear Construction" for additional information.

Southern Power

Southern Power's effective tax benefit rate was (1.6)% for the nine months ended September 30, 2021 compared to an effective tax rate of 11.3% for the corresponding period in 2020. The effective tax rate decrease was primarily due to changes in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in February 2021, as well as the tax impact from the sale of Plant Mankato in January 2020. See Note 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K for additional information.

Southern Company Gas

Southern Company Gas' effective tax rate was 36.6% for the nine months ended September 30, 2021 compared to 21.4% for the corresponding period in 2020. The effective tax rate increase was primarily related to changes in state apportionment rates as a result of the sale of Sequent. See Note (K) under "Southern Company Gas" 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, 2021. 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.

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, 2021 and 2020 are presented in the following tables.

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	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2021
Pension Plans
Service cost	$	109	$	26	$	28	$	4	$	2	$	10
Interest cost	87		20		26		4		2		6
Expected return on plan assets	(298)		(72)		(94)		(14)		(4)		(21)
Amortization:
Prior service costs	—		—		—		—		—		(1)
Regulatory asset	—		—		—		—		—		3
Net (gain)/loss	78		21		25		4		1		3
Net periodic pension cost (income)	$	(24)	$	(5)	$	(15)	$	(2)	$	1	$	—
Postretirement Benefits
Service cost	$	6	$	2	$	2	$	1	$	1	$	—
Interest cost	9		2		3		—		—		1
Expected return on plan assets	(19)		(8)		(7)		(1)		—		(2)
Amortization:
Regulatory asset	—		—		—		—		—		2
Net (gain)/loss	1		—		1		—		—		(1)
Net periodic postretirement benefit cost (income)	$	(3)	$	(4)	$	(1)	$	—	$	1	$	—
Nine Months Ended September 30, 2021
Pension Plans
Service cost	$	326	$	77	$	84	$	13	$	7	$	28
Interest cost	260		61		78		12		4		18
Expected return on plan assets	(893)		(215)		(282)		(41)		(11)		(64)
Amortization:
Prior service costs	—		—		1		—		—		(2)
Regulatory asset	—		—		—		—		—		11
Net (gain)/loss	235		62		75		11		3		9
Net periodic pension cost (income)	$	(72)	$	(15)	$	(44)	$	(5)	$	3	$	—
Postretirement Benefits
Service cost	$	18	$	5	$	5	$	1	$	1	$	1
Interest cost	26		6		9		1		—		3
Expected return on plan assets	(57)		(22)		(20)		(2)		—		(6)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		5
Net (gain)/loss	3		—		2		—		—		(2)
Net periodic postretirement benefit cost (income)	$	(11)	$	(11)	$	(4)	$	—	$	1	$	1

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	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2020
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 (income)	$	2	$	(2)	$	—	$	—	$	1	$	1
Nine Months Ended September 30, 2020
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 (income)	$	4	$	(7)	$	1	$	1	$	1	$	4

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(I) FAIR VALUE MEASUREMENTS

At September 30, 2021, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

	Fair Value Measurements Using:
At September 30, 2021	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)	$	75	$	425	$	—	$	—	$	500
Interest rate derivatives	—		25		—		—		25
Foreign currency derivatives	—		20		—		—		20
Investments in trusts:(b)(c)
Domestic equity	738		237		—		—		975
Foreign equity	167		183		—		—		350
U.S. Treasury and government agency securities	—		352		—		—		352
Municipal bonds	—		48		—		—		48
Pooled funds – fixed income	—		14		—		—		14
Corporate bonds	2		472		—		—		474
Mortgage and asset backed securities	—		92		—		—		92
Private equity	—		—		—		123		123
Cash and cash equivalents	5		—		—		—		5
Other	29		13		—		—		42
Cash equivalents	1,498		9		—		—		1,507
Other investments	9		26		—		—		35
Total	$	2,523	$	1,916	$	—	$	123	$	4,562
Liabilities:
Energy-related derivatives(a)	$	27	$	17	$	—	$	—	$	44
Interest rate derivatives	—		16		—		—		16
Foreign currency derivatives	—		43		—		—		43
Contingent consideration	—		—		16		—		16
Other	—		13		—		—		13
Total	$	27	$	89	$	16	$	—	$	132

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	Fair Value Measurements Using:
At September 30, 2021	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	$	—	$	104	$	—	$	—	$	104
Interest rate derivatives	—		5		—		—		5
Nuclear decommissioning trusts:(b)
Domestic equity	444		227		—		—		671
Foreign equity	167		—		—		—		167
U.S. Treasury and government agency securities	—		22		—		—		22
Municipal bonds	—		1		—		—		1
Corporate bonds	2		243		—		—		245
Mortgage and asset backed securities	—		22		—		—		22
Private equity	—		—		—		123		123
Other	6		—		—		—		6
Cash equivalents	443		9		—		—		452
Other investments	—		26		—		—		26
Total	$	1,062	$	659	$	—	$	123	$	1,844
Liabilities:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4
Georgia Power
Assets:
Energy-related derivatives	$	—	$	166	$	—	$	—	$	166
Nuclear decommissioning trusts:(b)(c)
Domestic equity	294		1		—		—		295
Foreign equity	—		180		—		—		180
U.S. Treasury and government agency securities	—		330		—		—		330
Municipal bonds	—		47		—		—		47
Corporate bonds	—		229		—		—		229
Mortgage and asset backed securities	—		70		—		—		70
Other	23		13		—		—		36
Cash equivalents	240		—		—		—		240
Total	$	557	$	1,036	$	—	$	—	$	1,593
Liabilities:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4

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	Fair Value Measurements Using:
At September 30, 2021	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	$	—	$	105	$	—	$	—	$	105
Cash equivalents	121		—		—		—		121
Total	$	121	$	105	$	—	$	—	$	226
Liabilities:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Southern Power
Assets:
Energy-related derivatives	$	—	$	10	$	—	$	—	$	10
Foreign currency derivatives	—		20		—		—		20
Total	$	—	$	30	$	—	$	—	$	30
Liabilities:
Energy-related derivatives	$	—	$	2	$	—	$	—	$	2
Foreign currency derivatives	—		11		—		—		11
Contingent consideration	—		—		16		—		16
Other	—		13		—		—		13
Total	$	—	$	26	$	16	$	—	$	42
Southern Company Gas
Assets:
Energy-related derivatives(a)	$	75	$	40	$	—	$	—	$	115
Interest rate derivatives	—		6		—		—		6
Non-qualified deferred compensation trusts:
Domestic equity	—		9		—		—		9
Foreign equity	—		3		—		—		3
Pooled funds – fixed income	—		14		—		—		14
Cash equivalents	5		—		—		—		5
Total	$	80	$	72	$	—	$	—	$	152
Liabilities:
Energy-related derivatives(a)	$	27	$	4	$	—	$	—	$	31
Interest rate derivatives	—		4		—		—		4
Total	$	27	$	8	$	—	$	—	$	35

(a)Excludes cash collateral of $(20) million.

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

(c)Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. At September 30, 2021, approximately $57 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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See Note (K) under "Assets Held for Sale" for information regarding assets recorded at fair value on a nonrecurring basis.

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 nine months ended September 30, 2021 and 2020. 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, 2021		Three Months Ended September 30, 2020		Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020
	(in millions)
Southern Company	$	9	$	108	$	173	$	85
Alabama Power	15		66		133		24
Georgia Power	(6)		42		40		61

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 it is primarily obligated to make generation-based payments to the seller, which commenced at the commercial operation of the respective facility and continue through 2026. The obligations are categorized as Level 3 under Fair Value Measurements as

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the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.

Southern Power also has payment obligations through 2040 whereby it must reimburse the transmission owners for interconnection facilities and network upgrades constructed to support connection of a Southern Power generating facility to the transmission system. The obligations are categorized as Level 2 under Fair Value Measurements as the fair value is determined using observable inputs for the contracted amounts and reimbursement period, as well as a discount rate. The fair value of the obligations reflects the net present value of expected payments.

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

At September 30, 2021, 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 $123 million and unfunded commitments related to the private equity investments totaled $72 million. Private equity investments include high-quality private equity funds across several market sectors and funds that invest in real estate assets. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.

At September 30, 2021, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas(*)
	(in billions)
Long-term debt, including securities due within one year:
Carrying amount	$	51.9	$	9.1	$	13.6	$	1.6	$	4.0	$	6.8
Fair value	57.6		10.4		15.2		1.7		4.4		7.8

(*)The long-term debt of Southern Company Gas is recorded at amortized cost, including the fair value adjustments at the effective date of the 2016 merger with Southern Company. Southern Company Gas amortizes the fair value adjustments over the remaining lives of the respective bonds, the latest being through 2043.

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

Commodity Contracts with Level 3 Valuation Inputs

Prior to July 1, 2021, Southern Company Gas had Level 3 physical natural gas forward contracts related to Sequent. See Note (K) under "Southern Company Gas" for information regarding the sale of Sequent. 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

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the unobservable components. The following table provides a reconciliation of Southern Company Gas' Level 3 contracts during the three and nine months ended September 30, 2021.

	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	(in millions)
Beginning balance	$	18	$	28
Instruments realized or otherwise settled during period	—		(6)
Changes in fair value	—		(4)
Sale of Sequent	(18)		(18)
Ending balance	$	—	$	—

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 prior to the sale of Sequent.

(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. Through the sale of Sequent on July 1, 2021, Southern Company Gas' wholesale gas operations used various contracts in its commercial activities that generally met the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with the classification of the hedged interest or principal, respectively. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information. See Note (K) under "Southern Company Gas" for information regarding Southern Company Gas' sale of Sequent.

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.

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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 an approved cost recovery mechanism.

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

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

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

At September 30, 2021, 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(*)	336	2030	2024
Alabama Power	75	2024	—
Georgia Power	99	2024	—
Mississippi Power	79	2025	—
Southern Power	6	2030	2022
Southern Company Gas(*)	77	2024	2024

(*)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 91.4 million mmBtu and short natural gas positions of 14.3 million mmBtu at September 30, 2021, which is also included in Southern Company's total volume. See Note (K) under "Southern Company Gas" for information regarding Southern Company Gas' sale of Sequent.

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 41 million mmBtu for Southern Company, which includes 10 million mmBtu for Alabama Power, 13 million mmBtu for Georgia Power, 5 million mmBtu for Mississippi Power, and 13 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, 2022 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. 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, 2021, 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, 2021
	(in millions)					(in millions)
Cash Flow Hedges of Forecasted Debt
Alabama Power	$	150	—	1.91%	August 2051	$	5
Fair Value Hedges of Existing Debt
Southern Company parent	400		1.75%	1-month LIBOR + 0.68%	March 2028	(2)
Southern Company parent	1,000		3.70%	1-month LIBOR + 2.36%	April 2030	3
Southern Company Gas	500		1.75%	1-month LIBOR + 0.38%	January 2031	2
Southern Company	$	2,050				$	8

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, 2022 total $(22) 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 2051 for the Southern Company parent entity, 2051 for Alabama Power, 2044 for Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.

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Foreign Currency Derivatives

Southern Company and certain subsidiaries, including Southern Power, may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Southern Company has elected to exclude the cross-currency basis spread from the assessment of effectiveness in the fair value hedges of its foreign currency risk and record any difference between the change in the fair value of the excluded components and the amounts recognized in earnings as a component of OCI.

At September 30, 2021, 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, 2021
	(in millions)			(in millions)				(in millions)
Fair Value Hedges of Existing Debt
Southern Company parent	$	1,476	3.39%	€	1,250	1.88%	September 2027	$	(32)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	9
Southern Power	564		3.78%	500		1.85%	June 2026	—
Southern Power total	$	1,241		€	1,100			$	9
Southern Company	$	2,717		€	2,350			$	(23)

The estimated pre-tax gain (loss) related to Southern Power's foreign currency derivatives accounted for as cash flow hedges expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2022 is $(4) 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:

	At September 30, 2021				At December 31, 2020
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:
Assets from risk management activities/Other current liabilities	$	308	$	9	$	24	$	11
Other deferred charges and assets/Other deferred credits and liabilities	118		6		18		19
Total derivatives designated as hedging instruments for regulatory purposes	$	426	$	15	$	42	$	30
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Other current liabilities	$	41	$	—	$	3	$	5
Other deferred charges and assets/Other deferred credits and liabilities	4		—		—		—
Interest rate derivatives:
Assets from risk management activities/Other current liabilities	25		—		20		—
Other deferred charges and assets/Other deferred credits and liabilities	—		16		—		—
Foreign currency derivatives:
Assets from risk management activities/Other current liabilities	9		33		—		23
Other deferred charges and assets/Other deferred credits and liabilities	11		10		87		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	90	$	59	$	110	$	28
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Other current liabilities	$	29	$	29	$	388	$	331
Other deferred charges and assets/Other deferred credits and liabilities	1		—		270		232
Total derivatives not designated as hedging instruments	$	30	$	29	$	658	$	563
Gross amounts recognized	$	546	$	103	$	810	$	621
Gross amounts offset(a)	(57)		(37)		(529)		(557)
Net amounts recognized in the Balance Sheets(b)	$	489	$	66	$	281	$	64

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	At September 30, 2021				At December 31, 2020
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	$	67	$	2	$	7	$	2
Other deferred charges and assets/Other deferred credits and liabilities	37		2		5		5
Total derivatives designated as hedging instruments for regulatory purposes	$	104	$	4	$	12	$	7
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	5	$	—	$	—	$	—
Gross amounts recognized	$	109	$	4	$	12	$	7
Gross amounts offset	(3)		(3)		(7)		(7)
Net amounts recognized in the Balance Sheets	$	106	$	1	$	5	$	—
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	124	$	2	$	7	$	5
Other deferred charges and assets/Other deferred credits and liabilities	42		2		8		8
Total derivatives designated as hedging instruments for regulatory purposes	$	166	$	4	$	15	$	13
Gross amounts recognized	$	166	$	4	$	15	$	13
Gross amounts offset	(3)		(3)		(12)		(12)
Net amounts recognized in the Balance Sheets	$	163	$	1	$	3	$	1
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	66	$	1	$	4	$	3
Other deferred charges and assets/Other deferred credits and liabilities	39		2		5		6
Total derivatives designated as hedging instruments for regulatory purposes	$	105	$	3	$	9	$	9
Gross amounts recognized	$	105	$	3	$	9	$	9
Gross amounts offset	(2)		(2)		(7)		(7)
Net amounts recognized in the Balance Sheets	$	103	$	1	$	2	$	2

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	At September 30, 2021				At December 31, 2020
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Southern Power
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	8	$	—	$	2	$	2
Other deferred charges and assets/Other deferred credits and liabilities	1		—		—		—
Foreign currency derivatives:
Other current assets/Other current liabilities	9		11		—		23
Other deferred charges and assets/Other deferred credits and liabilities	11		—		87		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	29	$	11	$	89	$	25
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	1	$	2	$	—	$	1
Total derivatives not designated as hedging instruments	$	1	$	2	$	—	$	1
Gross amounts recognized	$	30	$	13	$	89	$	26
Gross amounts offset	(1)		(1)		—		—
Net amounts recognized in the Balance Sheets	$	29	$	12	$	89	$	26

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(UNAUDITED)

	At September 30, 2021				At December 31, 2020
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/Other current liabilities	$	51	$	4	$	6	$	1
Total derivatives designated as hedging instruments for regulatory purposes	$	51	$	4	$	6	$	1
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Other current liabilities	$	33	$	—	$	1	$	3
Other deferred charges and assets/Other deferred credits and liabilities	3		—		—		—
Interest rate derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	6		—		—		—
Other deferred charges and assets/Other deferred credits and liabilities	—		4		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	42	$	4	$	1	$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Other current liabilities	$	28	$	27	$	388	$	330
Other deferred charges and assets/Other deferred credits and liabilities	1		—		270		232
Total derivatives not designated as hedging instruments	$	29	$	27	$	658	$	562
Gross amounts recognized	$	122	$	35	$	665	$	566
Gross amounts offset(a)	(48)		(28)		(503)		(531)
Net amounts recognized in the Balance Sheets(b)	$	74	$	7	$	162	$	35

(a)Gross amounts offset include cash collateral held on deposit in broker margin accounts of $(20) million and $28 million at September 30, 2021 and December 31, 2020, respectively.

(b)Net amounts of derivative instruments outstanding exclude immaterial premium and intrinsic value associated with weather derivatives for both periods presented.

The traditional electric operating companies had no energy-related derivatives not designated as hedging instruments at September 30, 2021 or December 31, 2020.

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At September 30, 2021 and December 31, 2020, 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, 2021:
Energy-related derivatives:
Other regulatory assets, current	$	(5)	$	(1)	$	(1)	$	—	$	(3)
Other regulatory liabilities, current	297		66		123		66		42
Other regulatory liabilities, deferred	112		35		40		37		—
Total energy-related derivative gains (losses)	$	404	$	100	$	162	$	103	$	39
At December 31, 2020:
Energy-related derivatives:
Other regulatory assets, deferred	$	(2)	$	—	$	(1)	$	(1)	$	—
Other regulatory liabilities, current	12		5		2		1		4
Other regulatory liabilities, deferred	2		1		1		—		—
Total energy-related derivative gains (losses)	$	12	$	6	$	2	$	—	$	4

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For the three and nine months ended September 30, 2021 and 2020, the pre-tax effects of cash flow and fair value hedge accounting on accumulated OCI were as follows:

Gain (Loss) Recognized in OCI on Derivative	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Southern Company
Cash flow hedges:
Energy-related derivatives	$	38	$	9	$	59	$	2
Interest rate derivatives	5		1		7		(27)
Foreign currency derivatives	(36)		54		(79)		(10)
Fair value hedges(*):
Foreign currency derivatives	(4)		—		(4)		—
Total	$	3	$	64	$	(17)	$	(35)
Southern Power
Cash flow hedges:
Energy-related derivatives	$	8	$	5	$	16	$	2
Foreign currency derivatives	(36)		54		(79)		(10)
Total	$	(28)	$	59	$	(63)	$	(8)
Southern Company Gas
Cash flow hedges:
Energy-related derivatives	$	30	$	4	$	43	$	—
Interest rate derivatives	—		1		—		(24)
Total	$	30	$	5	$	43	$	(24)

(*)Represents amounts excluded from the assessment of effectiveness for which the difference between changes in fair value and periodic amortization is recorded in OCI.

For the three and nine months ended September 30, 2021 and 2020, the pre-tax effects of 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, 2021 and 2020, 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,
	2021		2020		2021		2020
	(in millions)				(in millions)
Southern Company
Total cost of natural gas	$	129	$	71	$	943	$	654
Gain (loss) on energy-related cash flow hedges(a)	2		—		—		(8)
Total depreciation and amortization	896		889		2,658		2,619
Gain (loss) on energy-related cash flow hedges(a)	3		(1)		6		(3)
Total interest expense, net of amounts capitalized	(451)		(443)		(1,352)		(1,343)
Gain (loss) on interest rate cash flow hedges(a)	(7)		(6)		(20)		(19)
Gain (loss) on foreign currency cash flow hedges(a)	(6)		(6)		(18)		(18)
Gain (loss) on interest rate fair value hedges(b)	(4)		(3)		(16)		27
Total other income (expense), net	131		113		297		319
Gain (loss) on foreign currency cash flow hedges(a)(c)	(34)		56		(76)		52
Gain (loss) on foreign currency fair value hedges	(32)		—		(32)		—
Amount excluded from effectiveness testing recognized in earnings	4		—		4		—
Southern Power
Total depreciation and amortization	$	132	$	129	$	383	$	367
Gain (loss) on energy-related cash flow hedges(a)	3		(1)		6		(3)
Total interest expense, net of amounts capitalized	(36)		(36)		(111)		(114)
Gain (loss) on foreign currency cash flow hedges(a)	(6)		(6)		(18)		(18)
Total other income (expense), net	2		13		10		19
Gain (loss) on foreign currency cash flow hedges(a)(c)	(34)		56		(76)		52

(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, 2021 and 2020, 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.

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(UNAUDITED)

At September 30, 2021 and December 31, 2020, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:

	Carrying Amount of the Hedged Item				Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items	At September 30, 2021		At December 31, 2020		At September 30, 2021		At December 31, 2020
	(in millions)				(in millions)
Southern Company
Securities due within one year	$	—	$	(1,509)	$	—	$	(10)
Long-term debt	(3,320)		—		—		—
Southern Company Gas
Long-term debt	$	(497)	$	—	$	(1)	$	—

For the three and nine months ended September 30, 2021 and 2020, 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	2021		2020		2021		2020
		(in millions)				(in millions)
Energy-related derivatives:	Natural gas revenues(*)	$	(2)	$	(30)	$	(122)	$	54
	Cost of natural gas	20		5		36		18
Total derivatives in non-designated hedging relationships		$	18	$	(25)	$	(86)	$	72

(*)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, 2021 and 2020, 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, 2021, the Registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

At September 30, 2021, the Registrants had no interest rate derivative liabilities with contingent features. At September 30, 2021, 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, Inc., 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.

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(UNAUDITED)

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 and they may be required to post collateral based on the value of the positions in these accounts and the associated margin requirements. At September 30, 2021, 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, 2021, cash collateral held on deposit in broker margin accounts was $(20) million.

The Registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Registrants only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Registrants have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk.

Southern Company Gas uses established credit policies to determine and monitor the creditworthiness of counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or U.S. government securities held by a trustee. Prior to entering a physical transaction, Southern Company Gas assigns its counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.

Southern Company Gas utilizes netting agreements whenever possible to mitigate exposure to counterparty credit risk. Netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty across product lines and against cash collateral, provided the netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, counterparties are settled net, they are recorded on a gross basis on the balance sheet as energy marketing receivables and energy marketing payables.

The Registrants do not anticipate a material adverse effect on their respective financial statements as a result of counterparty nonperformance.

(K) ACQUISITIONS AND DISPOSITIONS

See Note 15 to the financial statements in Item 8 of the Form 10-K for additional information.

Southern Company

On October 29, 2021, Southern Company completed the sale of assets subject to a leveraged lease to the lessee for $45 million. No gain or loss was recognized on the sale. During the fourth quarter 2021, income tax benefits of approximately $16 million will be recognized as a result of the sale. At September 30, 2021, the leveraged lease investment was classified as held for sale. See Note 3 to the financial statements under "Other Matters – Southern Company" in Item 8 of the Form 10-K and "Assets Held for Sale" herein for additional information.

Alabama Power

On September 23, 2021, Alabama Power entered into an agreement to acquire all of the equity interests in Calhoun Power Company, LLC, which owns and operates the Calhoun Generating Station. See Note (B) under "Alabama Power – Calhoun Generating Station Acquisition" for additional information.

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Southern Power

Asset Acquisition

During the nine months ended September 30, 2021, Southern Power acquired a controlling membership 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
Deuel Harvest(*)	Wind	Invenergy Renewables, LLC	300	Deuel County, SD	100% of Class B	February 2021	25 years and 15 years

(*)On March 26, 2021, Southern Power acquired a controlling interest in the project from Invenergy Renewables LLC and, on March 30, 2021, Southern Power completed a tax equity transaction whereby it sold the Class A membership interests in the project. Southern Power consolidates the project's operating results in its financial statements and the tax equity partner and Invenergy Renewables LLC each own a noncontrolling interest.

Construction Projects

During the nine months ended September 30, 2021, Southern Power completed construction of and placed in service 45 MWs of the Garland battery energy storage facility and continued construction of the Tranquillity battery energy storage facility, the Glass Sands wind facility, and the remainder of the Garland battery energy storage facility. Total aggregate construction costs, excluding acquisition costs, are expected to be between $400 million and $460 million for the facilities under construction. At September 30, 2021, total costs of construction incurred for these projects were $341 million, of which $228 million remains 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 Under Construction at September 30, 2021
Garland Solar Storage(a)	Battery energy storage system	88	Kern County, CA	September 2021 and fourth quarter 2021(b)	20 years
Tranquillity Solar Storage(a)	Battery energy storage system	72	Fresno County, CA	Fourth quarter 2021 and first quarter 2022	20 years
Glass Sands(c)	Wind	118	Murray County, OK	Fourth quarter 2021	12 years

(a)During the third quarter 2021, Southern Power further restructured its ownership in the Garland and Tranquillity battery energy storage projects and completed tax equity transactions whereby it sold the Class A membership interests in the projects. Southern Power consolidates each project's operating results in its financial statements and the tax equity partner and two other partners each own a noncontrolling interest.

(b)The facility has a total capacity of 88 MWs, of which 45 MWs were placed in service in September 2021 and 43 MWs are expected to be placed in service later in the fourth quarter 2021.

(c)In December 2020, Southern Power purchased 100% of the membership interests of the Glass Sands facility.

Development Projects

Southern Power continues to evaluate and refine the deployment of the remaining wind turbine equipment purchased in 2016 and 2017 for development and construction projects. During the nine months ended September 30, 2021, gains on wind turbine equipment contributed to various equity method investments totaled approximately $37 million.

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Southern Company Gas

Sale of Sequent

On July 1, 2021, Southern Company Gas affiliates completed the sale of Sequent to Williams Field Services Group for a total cash purchase price of $159 million, including final working capital adjustments. The preliminary pre-tax gain associated with the transaction is approximately $121 million ($93 million after tax). As a result of the sale, changes in state apportionment rates resulted in $85 million of additional tax expense.

Prior to the sale, Southern Company Gas had existing agreements in place in which it guaranteed the payment performance of Sequent. Southern Company Gas will continue to guarantee Sequent's payment performance for a period of time as Williams Field Services Group obtains releases from these obligations. At September 30, 2021, the obligations subject to the payment performance guarantee totaled $36 million. Changes in the price of natural gas, market conditions, and the number of open contracts may change the amount that Southern Company Gas is required to guarantee for Sequent each month. The maximum potential exposure over the period of the payment performance guarantee generally is capped at $1 billion. At closing, Williams Field Services Group issued a payment performance guarantee to Southern Company Gas, equal to the outstanding guarantee obligation throughout this period.

Southern Company Gas' sale of Sequent did not represent a strategic shift in operations that has, or is expected to have, a major effect on its operations and financial results; therefore, none of the assets were classified as discontinued operations for any of the periods presented.

Sale of Pivotal LNG

In connection with its March 2020 sale of Pivotal LNG, Southern Company Gas was entitled to two $5 million payments contingent upon Dominion Modular LNG Holdings, Inc. meeting certain milestones related to Pivotal LNG. Southern Company Gas received the first payment on April 22, 2021 and expects to receive the second payment in February 2022.

Assets Held for Sale

The following table provides the major classes of assets classified as held for sale by Southern Company at September 30, 2021 and December 31, 2020:

	Southern Company
	At September 30,		At December 31,
	2021		2020
	(in millions)
Assets Held for Sale:
Total property, plant, and equipment	$	6	$	8
Leveraged leases	45		52
Total Assets Held for Sale	$	51	$	60

Southern Company's assets held for sale at September 30, 2021 and December 31, 2020 were recorded at fair value on a nonrecurring basis, based primarily on unobservable inputs (Level 3). See "Southern Company" herein for additional information.

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(UNAUDITED)

(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 and battery energy storage projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through its natural gas distribution utilities and is involved in several other complementary businesses including gas pipeline investments, wholesale gas services (through June 30, 2021), 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 $167 million and $361 million for the three and nine months ended September 30, 2021, respectively, and $101 million and $279 million for the three and nine months ended September 30, 2020, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were immaterial for all periods presented. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $18 million for the nine months ended September 30, 2021, which represented sales from Sequent through June 30, 2021, and $9 million and $22 million for the three and nine months ended September 30, 2020, 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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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

Financial data for business segments and products and services for the three and nine months ended September 30, 2021 and 2020 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, 2021
Operating revenues	$	5,018	$	679	$	(170)	$	5,527	$	623	$	124	$	(36)	$	6,238
Segment net income (loss)(a)(b)(c)	1,085		78		—		1,163		56		(121)		3		1,101
Nine Months Ended September 30, 2021
Operating revenues	$	12,813	$	1,610	$	(372)	$	14,051	$	2,994	$	412	$	(111)	$	17,346
Segment net income (loss)(a)(b)(c)(d)(e)(f)	2,352		211		—		2,563		389		(338)		(6)		2,608
At September 30, 2021
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	263	$	—	$	5,280
Assets held for sale	3		—		—		3		—		48		—		51
Total assets	89,057		13,611		(708)		101,960		22,958		3,704		(761)		127,861
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)(c)(f)(g)	2,571		212		—		2,783		360		(420)		9		2,732
At December 31, 2020
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	263	$	—	$	5,280
Assets held for sale	5		—		—		5		—		55		—		60
Total assets	85,486		13,235		(680)		98,041		22,630		3,168		(904)		122,935

(a)Attributable to Southern Company.

(b)For Southern Company Gas, includes a preliminary pre-tax gain of $121 million ($93 million after tax) related to its sale of Sequent, as well as the resulting $85 million of additional tax expense due to changes in state apportionment rates. See Note (K) under "Southern Company Gas" for additional information.

(c)For the traditional electric operating companies, includes pre-tax charges at Georgia Power for estimated losses associated with the construction of Plant Vogtle Units 3 and 4 of $264 million ($197 million after tax) and $772 million ($576 million after tax) for the three and nine months ended September 30, 2021, respectively, and $149 million ($111 million after tax) for the nine months ended September 30, 2020. 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.

(d)For Southern Power, includes gains on wind turbine equipment contributed to various equity method investments totaling approximately $37 million pre-tax ($28 million after tax). See Notes (E) and (K) under "Southern Power" for additional information.

(e)For Southern Company Gas, includes pre-tax impairment charges totaling $84 million ($67 million after tax) related to its equity method investment in the PennEast Pipeline project. See Notes (C) and (E) under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, for additional information.

(f)For the "All Other" column, includes pre-tax impairment charges related to leveraged lease investments of $7 million ($6 million after tax) and $154 million ($74 million after tax) for the nine months ended September 30, 2021 and 2020, respectively. See Note 3 to the financial statements in Item 8 of the Form 10-K under "Other Matters – Southern Company" for additional information.

(g)For Southern Power, includes a $39 million pre-tax gain ($23 million gain after tax) on the sale of Plant Mankato. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power" for additional information.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

Products and Services

	Electric Utilities' Revenues
	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2021	$	4,551	$	731	$	245	$	5,527
Three Months Ended September 30, 2020	4,243		584		222		5,049
Nine Months Ended September 30, 2021	$	11,492	$	1,822	$	737	$	14,051
Nine Months Ended September 30, 2020	10,503		1,473		652		12,628

	Southern Company Gas' Revenues
	Gas Distribution Operations		Wholesale Gas Services(*)		Gas Marketing Services		Other		Total
	(in millions)
Three Months Ended September 30, 2021	$	553	$	—	$	52	$	18	$	623
Three Months Ended September 30, 2020	476		(51)		39		13		477
Nine Months Ended September 30, 2021	$	2,451	$	188	$	311	$	44	$	2,994
Nine Months Ended September 30, 2020	2,072		(19)		272		37		2,362

(*)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. Also see Note (K) under "Southern Company Gas" regarding the July 1, 2021 sale of Sequent.

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. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information on the disposition activities described herein.

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 project, and a 50% joint ownership interest in the Dalton Pipeline. These natural gas pipelines enable the provision of diverse sources of natural gas supplies to the customers of Southern Company Gas. Gas pipeline investments also included a 5% ownership interest in the Atlantic Coast Pipeline construction project prior to its sale on March 24, 2020. See Note (C) under "Other Matters – Southern Company Gas" for information regarding the September 2021 cancellation of the PennEast Pipeline project.

Wholesale gas services (until the sale of Sequent on July 1, 2021) provided natural gas asset management and/or related logistics services for each of Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. The Virginia Natural Gas asset management agreement ended on March 31, 2021 and was not extended. Additionally, wholesale gas services engaged in natural gas storage and gas pipeline arbitrage and related activities. See Note (K) under "Southern Company Gas" for information regarding the sale of Sequent on July 1, 2021.

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

The all other column includes segments and subsidiaries that fall below the quantitative threshold for separate disclosure, including storage and fuels operations. The all other column included Jefferson Island through its sale on December 1, 2020 and Pivotal LNG through its sale on March 24, 2020.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

Business segment financial data for the three and nine months ended September 30, 2021 and 2020 was as follows:

	Gas Distribution Operations		Gas Pipeline Investments		Wholesale Gas Services(a)		Gas Marketing Services		Total		All Other		Eliminations		Consolidated
	(in millions)
Three Months Ended September 30, 2021
Operating revenues	$	556	$	8	$	—	$	52	$	616	$	11	$	(4)	$	623
Segment net income (loss)(b)(c)	45		10		94		(2)		147		(91)		—		56
Nine Months Ended September 30, 2021
Operating revenues	$	2,466	$	24	$	188	$	311	$	2,989	$	29	$	(24)	$	2,994
Segment net income (loss)(b)(c)(d)	308		3		108		60		479		(90)		—		389
Total assets at September 30, 2021	20,619		1,478		132		1,534		23,763		11,387		(12,192)		22,958
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 December 31, 2020	19,090		1,597		850		1,503		23,040		11,336		(11,746)		22,630

(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, 2021	$	—	$	—	$	—	$	—	$	—
Three Months Ended September 30, 2020	1,050		33		1,083		1,134		(51)
Nine Months Ended September 30, 2021	$	3,881	$	90	$	3,971	$	3,783	$	188
Nine Months Ended September 30, 2020	3,089		81		3,170		3,189		(19)

(b)For wholesale gas services, includes a preliminary pre-tax gain of $121 million ($93 million after tax) related to the sale of Sequent. See Note (K) under "Southern Company Gas" for additional information.

(c)For the "All Other" column, includes $85 million of additional tax expense due to changes in state apportionment rates as a result of the sale of Sequent. See Note (K) under "Southern Company Gas" for additional information.

(d)For gas pipeline investments, includes pre-tax impairment charges totaling $84 million ($67 million after tax) related to the equity method investment in the PennEast Pipeline project. See Notes (C) and (E) under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, 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	103
Results of Operations	107
Southern Company	107
Alabama Power	116
Georgia Power	121
Mississippi Power	127
Southern Power	131
Southern Company Gas	135
Future Earnings Potential	143
Accounting Policies	148
Financial Condition and Liquidity	149

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 (until the sale of Sequent on July 1, 2021), and gas marketing services. See Notes (K) and (L) to the Condensed Financial Statements herein for additional information on the sale of Sequent and segment reporting, respectively. 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

Alabama Power

On September 23, 2021, Alabama Power entered into an agreement to acquire all of the equity interests in Calhoun Power Company, LLC, which owns and operates a 743-MW winter peak, simple-cycle, combustion turbine generation facility in Calhoun County, Alabama (Calhoun Generating Station). The completion of the acquisition is subject to the satisfaction and waiver of certain conditions, including, among other customary conditions, approval by the Alabama PSC and the FERC. On October 28, 2021, Alabama Power filed a petition for a certificate of convenience and necessity with the Alabama PSC to procure additional generating capacity through the acquisition of the Calhoun Generating Station. The ultimate outcome of this matter cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Alabama Power – Calhoun Generating Station Acquisition" herein for additional information.

Georgia Power

Plant Vogtle Units 3 and 4 Construction and Start-Up Status

Construction continues on Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately 1,100 MWs each), in which Georgia Power holds a 45.7% ownership interest. Georgia Power's share of the total project capital cost forecast to complete Plant Vogtle Units 3 and 4, including contingency, through September 2022 and June 2023, respectively, is $9.48 billion.

Georgia Power estimates the productivity impacts of the COVID-19 pandemic have consumed approximately three to four months of schedule margin previously embedded in the site work plan for Unit 3 and Unit 4. In addition, throughout 2020, the project continued to face challenges as described in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein. As a result of these factors, in January 2021, Southern Nuclear further extended certain milestone dates, including the start of hot functional testing and fuel load for Unit 3, from those established in October 2020.

Following the January 2021 milestone extensions, Southern Nuclear has been performing additional construction remediation work necessary to ensure quality and design standards are met as system turnovers are completed to

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

support hot functional testing, which was completed in July 2021, and fuel load for Unit 3. As a result of challenges including, but not limited to, construction productivity, construction remediation work, the pace of system turnovers, spent fuel pool repairs, and the timeframe and duration for hot functional and other testing, at the end of the second quarter 2021, Southern Nuclear further extended certain milestone dates, including the fuel load for Unit 3, from those established in January 2021. Through the third quarter 2021, the project continued to face challenges including, but not limited to, construction productivity, construction remediation work, and the pace of system turnovers. As a result of these continued challenges, at the end of the third quarter 2021, Southern Nuclear further extended certain milestone dates, including fuel load for Unit 3, from those established at the end of the second quarter 2021. The site work plan currently targets fuel load for Unit 3 in the first quarter 2022 and an in-service date of May 2022 and primarily depends on significant improvements in overall construction productivity and production levels, the volume of construction remediation work, the pace of system and area turnovers, and the progression of startup and other testing. As the site work plan includes minimal margin to these milestone dates, an in-service date in the third quarter 2022 for Unit 3 is projected, although any further delays could result in a later in-service date.

As the result of productivity challenges, at the end of the second quarter 2021, Southern Nuclear also further extended milestone dates for Unit 4 from those established in January 2021. These productivity challenges continued into the third quarter 2021 and some craft and support resources were diverted temporarily to support construction efforts on Unit 3. As a result of these factors, at the end of the third quarter 2021, Southern Nuclear further extended the milestone dates for Unit 4 from those established at the end of the second quarter 2021. The site work plan targets an in-service date of March 2023 for Unit 4 and primarily depends on overall construction productivity and production levels significantly improving as well as appropriate levels of craft laborers, particularly electricians and pipefitters, being added and maintained. As the site work plan includes minimal margin to the milestone dates, an in-service date in the second quarter 2023 for Unit 4 is projected, although any further delays could result in a later in-service date.

As of March 31, 2021, approximately $84 million of the construction contingency established in the fourth quarter 2020 was assigned to the base capital cost forecast for costs primarily associated with the schedule extension for Unit 3 to December 2021, construction productivity, support resources, and construction remediation work. Georgia Power increased its total capital cost forecast as of March 31, 2021 by adding $48 million to the remaining construction contingency. As of June 30, 2021, all of the remaining construction contingency previously established and an additional $341 million was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units 3 and 4, construction remediation work for Unit 3, and construction productivity and support resources for Units 3 and 4. Georgia Power also increased its total capital cost forecast as of June 30, 2021 by adding $119 million to replenish construction contingency. As a result of the factors discussed above, during the third quarter 2021, all of the remaining construction contingency previously established in the second quarter 2021 and an additional $127 million was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units 3 and 4, construction productivity and support resources for Units 3 and 4, and construction remediation work for Unit 3. Georgia Power also increased its total capital cost forecast as of September 30, 2021 by adding $137 million to replenish construction contingency.

After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded pre-tax charges to income in the first quarter 2021, the second quarter 2021, and the third quarter 2021 of $48 million ($36 million after tax), $460 million ($343 million after tax), and $264 million ($197 million after tax), respectively, for the increases in the total project capital cost forecast. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.

The ultimate impact of the COVID-19 pandemic and other factors 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 "Georgia Power – Nuclear Construction" herein for additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

Plant Vogtle Unit 3 and Common Facilities Rate Proceeding

On June 15, 2021, Georgia Power filed an application with the Georgia PSC to adjust retail base rates to include a portion of costs related to its investment in Plant Vogtle Unit 3 and the common facilities shared between Plant Vogtle Units 3 and 4 (Common Facilities), as well as the related costs of operation. On November 2, 2021, the Georgia PSC voted to approve Georgia Power's application as filed, with certain modifications pursuant to a stipulated agreement between Georgia Power and the staff of the Georgia PSC. The related increase in annual retail base rates of approximately $302 million includes recovery of all projected operations and maintenance expenses for Unit 3 and the Common Facilities and other related costs of operation, partially offset by the related production tax credits, and will become effective the month after Unit 3 is placed in service. This increase will be partially offset by a decrease in the NCCR tariff of approximately $78 million expected to be effective January 1, 2022. See Note (B) to the Condensed Financial Statements under "Georgia Power – Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" herein for additional information.

Rate Plan

In accordance with the terms of the 2019 ARP, on October 1, 2021, Georgia Power filed tariff adjustments to become effective January 1, 2022 that would result in a net increase in rates of $157 million pending approval by the Georgia PSC. The ultimate outcome of this matter cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Georgia Power – Rate Plan" herein for additional information.

Mississippi Power

During the first half of 2021, the Mississippi PSC approved the following non-fuel rate changes related to Mississippi Power's annual rate filings for 2021:

•an annual increase in revenues related to the ad valorem tax adjustment factor of approximately $28 million, which became effective with the first billing cycle of May 2021,

•an annual increase in revenues related to PEP of approximately $16 million, or 1.8%, which became effective with the first billing cycle of April 2021 in accordance with the PEP rate schedule, and

•an annual decrease in revenues related to the ECO Plan of approximately $9 million, which became effective with the first billing cycle of July 2021.

On September 9, 2021, the Mississippi PSC issued an order confirming the conclusion of its review of Mississippi Power's 2021 IRP with no deficiencies identified. The 2021 IRP includes a schedule to retire Plant Watson Unit 4 (268 MWs) and Mississippi Power's 40% ownership interest in Plant Greene County Units 1 and 2 (103 MWs each) in December 2023, 2025, and 2026, respectively, consistent with each unit's remaining useful life in the most recent approved depreciation studies. In addition, the schedule reflects the early retirement of Mississippi Power's 50% undivided ownership interest in Plant Daniel Units 1 and 2 (502 MWs) by the end of 2027.

On October 14, 2021, the Mississippi PSC issued an accounting order giving Mississippi Power the authority to reclassify the retail costs associated with Hurricanes Zeta and Ida to a regulatory asset to be recovered through PEP over a period to be determined in Mississippi Power's 2022 PEP proceeding. At September 30, 2021, these costs totaled approximately $49 million.

See Note (B) to the Condensed Financial Statements under "Mississippi Power" herein for additional information.

Southern Power

During the nine months ended September 30, 2021, Southern Power completed construction of and placed in service 45 MWs of the 88-MW Garland battery energy storage facility and continued construction of the 72-MW Tranquillity battery energy storage facility, the 118-MW Glass Sands wind facility, and the remainder of the Garland battery energy storage facility. On March 26, 2021, Southern Power purchased a controlling membership interest in the approximately 300-MW Deuel Harvest wind facility located in Deuel County, South Dakota from Invenergy Renewables, LLC. See Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

At September 30, 2021, 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 93% through 2025 and 91% through 2030, with an average remaining contract duration of approximately 14 years.

Southern Company Gas

On April 28, 2021, Atlanta Gas Light filed its first Integrated Capacity and Delivery Plan (i-CDP) with the Georgia PSC, which includes a series of ongoing and proposed pipeline safety, reliability, and growth programs for the next 10 years, as well as the required capital investments and related costs to implement the programs. On October 14, 2021, Atlanta Gas Light and the staff of the Georgia PSC filed a joint stipulation agreement, under which, for the years 2022 through 2024, Atlanta Gas Light would incrementally reduce its combined GRAM and System Reinforcement Rider request by 10% through Atlanta Gas Light's GRAM mechanism, or $5 million for 2022 based on the initial July 21, 2021 GRAM filing, as discussed further below. The stipulation agreement also would provide for $1.7 billion of total capital investment for the years 2022 through 2024. The Georgia PSC is scheduled to vote on this matter later in November 2021. The ultimate outcome of this matter cannot be determined at this time.

On September 14, 2021, the Virginia Commission approved a stipulation agreement related to Virginia Natural Gas' June 2020 general rate case filing, which allows for a $43 million increase in annual base rate revenues, including $14 million related to the recovery of investments under the SAVE program, based on a ROE of 9.5% and an equity ratio of 51.9%. Interim rate adjustments became effective as of November 1, 2020, subject to refund, based on Virginia Natural Gas' original request for an increase of approximately $50 million.

On July 21, 2021, Atlanta Gas Light filed its annual GRAM filing with the Georgia PSC requesting an annual base rate increase of $49 million. Later in November 2021, Atlanta Gas Light expects to file an amended GRAM filing in accordance with the reduction agreed to in the October 14, 2021 joint stipulation agreement, as discussed above. Resolution of the GRAM filing is expected by December 31, 2021, with the new rates to become effective January 1, 2022. The ultimate outcome of this matter cannot be determined at this time.

See Note (B) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

On July 1, 2021, Southern Company Gas affiliates completed the sale of Sequent to Williams Field Services Group for a total cash purchase price of $159 million, including final working capital adjustments. The preliminary pre-tax gain associated with the transaction is approximately $121 million ($93 million after tax). As a result of the sale, changes in state apportionment rates resulted in $85 million of additional tax expense. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

During the second and third quarters of 2021, Southern Company Gas recorded pre-tax impairment charges totaling $84 million ($67 million after tax) related to its equity method investment in the PennEast Pipeline project. On September 27, 2021, PennEast Pipeline announced that further development of the project is no longer supported, and, as a result, all further development of the project has ceased. See Notes (C) and (E) to the Condensed Financial Statements herein under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, for additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

RESULTS OF OPERATIONS

Southern Company

Net Income

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(150)	(12.0)	$(124)	(4.5)

Consolidated net income attributable to Southern Company was $1.1 billion ($1.04 per share) for the third quarter 2021 compared to $1.3 billion ($1.18 per share) for the corresponding period in 2020. The decrease was primarily due to a $197 million after-tax charge in the third quarter 2021 related to the construction of Plant Vogtle Units 3 and 4 at Georgia Power and higher non-fuel operations and maintenance costs, partially offset by higher retail electric revenues driven by rates and pricing and sales growth.

Consolidated net income attributable to Southern Company was $2.6 billion ($2.46 per share) for year-to-date 2021 compared to $2.7 billion ($2.58 per share) for the corresponding period in 2020. The decrease was primarily due to a $465 million increase in after-tax charges related to the construction of Plant Vogtle Units 3 and 4 at Georgia Power and higher non-fuel operations and maintenance costs, partially offset by an increase in natural gas revenues associated with colder weather in the first quarter 2021 as compared to the corresponding period in 2020 and infrastructure replacement programs and base rate changes, higher retail electric revenues primarily associated with rates and pricing and sales growth, and higher wholesale electric capacity revenues.

Retail Electric Revenues

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$308	7.3	$989	9.4

In the third quarter 2021, retail electric revenues were $4.6 billion compared to $4.2 billion for the corresponding period in 2020. For year-to-date 2021, retail electric revenues were $11.5 billion compared to $10.5 billion for the corresponding period in 2020.

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

	Third Quarter 2021				Year-To-Date 2021
	(in millions)		(% change)		(in millions)		(% change)
Retail electric – prior year	$	4,243			$	10,503
Estimated change resulting from –
Rates and pricing	74		1.8	%	210		2.0	%
Sales growth	86		2.0		158		1.5
Weather	(95)		(2.2)		12		0.1
Fuel and other cost recovery	243		5.7		609		5.8
Retail electric – current year	$	4,551	7.3	%	$	11,492	9.4	%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2021 when compared to the corresponding periods in 2020. These increases were primarily due to an increase in Alabama Power's Rate RSE effective January 1, 2021 and increases at Georgia Power resulting from higher contributions by commercial and industrial customers with variable demand-driven pricing and fixed residential customer bill programs, partially offset by a decrease in the NCCR tariff effective January 1, 2021. The increase in the third quarter 2021 was also partially offset by pricing effects associated with decreased residential customer usage at

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AND RESULTS OF OPERATIONS (Continued)

Georgia Power. The increase for year-to-date 2021 also reflects increased ECCR tariff revenues at Georgia Power associated with higher KWH sales. See Note 2 to the financial statements under "Alabama Power – Rate RSE" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction – Regulatory Matters" herein for additional information.

Revenues attributable to changes in sales increased in the third quarter and year-to-date 2021 when compared to the corresponding periods in 2020. Weather-adjusted residential KWH sales increased 0.5% in the third quarter 2021 when compared to the corresponding period in 2020 primarily due to customer growth, largely offset by decreased customer usage primarily due to shelter-in-place orders in effect during 2020. Weather-adjusted residential KWH sales decreased 0.1% for year-to-date 2021 when compared to the corresponding period in 2020 primarily due to decreased customer usage resulting from shelter-in-place orders in effect during 2020, partially offset by customer growth. Weather-adjusted commercial KWH sales increased 4.2% and 3.3% in the third quarter and year-to-date 2021, respectively, and industrial KWH sales increased 4.8% and 4.3% in the third quarter and year-to-date 2021, respectively, when compared to the corresponding periods in 2020, primarily due to the negative impacts of the COVID-19 pandemic on energy sales in 2020.

Fuel and other cost recovery revenues increased $243 million and $609 million in the third quarter and year-to-date 2021, respectively, compared to the corresponding periods in 2020 primarily due to higher fuel and purchased power costs. 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 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$147	25.2	$349	23.7

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 2021, wholesale electric revenues were $731 million compared to $584 million for the corresponding period in 2020. For year-to-date 2021, wholesale electric revenues were $1.8 billion compared to $1.5 billion for the corresponding period in 2020. Increases in energy revenues of $132 million and $285 million for the third quarter and year-to-date 2021, respectively, reflect higher natural gas prices when compared to the corresponding periods in 2020. In addition, increases in capacity revenues of $15 million and $64 million for the third quarter and year-to-date 2021, respectively, primarily resulted from a power sales agreement at Alabama Power that began in September 2020 and increased capacity sales under existing contracts at Southern Power.

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Other Electric Revenues

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$15	9.1	$41	8.5

For year-to-date 2021, other electric revenues were $525 million compared to $484 million for the corresponding period in 2020. The increase was primarily due to increases of $25 million in customer fees largely resulting from the COVID-19 pandemic-related temporary suspensions of disconnections and late fees in 2020 for the traditional electric operating companies, $12 million in transmission revenues, and $8 million related to outdoor lighting sales at Georgia Power.

Natural Gas Revenues

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$146	30.6	$632	26.8

In the third quarter 2021, natural gas revenues were $623 million compared to $477 million for the corresponding period in 2020. For year-to-date 2021, natural gas revenues were $3.0 billion compared to $2.4 billion for the corresponding period in 2020.

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

	Third Quarter 2021				Year-To-Date 2021
	(in millions)		(% change)		(in millions)		(% change)
Natural gas revenues – prior year	$	477			$	2,362
Estimated change resulting from –
Infrastructure replacement programs and base rate changes	28		5.9	%	109		4.6	%
Gas costs and other cost recovery	54		11.3		294		12.5
Wholesale gas services	51		10.7		207		8.8
Other	13		2.7		22		0.9
Natural gas revenues – current year	$	623	30.6	%	$	2,994	26.8	%

Revenues from infrastructure replacement programs and base rate changes at the natural gas distribution utilities increased in the third quarter and year-to-date 2021 compared to the corresponding periods in 2020 primarily due to rate increases at Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas and continued investment in infrastructure replacement. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K for additional information.

Revenues associated with gas costs and other cost recovery increased in the third quarter and year-to-date 2021 compared to the corresponding periods in 2020 primarily due to higher volumes of natural gas sold and higher natural gas cost recovery. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities.

For the third quarter 2021, the change in revenues related to Southern Company Gas' wholesale gas services was due to the sale of Sequent on July 1, 2021. The year-to-date 2021 change reflects higher volumes of natural gas sold and higher commercial activities as a result of Winter Storm Uri, partially offset by derivative losses all prior to the sale of Sequent on July 1, 2021. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

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AND RESULTS OF OPERATIONS (Continued)

Other Revenues

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$2	1.3	$77	17.7

For year-to-date 2021, other revenues were $513 million compared to $436 million for the corresponding period in 2020. The increase was primarily due to increases of $42 million in unregulated sales of products and services at Alabama Power and Georgia Power and $26 million related to distributed infrastructure and energy efficiency projects at PowerSecure.

Fuel and Purchased Power Expenses

	Third Quarter 2021 vs. Third Quarter 2020			Year-To-Date 2021 vs. Year-To-Date 2020
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	301	32.3	$	740	33.8
Purchased power	58		25.2	101		16.5
Total fuel and purchased power expenses	$	359		$	841

In the third quarter 2021, total fuel and purchased power expenses were $1.5 billion compared to $1.2 billion for the corresponding period in 2020. The increase was primarily the result of a $370 million increase in the average cost of fuel and purchased power and an $11 million net decrease in the volume of KWHs generated and purchased.

For year-to-date 2021, total fuel and purchased power expenses were $3.6 billion compared to $2.8 billion for the corresponding period in 2020. The increase was primarily the result of a $690 million increase in the average cost of fuel and purchased power and a $151 million net increase in the volume of KWHs generated and purchased.

Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See Note 2 to the financial statements in Item 8 of the Form 10-K for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.

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AND RESULTS OF OPERATIONS (Continued)

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

	Third Quarter 2021	Third Quarter 2020	Year-To-Date 2021	Year-To-Date 2020
Total generation (in billions of KWHs)(a)	50	50	136	132
Total purchased power (in billions of KWHs)	5	5	13	14
Sources of generation (percent)(a) —
Gas	48	52	47	53
Coal	26	24	24	17
Nuclear	16	16	17	17
Hydro	3	2	4	5
Wind, Solar, and Other	7	6	8	8
Cost of fuel, generated (in cents per net KWH)—
Gas(a)	3.38	1.98	2.87	1.94
Coal	2.82	3.01	2.84	2.96
Nuclear	0.78	0.78	0.76	0.78
Average cost of fuel, generated (in cents per net KWH)(a)	2.75	2.04	2.45	1.91
Average cost of purchased power (in cents per net KWH)(b)	6.45	4.94	5.77	4.53

(a)Third quarter and year-to-date 2021 excludes Central Alabama Generating Station KWHs and associated cost of fuel as its fuel is provided by the purchaser under a power sales agreement. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.

(b)Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.

Fuel

In the third quarter 2021, fuel expense was $1.2 billion compared to $933 million for the corresponding period in 2020. The increase was primarily due to a 70.7% increase in the average cost of natural gas per KWH generated and a 9.1% increase in the volume of KWHs generated by coal, partially offset by a 91.2% increase in the volume of KWHs generated by hydro, a 6.3% decrease in the average cost of coal per KWH generated, and a 9.4% decrease in the volume of KWHs generated by natural gas.

For year-to-date 2021, fuel expense was $2.9 billion compared to $2.2 billion for the corresponding period in 2020. The increase was primarily due to a 47.9% increase in the average cost of natural gas per KWH generated, a 43.7% increase in the volume of KWHs generated by coal, and an 11.3% decrease in the volume of KWHs generated by hydro, partially offset by a 9.1% decrease in the volume of KWHs generated by natural gas and a 4.1% decrease in the average cost of coal per KWH generated.

Purchased Power

In the third quarter 2021, purchased power expense was $288 million compared to $230 million for the corresponding period in 2020. The increase was primarily due to a 30.6% increase in the average cost per KWH purchased primarily due to higher natural gas prices.

For year-to-date 2021, purchased power expense was $712 million compared to $611 million for the corresponding period in 2020. The increase was primarily due to a 27.4% increase in the average cost per KWH purchased primarily due to higher natural gas prices, partially offset by a 3.8% decrease in the volume of KWHs purchased.

Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.

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AND RESULTS OF OPERATIONS (Continued)

Cost of Natural Gas

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$58	81.7	$289	44.2

Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. Cost of natural gas at the natural gas distribution utilities represented 78% and 85% of total cost of natural gas for the third quarter and year-to-date 2021, respectively.

In the third quarter 2021, cost of natural gas was $129 million compared to $71 million for the corresponding period in 2020. The increase reflects higher gas cost recovery driven by a 103% increase in natural gas prices in the third quarter 2021 compared to the corresponding period in 2020.

For year-to-date 2021, cost of natural gas was $943 million compared to $654 million for the corresponding period in 2020. The increase reflects higher volumes sold due to colder weather and higher gas cost recovery for year-to-date 2021 compared to the corresponding period in 2020. The increase also reflects a 69% increase in natural gas prices for year-to-date 2021 compared to the corresponding period in 2020.

Cost of Other Sales

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(1)	(1.4)	$54	26.9

For year-to-date 2021, cost of other sales was $255 million compared to $201 million for the corresponding period in 2020. The increase primarily relates to increases of $24 million in unregulated power delivery construction and maintenance projects at Georgia Power and $19 million related to distributed infrastructure and energy efficiency projects at PowerSecure.

Other Operations and Maintenance Expenses

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$160	12.4	$472	12.5

In the third quarter 2021, other operations and maintenance expenses were $1.4 billion compared to $1.3 billion for the corresponding period in 2020. The increase reflects the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. The increase was primarily associated with increases of $70 million in transmission and distribution expenses, including $9 million of reliability NDR credits applied in 2020 at Alabama Power, and $18 million in scheduled generation outage and maintenance expenses. Also contributing to the increase was a $15 million loss on a sales-type lease at Southern Power, which was recorded upon commencement of the Garland battery energy storage facility PPA, and an increase of $14 million in compensation and benefit expenses.

For year-to-date 2021, other operations and maintenance expenses were $4.3 billion compared to $3.8 billion for the corresponding period in 2020. The increase reflects the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. The increase was primarily associated with increases of $122 million in transmission and distribution expenses, including $31 million of reliability NDR credits applied in 2020 at Alabama Power, and $115 million in compensation and benefit expenses, primarily associated with incentive compensation at Southern Company Gas prior to the sale of Sequent, as well as increases in pension and medical costs. Also contributing to the increase was a $76 million increase in scheduled generation outage and maintenance expenses, a

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AND RESULTS OF OPERATIONS (Continued)

$19 million increase in compliance and environmental expenses at the traditional electric operating companies, an $18 million decrease in nuclear property insurance refunds, and a $15 million loss on a sales-type lease at Southern Power, which was recorded upon commencement of the Garland battery energy storage facility PPA.

Depreciation and Amortization

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$7	0.8	$39	1.5

In the third quarter 2021, depreciation and amortization was $896 million compared to $889 million for the corresponding period in 2020. For year-to-date 2021, depreciation and amortization was $2.7 billion compared to $2.6 billion for the corresponding period in 2020. The increases for the third quarter and year-to-date 2021 primarily reflect increases of $34 million and $113 million, respectively, in depreciation associated with additional plant in service, partially offset by decreased amortization of regulatory assets related to CCR AROs of $22 million and $66 million, respectively, under the terms of Georgia Power's 2019 ARP. See Note (B) to the Condensed Financial Statements under "Georgia Power – Rate Plan" herein and Note 2 to the financial statements under "Georgia Power – Rate Plans – 2019 ARP" in Item 8 of the Form 10-K for additional information regarding Georgia Power's recovery of costs associated with CCR AROs.

Taxes Other Than Income Taxes

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$8	2.6	$37	4.0

For year-to-date 2021, taxes other than income taxes were $969 million compared to $932 million for the corresponding period in 2020. The increase primarily reflects increases of $24 million in property taxes primarily resulting from higher assessed values and $11 million in revenue tax expenses as a result of higher natural gas revenues at Southern Company Gas.

Estimated Loss on Plant Vogtle Units 3 and 4

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$264	N/M	$623	N/M

N/M - Not meaningful

In the third quarter 2021, Georgia Power recorded an estimated probable loss on Plant Vogtle Units 3 and 4 of $264 million. For year-to-date 2021 and 2020, estimated probable losses on Plant Vogtle Units 3 and 4 of $772 million and $149 million, respectively, were recorded at Georgia Power. These losses reflect revisions to the total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.

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AND RESULTS OF OPERATIONS (Continued)

(Gain) Loss on Dispositions, Net

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$125	N/M	$140	N/M

N/M - Not meaningful

In the third quarter 2021, gain on dispositions, net was $125 million compared to an immaterial gain for the corresponding period in 2020. For year-to-date 2021, gain on dispositions, net was $179 million compared to $39 million for the corresponding period in 2020. The increases primarily reflect a $121 million gain at Southern Company Gas related to the sale of Sequent in the third quarter 2021. The year-to-date 2021 increase also reflects $39 million in gains at Southern Power primarily from contributions of wind turbine equipment to various equity method investments in the first quarter 2021 and $13 million in gains at Alabama Power primarily from property sales, partially offset by a $39 million gain at Southern Power related to the sale of Plant Mankato in the first quarter 2020.

See Note (E) to the Condensed Financial Statements under "Southern Power" herein, Note (K) to the Condensed Financial Statements under "Southern Power" and "Southern Company Gas" 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.

Allowance for Equity Funds Used During Construction

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$11	28.9	$34	32.1

In the third quarter 2021, allowance for equity funds used during construction was $49 million compared to $38 million for the corresponding period in 2020. For year-to-date 2021, allowance for equity funds used during construction was $140 million compared to $106 million for the corresponding period in 2020. The increases were primarily associated with Georgia Power's construction of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

Earnings from Equity Method Investments

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(3)	(9.1)	$(70)	(66.7)

For year-to-date 2021, earnings from equity method investments were $35 million compared to $105 million for the corresponding period in 2020. The decrease was primarily due to pre-tax impairment charges totaling $84 million at Southern Company Gas related to the PennEast Pipeline project, partially offset by a $22 million increase in investment income at Southern Holdings. See Notes (C) and (E) to the Condensed Financial Statements herein under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, for additional information.

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AND RESULTS OF OPERATIONS (Continued)

Impairment of Leveraged Leases

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$—	N/M	$(147)	(95.5)

N/M - Not meaningful

For year-to-date 2020, impairment charges of $154 million were recorded related to leveraged lease investments at Southern Holdings. See Note (K) to the Condensed Financial Statements under "Southern Company" and "Assets Held for Sale" herein and Note 3 to the financial statements under "Other Matters – Southern Company" in Item 8 of the Form 10-K for additional information.

Other Income (Expense), Net

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$18	15.9	$(22)	(6.9)

In the third quarter 2021, other income (expense), net was $131 million compared to $113 million for the corresponding period in 2020. The increase was primarily due to a $36 million increase in non-service cost-related retirement benefits income, partially offset by a $12 million gain recorded by Southern Power in the third quarter 2020 associated with the Roserock solar facility litigation.

For year-to-date 2021, other income (expense), net was $297 million compared to $319 million for the corresponding period in 2020. The decrease was primarily due to $101 million in charitable contributions at Southern Company Gas in the second quarter 2021, a $14 million decrease in interest income, and a $12 million gain recorded by Southern Power in the third quarter 2020 associated with the Roserock solar facility litigation, largely offset by a $107 million increase in non-service cost-related retirement benefits income.

See Note (H) to the Condensed Financial Statements herein for additional information.

Income Taxes

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$79	27.0	$107	24.2

In the third quarter 2021, income taxes were $372 million compared to $293 million for the corresponding period in 2020. For year-to-date 2021, income taxes were $550 million compared to $443 million for the corresponding period in 2020. The increases were primarily due to $85 million in additional tax expense resulting from changes in state apportionment rates as a result of Southern Company Gas' sale of Sequent in the third quarter 2021 and a $30 million increase in a valuation allowance on certain state tax credit carryforwards at Georgia Power, partially offset by lower pre-tax earnings primarily resulting from higher charges in 2021 compared to the corresponding periods in 2020 associated with the construction of Plant Vogtle Units 3 and 4 at Georgia Power. The increase for year-to-date 2021 also reflects the tax impact of the second quarter 2020 charge to earnings associated with a leveraged lease investment.

See Notes (G) and (K) to the Condensed Financial Statements herein and Note 3 to the financial statements under "Other Matters – Southern Company" in Item 8 of the Form 10-K for additional information.

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AND RESULTS OF OPERATIONS (Continued)

Net Income (Loss) Attributable to Noncontrolling Interests

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(23)	(82.1)	$(30)	N/M

N/M - Not meaningful

Substantially all noncontrolling interests relate to renewable projects at Southern Power. In the third quarter 2021, net income attributable to noncontrolling interests was $5 million compared to $28 million for the corresponding period in 2020. For year-to-date 2021, net loss attributable to noncontrolling interests was $27 million compared to net income of $3 million for the corresponding period in 2020. These changes were primarily due to loss allocations of $13 million related to the commencement of the Garland battery energy storage facility PPA in the third quarter 2021 and lower income allocations to solar equity partners and higher HLBV loss allocations to Southern Power's wind tax equity partners, including new partnerships entered into subsequent to the third quarter 2020, totaling $10 million and $16 million for the third quarter and year-to-date 2021, respectively. See Notes (D) and (K) to the Condensed Financial Statements under "Lease Receivables" and "Southern Power," respectively, herein for additional information.

Alabama Power

Net Income

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$55	12.4	$167	16.3

Alabama Power's net income after dividends on preferred stock for the third quarter 2021 was $499 million compared to $444 million for the corresponding period in 2020. Alabama Power's net income after dividends on preferred stock for year-to-date 2021 was $1.19 billion compared to $1.02 billion for the corresponding period in 2020. The increases were primarily due to an increase in retail revenues associated with a Rate RSE adjustment effective in January 2021 and higher customer usage. Also contributing to the increases were increased sales of unregulated products and services and additional wholesale capacity revenues related to a power sales agreement that began in September 2020. The third quarter 2021 increase was partially offset by a decrease in revenues associated with milder weather in the third quarter 2021 compared to the corresponding period in 2020. Additionally, the third quarter and year-to-date 2021 increases were partially offset by an increase in operations and maintenance expenses and depreciation.

Retail Revenues

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$76	4.8	$354	8.8

In the third quarter 2021, retail revenues were $1.65 billion compared to $1.58 billion for the corresponding period in 2020. For year-to-date 2021, retail revenues were $4.36 billion compared to $4.00 billion for the corresponding period in 2020.

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AND RESULTS OF OPERATIONS (Continued)

Details of the changes in retail revenues were as follows:

	Third Quarter 2021				Year-To-Date 2021
	(in millions)		(% change)		(in millions)		(% change)
Retail – prior year	$	1,575			$	4,003
Estimated change resulting from –
Rates and pricing	57		3.6	%	172		4.3	%
Sales growth	30		1.9		43		1.1
Weather	(28)		(1.8)		14		0.3
Fuel and other cost recovery	17		1.1		125		3.1
Retail – current year	$	1,651	4.8	%	$	4,357	8.8	%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2021 when compared to the corresponding periods in 2020 primarily due to a Rate RSE increase effective January 1, 2021. See Note 2 to the financial statements under "Alabama Power – Rate RSE" in Item 8 of the Form 10-K for additional information.

Revenues attributable to changes in sales increased in the third quarter and year-to-date 2021 when compared to the corresponding periods in 2020. Weather-adjusted residential KWH sales decreased 0.1% and 1.3% in the third quarter and year-to-date 2021, respectively, when compared to the corresponding periods in 2020 primarily due to safer-at-home guidelines in effect during 2020. Weather-adjusted commercial KWH sales increased 3.3% and 3.0% in the third quarter and year-to-date 2021, respectively, and industrial KWH sales increased 4.6% and 2.7% in the third quarter and year-to-date 2021, respectively, when compared to the corresponding periods in 2020, primarily due to the negative impacts of the COVID-19 pandemic on energy sales in 2020.

Fuel and other cost recovery revenues increased in the third quarter and year-to-date 2021 when compared to the corresponding periods in 2020 primarily due to increases 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 NDR. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.

Wholesale Revenues – Non-Affiliates

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$34	46.6	$101	54.9

Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Alabama Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not affect net income. Short-term opportunity energy sales are also included in wholesale energy sales to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above Alabama Power's variable cost to produce the energy.

In the third quarter 2021, wholesale revenues from sales to non-affiliates were $107 million compared to $73 million for the corresponding period in 2020. For year-to-date 2021, wholesale revenues from sales to non-affiliates were $285 million compared to $184 million for the corresponding period in 2020. The third quarter and year-to-date 2021 increases consisted of increases in capacity revenues of $12 million and $47 million, respectively, primarily related to a power sales agreement that began in September 2020 and increases in energy revenues of $22 million and $54 million, respectively, primarily due to higher natural gas prices.

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Wholesale Revenues – Affiliates

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$42	381.8	$73	202.8

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

In the third quarter 2021, wholesale revenues from sales to affiliates were $53 million compared to $11 million for the corresponding period in 2020. For year-to-date 2021, wholesale revenues from sales to affiliates were $109 million compared to $36 million for the corresponding period in 2020. The third quarter and year-to-date 2021 increases were primarily due to increases of 186.2% and 85.4%, respectively, in KWH sales due to increased demand for Alabama Power's available lower cost generation compared to the corresponding periods in 2020 and increases of 73.2% and 61.0%, respectively, in the price of energy as a result of higher natural gas prices.

Other Revenues

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$23	32.9	$46	20.7

In the third quarter 2021, other revenues were $93 million compared to $70 million for the corresponding period in 2020. For year-to-date 2021, other revenues were $268 million compared to $222 million for the corresponding period in 2020. The third quarter and year-to-date 2021 increases were primarily due to increases of $10 million and $25 million, respectively, in unregulated sales of products and services, increases of $5 million and $11 million, respectively, in customer fees largely resulting from the COVID-19 pandemic-related temporary suspensions of disconnections and late fees in 2020, and increases of $4 million and $7 million, respectively, in cogeneration steam revenue associated with higher natural gas prices. In addition, the third quarter 2021 increase included a $4 million increase in transmission revenues.

Fuel and Purchased Power Expenses

	Third Quarter 2021 vs. Third Quarter 2020			Year-To-Date 2021 vs. Year-To-Date 2020
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	67	21.9	$	206	28.6
Purchased power – non-affiliates	12		18.8	20		13.1
Purchased power – affiliates	1		2.3	21		22.6
Total fuel and purchased power expenses	$	80		$	247

In the third quarter 2021, total fuel and purchased power expenses were $494 million compared to $414 million for the corresponding period in 2020. The increase was primarily due to an $85 million increase in the average cost of fuel and purchased power, partially offset by a $5 million net decrease related to the volume of KWHs generated and purchased.

For year-to-date 2021, total fuel and purchased power expenses were $1.21 billion compared to $0.97 billion for the corresponding period in 2020. The increase was primarily due to a $151 million increase in the average cost of fuel and purchased power and a $96 million net increase related to the volume of KWHs generated and purchased.

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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 2021	Third Quarter 2020	Year-To-Date 2021	Year-To-Date 2020
Total generation (in billions of KWHs)(a)	16	15	45	41
Total purchased power (in billions of KWHs)	2	2	5	5
Sources of generation (percent)(a) —
Coal	50	47	47	38
Nuclear	24	25	25	28
Gas	18	24	19	23
Hydro	8	4	9	11
Cost of fuel, generated (in cents per net KWH) —
Coal	2.85	2.86	2.78	2.78
Nuclear	0.73	0.76	0.71	0.76
Gas(a)	3.03	1.80	2.68	1.96
Average cost of fuel, generated (in cents per net KWH)(a)	2.33	2.04	2.20	1.93
Average cost of purchased power (in cents per net KWH)(b)	7.96	5.12	6.70	4.76

(a)Third quarter and year-to-date 2021 excludes Central Alabama Generating Station KWHs and associated cost of fuel as its fuel is provided by the purchaser under a power sales agreement. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.

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

Fuel

In the third quarter 2021, fuel expense was $373 million compared to $306 million for the corresponding period in 2020. The increase was primarily due to a 68.3% increase in the average cost of natural gas per KWH generated, which excludes tolling agreements, and a 15.9% increase in the volume of KWHs generated by coal, partially offset by a 121.6% increase in the volume of KWHs generated by hydro and a 19.8% decrease in the volume of KWHs generated by natural gas.

For year-to-date 2021, fuel expense was $927 million compared to $721 million for the corresponding period in 2020. The increase was primarily due to a 36.7% increase in the average cost of natural gas per KWH generated, which excludes tolling agreements, a 31.7% increase in the volume of KWHs generated by coal, and an 8.1% decrease in the volume of KWHs generated by hydro, partially offset by a 9.3% decrease in the volume of KWHs generated by natural gas.

Purchased Power – Non-Affiliates

In the third quarter 2021, purchased power expense from non-affiliates was $76 million compared to $64 million for the corresponding period in 2020. For year-to-date 2021, purchased power expense from non-affiliates was $173 million compared to $153 million for the corresponding period in 2020. These increases for the third quarter and year-to-date 2021 were primarily due to increases of 20.6% and 16.1%, respectively, in the amount of energy purchased due to a new PPA that began in September 2020 and increases of 12.3% and 14.0%, respectively, in the average cost of purchased power per KWH as a result of higher natural gas prices.

Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.

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Purchased Power – Affiliates

For year-to-date 2021, purchased power expense from affiliates was $114 million compared to $93 million for the corresponding period in 2020. The year-to-date 2021 increase was primarily due to an 88.0% increase in the average cost of purchased power per KWH as a result of higher natural gas prices, partially offset by a 35.0% decrease in the volume of KWH purchased as a result of increased generation compared to the corresponding period in 2020.

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

Other Operations and Maintenance Expenses

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$14	3.6	$97	9.0

In the third quarter 2021, other operations and maintenance expenses were $401 million compared to $387 million for the corresponding period in 2020. For year-to-date 2021, other operations and maintenance expenses were $1.18 billion compared to $1.08 billion for the corresponding period in 2020. The increases reflect the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. The third quarter and year-to-date 2021 increases were primarily due to increases of $15 million and $49 million, respectively, in generation expenses associated with scheduled outages and Rate CNP Compliance-related expenses primarily related to the addition of new environmental systems in 2021. Also contributing to the third quarter and year-to-date 2021 increases were increases of $6 million and $23 million, respectively, in compensation and benefit expenses and $3 million and $10 million, respectively, related to unregulated services, as well as $9 million and $31 million, respectively, in transmission and distribution line maintenance expenses related to reliability NDR credits applied in 2020. The third quarter and year-to-date 2021 increases were partially offset by decreases of $22 million and $30 million, respectively, in bad debt expenses. 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.

Depreciation and Amortization

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$9	4.4	$34	5.6

In the third quarter 2021, depreciation and amortization was $214 million compared to $205 million in the corresponding period in 2020. For year-to-date 2021, depreciation and amortization was $640 million compared to $606 million for the corresponding period in 2020. These increases were primarily due to additional plant in service, including the purchase of the Central Alabama Generating Station in August 2020. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.

Other Income (Expense), Net

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(1)	(3.3)	$15	19.2

For year-to-date 2021, other income (expense), net was $93 million compared to $78 million for the corresponding period in 2020. The increase was 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.

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Income Taxes

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$22	16.9	$59	19.2

In the third quarter 2021, income taxes were $152 million compared to $130 million for the corresponding period in 2020. For year-to-date 2021, income taxes were $366 million compared to $307 million for the corresponding period in 2020. The increases were primarily due to higher pre-tax earnings.

Georgia Power

Net Income

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(237)	(30.7)	$(381)	(27.0)

Georgia Power's net income for the third quarter 2021 was $536 million compared to $773 million for the corresponding period in 2020. The decrease was primarily due to a $197 million after-tax charge in the third quarter 2021 related to the construction of Plant Vogtle Units 3 and 4, higher non-fuel operations and maintenance costs, and lower retail revenues associated with milder weather in the third quarter 2021 as compared to the corresponding period in 2020, partially offset by sales growth.

For year-to-date 2021, net income was $1.03 billion compared to $1.41 billion for the corresponding period in 2020. The decrease was primarily due to a $465 million increase in after-tax charges related to the construction of Plant Vogtle Units 3 and 4. Also contributing to the decrease were higher non-fuel operations and maintenance costs, partially offset by higher retail revenues associated with sales growth.

See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

Retail Revenues

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$217	8.9	$595	10.1

In the third quarter 2021, retail revenues were $2.65 billion compared to $2.44 billion for the corresponding period in 2020. For year-to-date 2021, retail revenues were $6.47 billion compared to $5.87 billion for the corresponding period in 2020.

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Details of the changes in retail revenues were as follows:

	Third Quarter 2021				Year-To-Date 2021
	(in millions)		(% change)		(in millions)		(% change)
Retail – prior year	$	2,435			$	5,870
Estimated change resulting from –
Rates and pricing	10		0.4	%	30		0.5	%
Sales growth	51		2.1		110		1.9
Weather	(63)		(2.6)		(4)		(0.1)
Fuel cost recovery	219		9.0		459		7.8
Retail – current year	$	2,652	8.9	%	$	6,465	10.1	%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2021 when compared to the corresponding periods in 2020. The increases were primarily due to higher contributions from commercial and industrial customers with variable demand-driven pricing and fixed residential customer bill programs, partially offset by a decrease in the NCCR tariff effective January 1, 2021. The increase in the third quarter 2021 was also partially offset by pricing effects associated with decreased residential customer usage. The increase for year-to-date 2021 also reflects increased ECCR tariff revenues associated with higher KWH sales. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction – Regulatory Matters" herein for additional information.

Revenues attributable to changes in sales increased in the third quarter and year-to-date 2021 when compared to the corresponding periods in 2020. Weather-adjusted residential KWH sales increased 0.7% in both the third quarter and year-to-date 2021 when compared to the corresponding periods in 2020 primarily due to customer growth, largely offset by decreased customer usage, primarily due to shelter-in-place orders in effect during 2020. Weather-adjusted commercial KWH sales increased 4.8% and 3.4% in the third quarter and year-to-date 2021, respectively, and weather-adjusted industrial KWH sales increased 5.5% and 6.7% in the third quarter and year-to-date 2021, respectively, when compared to the corresponding periods in 2020, primarily due to the negative impacts of the COVID-19 pandemic on energy sales in 2020.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased in the third quarter and year-to-date 2021 when compared to the corresponding periods in 2020 due to higher fuel and purchased power costs. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Georgia Power – Fuel Cost Recovery" for additional information.

Wholesale Revenues

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$29	85.3	$58	68.2

Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Wholesale capacity revenues from PPAs are recognized in amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are

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accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.

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

In the third quarter 2021, wholesale revenues were $63 million compared to $34 million for the corresponding period in 2020. For year-to-date 2021, wholesale revenues were $143 million compared to $85 million for the corresponding period in 2020. The increases for the third quarter and year-to-date 2021 were primarily due to increases of 25.1% and 15.1%, respectively, in KWH sales as a result of higher market demand and higher natural gas prices.

Other Revenues

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(7)	(4.7)	$26	6.3

For year-to-date 2021, other revenues were $442 million compared to $416 million for the corresponding period in 2020. The increase for year-to-date 2021 was primarily due to increases of $37 million in unregulated sales associated with power delivery construction and maintenance projects and outdoor lighting and $13 million in customer fees largely resulting from the COVID-19 pandemic-related temporary suspension of disconnections and late fees in 2020. These increases were partially offset by decreases of $11 million associated with the timing of certain unregulated energy conservation projects, $4 million in pole attachment revenues, and $3 million in solar application fees.

Fuel and Purchased Power Expenses

	Third Quarter 2021 vs. Third Quarter 2020			Year-To-Date 2021 vs. Year-To-Date 2020
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	64	17.4	$	262	31.7
Purchased power – non-affiliates	27		18.5	52		12.7
Purchased power – affiliates	146		102.8	180		45.8
Total fuel and purchased power expenses	$	237		$	494

In the third quarter 2021, total fuel and purchased power expenses were $893 million compared to $656 million for the corresponding period in 2020. For year-to-date 2021, total fuel and purchased power expenses were $2.12 billion compared to $1.63 billion for the corresponding period in 2020. The increases for the third quarter and year-to-date 2021 were due to increases of $206 million and $409 million, respectively, related to the average cost of fuel and purchased power and net increases of $31 million and $85 million, respectively, related to the volume of KWHs generated and purchased.

Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through Georgia Power's fuel cost recovery mechanism. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Georgia Power – Fuel Cost Recovery" for additional information.

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

	Third Quarter 2021	Third Quarter 2020	Year-To-Date 2021	Year-To-Date 2020
Total generation (in billions of KWHs)	16	17	46	42
Total purchased power (in billions of KWHs)	10	8	23	25
Sources of generation (percent) —
Gas	45	48	46	53
Nuclear	24	24	26	27
Coal	28	26	24	15
Hydro and solar	3	2	4	5
Cost of fuel, generated (in cents per net KWH) —
Gas	3.28	2.14	2.84	2.12
Nuclear	0.83	0.81	0.80	0.81
Coal	2.73	3.19	2.89	3.31
Average cost of fuel, generated (in cents per net KWH)	2.51	2.09	2.30	1.93
Average cost of purchased power (in cents per net KWH)(*)	5.24	3.76	4.80	3.50

(*)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 2021, fuel expense was $432 million compared to $368 million for the corresponding period in 2020. For year-to-date 2021, fuel expense was $1.09 billion compared to $0.83 billion for the corresponding period in 2020. The increases for the third quarter and year-to-date 2021 were primarily due to increases of 53.3% and 34.0%, respectively, in the average cost of natural gas per KWH generated, partially offset by decreases of 14.4% and 12.7%, respectively, in the average cost of coal per KWH generated and decreases of 11.1% and 6.0%, respectively, in the volume of KWHs generated by natural gas. Also contributing to the increase for year-to-date 2021 was a 76.1% increase in the volume of KWHs generated by coal.

Purchased Power – Non-Affiliates

In the third quarter 2021, purchased power expense from non-affiliates was $173 million compared to $146 million in the corresponding period in 2020. For year-to-date 2021, purchased power expense from non-affiliates was $461 million compared to $409 million in the corresponding period in 2020. The increases for the third quarter and year-to-date 2021 were primarily due to increases of 28.5% and 24.2%, respectively, in the average cost per KWH purchased primarily due to higher natural gas prices, partially offset by decreases of 5.6% and 7.7%, respectively, in the volume of KWHs purchased as Georgia Power units and Southern Company system resources generally dispatched at a lower cost than available market resources.

Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.

Purchased Power – Affiliates

In the third quarter 2021, purchased power expense from affiliates was $288 million compared to $142 million in the corresponding period in 2020. For year-to-date 2021, purchased power expense from affiliates was $573 million compared to $393 million in the corresponding period in 2020. The increases for the third quarter and year-to-date 2021 were primarily due to increases of 113.4% and 68.0%, respectively, in the average cost per KWH purchased

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primarily due to higher natural gas prices. Also contributing to the increase for the third quarter 2021 was an increase of 26.9% in the volume of KWHs purchased due to lower cost Southern Company system resources as compared to available Georgia Power-owned generation.

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

Other Operations and Maintenance Expenses

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$61	12.6	$147	10.4

In the third quarter 2021, other operations and maintenance expenses were $544 million compared to $483 million for the corresponding period in 2020. For year-to-date 2021, other operations and maintenance expenses were $1.56 billion compared to $1.41 billion for the corresponding period in 2020. These increases reflect the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. The increases for the third quarter and year-to-date 2021 were primarily associated with increases of $37 million and $68 million, respectively, in transmission and distribution vegetation and asset management activities, $8 million and $14 million, respectively, in generation expenses associated with non-outage maintenance costs and environmental projects, and $5 million and $24 million, respectively, in certain compensation and benefit expenses. Also contributing to the increase for year-to-date 2021 was a net increase of $12 million related to unregulated power delivery construction and maintenance projects and energy conservation projects as well as an $8 million decrease in nuclear property insurance refunds.

Depreciation and Amortization

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(13)	(3.6)	$(39)	(3.7)

In the third quarter 2021, depreciation and amortization was $345 million compared to $358 million for the corresponding period in 2020. For year-to-date 2021, depreciation and amortization was $1.03 billion compared to $1.06 billion for the corresponding period in 2020. The decreases for the third quarter and year-to-date 2021 primarily reflect decreased amortization of regulatory assets related to CCR AROs of $22 million and $66 million, respectively, under the terms of the 2019 ARP, partially offset by increases of $10 million and $30 million, respectively, in depreciation associated with additional plant in service. See Note (B) to the Condensed Financial Statements under "Georgia Power – Rate Plan" herein and Note 2 to the financial statements under "Georgia Power – Rate Plans – 2019 ARP" in Item 8 of the Form 10-K for additional information regarding recovery of costs associated with CCR AROs.

Taxes Other Than Income Taxes

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$7	5.7	$21	6.1

In the third quarter 2021, taxes other than income taxes was $130 million compared to $123 million for the corresponding period in 2020. For year-to-date 2021, taxes other than income taxes was $365 million compared to $344 million for the corresponding period in 2020. The increases for the third quarter and year-to-date 2021 were primarily due to increases of $5 million and $14 million, respectively, in municipal franchise fees largely related to

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higher retail revenues and increases of $2 million and $9 million, respectively, in property taxes primarily resulting from an increase in the assessed value of property.

Estimated Loss on Plant Vogtle Units 3 and 4

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$264	N/M	$623	N/M

N/M - Not meaningful

In the third quarter 2021, Georgia Power recorded an estimated probable loss on Plant Vogtle Units 3 and 4 of $264 million. For year-to-date 2021 and 2020, Georgia Power recorded estimated probable losses on Plant Vogtle Units 3 and 4 of $772 million and $149 million, respectively. These losses reflect revisions to the total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.

Allowance for Equity Funds Used During Construction

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$11	50.0	$31	49.2

In the third quarter 2021, allowance for equity funds used during construction was $33 million compared to $22 million for the corresponding period in 2020. For year-to-date 2021, allowance for equity funds used during construction was $94 million compared to $63 million for the corresponding period in 2020. The increases were primarily related to a higher AFUDC base largely associated with the construction of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

Other Income (Expense), Net

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$10	31.3	$31	33.3

In the third quarter 2021, other income (expense), net was $42 million compared to $32 million for the corresponding period in 2020. For year-to-date 2021, other income (expense), net was $124 million compared to $93 million for the corresponding period in 2020. The increases were primarily due to increases of $12 million and $37 million, respectively, in non-service cost-related retirement benefits income. The increase for year-to-date 2021 was partially offset by a $5 million decrease in interest income due to lower short-term cash investments. See Note (H) to the Condensed Financial Statements herein for additional information on retirement benefits.

Income Taxes

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(59)	(34.3)	$(117)	(59.1)

In the third quarter 2021, income taxes were $113 million compared to $172 million for the corresponding period in 2020. The decrease was primarily due to lower pre-tax earnings largely resulting from the third quarter 2021 charge

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AND RESULTS OF OPERATIONS (Continued)

associated with the construction of Plant Vogtle Units 3 and 4, partially offset by an increase in a valuation allowance on certain state tax credit carryforwards.

For year-to-date 2021, income taxes were $81 million compared to $198 million for the corresponding period in 2020. The decrease was primarily due to lower pre-tax earnings resulting from higher charges in 2021 compared to the corresponding period in 2020 associated with the construction of Plant Vogtle Units 3 and 4, partially offset by an increase in a valuation allowance on certain state tax credit carryforwards.

See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" and Note (G) to the Condensed Financial Statements herein for additional information.

Mississippi Power

Net Income

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(17)	(25.4)	$(5)	(3.6)

In the third quarter 2021, net income was $50 million compared to $67 million for the corresponding period in 2020. For year-to-date 2021, net income was $133 million compared to $138 million for the corresponding period in 2020. The decreases were primarily due to increases in operations and maintenance expenses, largely offset by an increase in revenues, resulting from an increase in base rates that became effective for the first billing cycle of April 2021 and higher customer usage when compared to the corresponding periods in 2020.

Retail Revenues

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$16	6.9	$40	6.3

In the third quarter 2021, retail revenues were $248 million compared to $232 million for the corresponding period in 2020. For year-to-date 2021, retail revenues were $670 million compared to $630 million for the corresponding period in 2020.

Details of the changes in retail revenues were as follows:

	Third Quarter 2021				Year-To-Date 2021
	(in millions)		(% change)		(in millions)		(% change)
Retail – prior year	$	232			$	630
Estimated change resulting from –
Rates and pricing	7		3.0	%	8		1.3	%
Sales growth	5		2.2		5		0.8
Weather	(4)		(1.7)		2		0.3
Fuel and other cost recovery	8		3.4		25		4.0
Retail – current year	$	248	6.9	%	$	670	6.4	%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2021 when compared to the corresponding periods in 2020 primarily due to an increase in revenues in accordance with new PEP rates that became effective for the first billing cycle of April 2021. See Note (B) to the Condensed Financial Statements under "Mississippi Power – Performance Evaluation Plan" herein for additional information.

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AND RESULTS OF OPERATIONS (Continued)

Revenues attributable to changes in sales increased in the third quarter and year-to-date 2021 when compared to the corresponding periods in 2020. Weather-adjusted residential KWH sales increased 2.6% and 0.2% in the third quarter and year-to-date 2021, respectively, when compared to the corresponding periods in 2020 due to increased customer usage. Weather-adjusted commercial KWH sales increased 2.8% and 2.5% in the third quarter and year-to-date 2021, respectively, and industrial KWH sales increased 4.9% and 0.2% in the third quarter and year-to-date 2021, respectively, when compared to corresponding periods in 2020, primarily due to the negative impacts of the COVID-19 pandemic on energy sales in 2020.

Fuel and other cost recovery revenues increased in the third quarter and year-to-date 2021 when compared to the corresponding periods in 2020 primarily as a result of higher recoverable fuel costs. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income.

Wholesale Revenues – Non-Affiliates

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(1)	(1.6)	$14	8.5

Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. In addition, Mississippi Power provides service under long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. See Note 2 to the financial statements under "Mississippi Power" in Item 8 of the Form 10-K for additional information.

For year-to-date 2021, wholesale revenues from sales to non-affiliates were $178 million compared to $164 million for the corresponding period in 2020. The increase was primarily due to higher fuel costs and opportunity sales, as well as increases in revenue from MRA customers primarily due to colder weather in the first quarter 2021 and changes in power supply agreements subsequent to the third quarter 2020.

Wholesale Revenues – Affiliates

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$26	72.2	$38	46.3

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 2021, wholesale revenues from sales to affiliates were $62 million compared to $36 million for the corresponding period in 2020 . For year-to-date 2021, wholesale revenues from sales to affiliates were $120 million compared to $82 million for the corresponding period in 2020. The increases for third quarter and year-to-date 2021 were primarily due to increases of $29 million and $52 million, respectively, associated with higher

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AND RESULTS OF OPERATIONS (Continued)

natural gas prices, partially offset by decreases of $2 million and $14 million, respectively, associated with lower KWH sales.

Fuel and Purchased Power Expenses

	Third Quarter 2021 vs. Third Quarter 2020			Year-To-Date 2021 vs. Year-To-Date 2020
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	36	35.0	$	64	24.1
Purchased power	—		—	3		16.7
Total fuel and purchased power expenses	$	36		$	67

In the third quarter 2021, total fuel and purchased power expenses were $145 million compared to $109 million for the corresponding period in 2020. For year-to-date 2021, total fuel and purchased power expenses were $351 million compared to $284 million for the corresponding period in 2020. The increases were primarily due to an increase in the average cost of fuel compared to the corresponding periods in 2020.

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 2021	Third Quarter 2020	Year-To-Date 2021	Year-To-Date 2020
Total generation (in millions of KWHs)	4,878	5,011	13,016	13,662
Total purchased power (in millions of KWHs)	124	162	562	558
Sources of generation (percent) –
Gas	93	89	91	94
Coal	7	11	9	6
Cost of fuel, generated (in cents per net KWH) –
Gas	2.99	1.99	2.66	1.94
Coal	3.16	3.52	3.13	3.70
Average cost of fuel, generated (in cents per net KWH)	3.00	2.16	2.70	2.06
Average cost of purchased power (in cents per net KWH)	4.51	3.66	3.78	3.17

Fuel

In the third quarter 2021, fuel expense was $139 million compared to $103 million for the corresponding period in 2020. The increase was primarily due to a 50.3% increase in the average cost of natural gas per KWH generated, partially offset by a 31.5% decrease in the volume of KWHs generated by coal and a 10.2% decrease in the average cost of coal per KWH generated.

For year-to-date 2021, fuel expense was $330 million compared to $266 million for the corresponding period in 2020. The increase was due to a 37.1% increase in the average cost of natural gas per KWH generated and 34.2% increase in the volume of KWHs generated by coal, partially offset by a 15.4% decrease in the average cost of coal per KWH generated and an 8.0% decrease in the volume of KWHs generated by natural gas.

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AND RESULTS OF OPERATIONS (Continued)

Other Operations and Maintenance Expenses

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$23	37.1	$28	13.9

In the third quarter 2021, other operations and maintenance expenses were $85 million compared to $62 million for the corresponding period in 2020. The increase reflects the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. The increase primarily reflects increases of $9 million associated with the Kemper County energy facility (primarily related to increases in dismantlement and closure costs and no salvage proceeds in 2021) and $7 million in generation expenses associated with outage and non-outage maintenance.

For year-to-date 2021, other operations and maintenance expenses were $230 million compared to $202 million for the corresponding period in 2020. The increase reflects the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. The increase was primarily due to increases of $5 million associated with the Kemper County energy facility (primarily related to increases in dismantlement and closure costs and less salvage proceeds in 2021), $8 million in generation expenses associated with outage and non-outage maintenance, and $5 million in compensation and benefit expenses.

Depreciation and Amortization

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(1)	(2.1)	$3	2.2

For year-to-date, depreciation and amortization was $138 million compared to $135 million for the corresponding period in 2020. The increase was primarily due to a $6 million increase in depreciation due to additional plant in service and an increase in depreciation rates in accordance with the Mississippi Power Rate Case Settlement, partially offset by a $2 million net decrease in amortization associated with regulatory assets and liabilities. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Mississippi Power" for additional information.

Taxes Other Than Income Taxes

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$2	6.5	$6	6.7

For year-to-date 2021, taxes other than income taxes were $96 million compared to $90 million for the corresponding period in 2020. The increase primarily reflects an increase in ad valorem taxes due to higher assessed values.

Other Income (Expense), Net

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$1	16.7	$8	42.1

For year-to-date 2021, other income (expense), net was $27 million compared to $19 million for the corresponding period in 2020. The increase was primarily related to increases of $4 million in non-service cost-related retirement benefits income, $2 million in contributions in aid of construction, and $2 million in interest associated with a sales-type lease. See Notes (D) and (H) to the Condensed Financial Statements herein for additional information.

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AND RESULTS OF OPERATIONS (Continued)

Southern Power

Net Income Attributable to Southern Power

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$4	5.4	$(1)	(0.5)

Net income attributable to Southern Power for the third quarter 2021 was $78 million compared to $74 million for the corresponding period in 2020. The increase was primarily due to a net increase in revenues associated with new PPAs.

Net income attributable to Southern Power for year-to-date 2021 was $211 million compared to $212 million for the corresponding period in 2020. The decrease was primarily due to an increase in other operations and maintenance expenses in 2021 primarily associated with scheduled outages and maintenance and a gain recorded in the third quarter 2020 associated with the Roserock solar facility litigation, partially offset by a net increase in revenues associated with new PPAs and a tax benefit due to changes in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in February 2021.

Operating Revenues

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$156	29.8	$273	20.4

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

Natural Gas Capacity and Energy Revenue

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

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

Solar and Wind Energy Revenue

Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have capacity revenue. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy generated from the respective facility and sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors.

See FUTURE EARNINGS POTENTIAL – "Southern Power's Power Sales Agreements" in Item 7 of the Form 10-K for additional information regarding Southern Power's PPAs.

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AND RESULTS OF OPERATIONS (Continued)

Operating Revenues Details

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

	Third Quarter 2021		Third Quarter 2020		Year-To-Date 2021		Year-To-Date 2020
	(in millions)
PPA capacity revenues	$	118	$	116	$	311	$	297
PPA energy revenues	413		319		954		794
Total PPA revenues	531		435		1,265		1,091
Non-PPA revenues	139		84		327		235
Other revenues	9		4		18		11
Total operating revenues	$	679	$	523	$	1,610	$	1,337

In the third quarter 2021, total operating revenues were $679 million, reflecting a $156 million, or 30%, increase from the corresponding period in 2020. The increase in operating revenues was primarily due to the following:

•PPA energy revenues increased $94 million, or 29%, primarily due to an increase in sales under existing natural gas PPAs resulting from a $75 million increase in the price of fuel and purchased power and a $20 million increase related to a net increase in natural gas PPAs.

•Non-PPA revenues increased $55 million, or 65%, due to a $60 million increase in the market price of energy, partially offset by a $5 million decrease in the volume of KWHs sold through short-term sales.

For year-to-date 2021, total operating revenues were $1.6 billion, reflecting a $273 million, or 20%, increase from the corresponding period in 2020. The increase in operating revenues was primarily due to the following:

•PPA capacity revenues increased $14 million, or 5%, primarily due to increased capacity sales under existing contracts.

•PPA energy revenues increased $160 million, or 20%, primarily due to an increase in sales under existing natural gas PPAs resulting from a $139 million increase in the price of fuel and purchased power and a $25 million increase related to a net increase in natural gas PPAs. Also contributing to the increase was $12 million related to new wind PPAs which began subsequent to the first quarter 2020, partially offset by a $10 million decrease in sales under existing wind PPAs primarily due to a decrease in the volume of KWHs sold.

•Non-PPA revenues increased $92 million, or 39%, due to a $132 million increase in the market price of energy, partially offset by a $40 million decrease in the volume of KWHs sold through short-term sales.

Fuel and Purchased Power Expenses

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

	Third Quarter 2021	Third Quarter 2020	Year-To-Date 2021	Year-To-Date 2020
	(in billions of KWHs)
Generation	12.1	12.3	31.8	34.3
Purchased power	0.8	0.7	2.0	2.3
Total generation and purchased power	12.9	13.0	33.8	36.6
Total generation and purchased power, excluding solar, wind, and tolling agreements	7.7	7.4	20.2	21.9

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AND RESULTS OF OPERATIONS (Continued)

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 2021 vs. Third Quarter 2020			Year-To-Date 2021 vs. Year-To-Date 2020
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	122	89.1	$	194	56.1
Purchased power	22		115.8	34		65.4
Total fuel and purchased power expenses	$	144		$	228

In the third quarter 2021, total fuel and purchased power expenses increased $144 million, or 92%, compared to the corresponding period in 2020. Fuel expense increased $122 million due to a $115 million increase in the average cost of fuel per KWH generated and a $7 million increase associated with the volume of KWHs generated. Purchased power expense increased $22 million primarily due to an increase in the average cost of purchased power.

For year-to-date 2021, total fuel and purchased power expenses increased $228 million, or 57%, compared to the corresponding period in 2020. Fuel expense increased $194 million due to a $221 million increase in the average cost of fuel per KWH generated, partially offset by a $27 million decrease associated with the volume of KWHs generated. Purchased power expense increased $34 million due to a $39 million increase associated with the average cost of purchased power, partially offset by a $5 million decrease associated with the volume of KWHs purchased.

Other Operations and Maintenance Expenses

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$5	5.6	$63	25.7

For year-to-date 2021, other operations and maintenance expenses were $308 million compared to $245 million for the corresponding period in 2020. The increase was primarily due to increases of $22 million in scheduled outage and maintenance expenses, $9 million in transmission expenses, $6 million in expenses associated with new wind facilities placed in service subsequent to the first quarter 2020, and $6 million related to the allocation of uncollected settlements by the Energy Reliability Council of Texas market as a result of Winter Storm Uri.

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AND RESULTS OF OPERATIONS (Continued)

Depreciation and Amortization

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$3	2.3	$16	4.4

For year-to-date 2021, depreciation and amortization was $383 million compared to $367 million for the corresponding period in 2020. The increase primarily resulted from new wind facilities placed in service subsequent to the first quarter 2020.

Loss on Sales-Type Lease

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$15	N/M	$15	N/M

N/M - Not meaningful

In the third quarter 2021, a $15 million loss on sales-type lease was recorded upon commencement of the Garland battery energy storage facility PPA, $10 million of which was allocated through noncontrolling interests to Southern Power's partners in the project. See Notes (D) and (K) to the Condensed Financial Statements under "Lease Receivables" and "Southern Power," respectively, herein for additional information.

(Gain) Loss on Dispositions, Net

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$—	—

For year-to-date 2021, gains on dispositions totaled $39 million primarily from contributions of wind turbine equipment to various equity method investments in the first quarter 2021. A $39 million gain was also recorded in the first quarter 2020 related to the sale of Plant Mankato. See Notes (E) and (K) to the Condensed Financial

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AND RESULTS OF OPERATIONS (Continued)

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.

Other Income (Expense), Net

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(11)	(84.6)	$(9)	(47.4)

In the third quarter 2021, other income (expense), net was $2 million compared to $13 million for the corresponding period in 2020. For year-to-date 2021, other income (expense), net was $10 million compared to $19 million for the corresponding period in 2020. The decreases primarily related to a $12 million gain recorded in the third quarter 2020 associated with the Roserock solar facility litigation.

Income Taxes (Benefit)

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(5)	(35.7)	$(30)	(111.1)

For year-to-date 2021, income tax benefit was $3 million compared to income tax expense of $27 million for the corresponding period in 2020. The change was primarily due to changes in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in February 2021 and the tax impact from the sale of Plant Mankato in January 2020.

See Note (G) to the Condensed Financial Statements herein, MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Alabama State Tax Reform Legislation" in Item 7 of the Form 10-K, and Note 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K for additional information.

Net Income (Loss) Attributable to Noncontrolling Interests

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(23)	(82.1)	$(30)	N/M

N/M - Not meaningful

In the third quarter 2021, net income attributable to noncontrolling interests was $5 million compared to $28 million for the corresponding period in 2020. For year-to-date 2021, net loss attributable to noncontrolling interests was $27 million compared to net income of $3 million for the corresponding period in 2020. These changes were primarily due to loss allocations of $13 million related to the commencement of the Garland battery energy storage facility PPA in the third quarter 2021, which includes $10 million allocated from the loss on sales-type lease. In addition, these changes were due to lower income allocations to solar equity partners and higher HLBV loss allocations to wind tax equity partners, including new partnerships entered into subsequent to the third quarter 2020, totaling $10 million and $16 million for the third quarter and year-to-date 2021, respectively. See Notes (D) and (K) to the Condensed Financial Statements under "Lease Receivables" and "Southern Power," respectively, herein 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.

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AND RESULTS OF OPERATIONS (Continued)

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. Southern Company Gas also utilizes weather hedges to limit the negative income impacts in the event of warmer-than-normal weather.

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

Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services illustrate the effects of weather and customer demand for natural gas. 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. Prior to the sale of Sequent, wholesale gas services' operating revenues occasionally were 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

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$42	N/M	$29	8.1

N/M - Not meaningful

In the third quarter 2021, net income was $56 million compared to $14 million for the corresponding period in 2020. For year-to-date 2021, net income was $389 million compared to $360 million for the corresponding period in 2020. The increases for the third quarter and year-to-date 2021 primarily reflect increases of $139 million and $153 million, respectively, at wholesale gas services primarily due to the gain on the sale of Sequent and higher revenues, partially offset by $85 million of deferred income taxes. The third quarter 2021 change also reflects a decrease of $13 million at gas pipeline investments primarily from after-tax charges related to the PennEast Pipeline project. The year-to-date 2021 increase also reflects a $24 million increase at gas distribution operations primarily due to base rate increases and continued investment in infrastructure replacement, partially offset by a decrease of $71 million at gas pipeline investments primarily related to after-tax impairment charges related to the PennEast Pipeline project.

See Note (C) to the Condensed Financial Statements under "Other Matters – Southern Company Gas" herein and Notes (E) and (K) to the Condensed Financial Statements under "Southern Company Gas" herein, as well as Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.

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Natural Gas Revenues, including Alternative Revenue Programs

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$146	30.6	$632	26.8

In the third quarter 2021, natural gas revenues, including alternative revenue programs, were $623 million compared to $477 million for the corresponding period in 2020. For year-to-date 2021, natural gas revenues, including alternative revenue programs, were $3.0 billion compared to $2.4 billion for the corresponding period in 2020.

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

	Third Quarter 2021				Year-To-Date 2021
	(in millions)		(% change)		(in millions)		(% change)
Natural gas revenues – prior year	$	477			$	2,362
Estimated change resulting from –
Infrastructure replacement programs and base rate changes	28		5.9	%	109		4.6	%
Gas costs and other cost recovery	54		11.3		294		12.5
Wholesale gas services	51		10.7		207		8.8
Other	13		2.7		22		0.9
Natural gas revenues – current year	$	623	30.6	%	$	2,994	26.8	%

Revenues from infrastructure replacement programs and base rate changes increased in the third quarter and year-to-date 2021 compared to the corresponding periods in 2020 primarily due to rate increases at Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas and continued investment in infrastructure replacement. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K for additional information.

Revenues associated with gas costs and other cost recovery increased in the third quarter and year-to-date 2021 compared to the corresponding periods in 2020 primarily due to higher volumes of natural gas sold and higher natural gas cost recovery. See "Cost of Natural Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.

For the third quarter 2021, the change in revenues related to Southern Company Gas' wholesale gas services was due to the sale of Sequent on July 1, 2021. The year-to-date 2021 change reflects higher volumes of natural gas sold and higher commercial activities as a result of Winter Storm Uri, partially offset by derivative losses all prior to the sale of Sequent on July 1, 2021. See "Segment Information – Wholesale Gas Services" herein for additional information. Also see Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

Southern Company Gas' natural gas distribution utilities have various regulatory mechanisms that limit their exposure to weather changes. Southern Company Gas also uses hedges for any remaining exposure to warmer-than-normal weather in Illinois for gas distribution operations and in Illinois and Georgia for gas marketing services; therefore, weather typically does not have a significant net income impact. The following table presents Heating Degree Days information for Illinois and Georgia, the primary locations where Southern Company Gas' operations are impacted by weather.

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	Third Quarter			2021 vs. normal		2021 vs. 2020		Year-to-Date			2021 vs. normal		2021 vs. 2020
	Normal(*)	2021	2020	(warmer)		(warmer)		Normal(*)	2021	2020	(warmer)		colder
	(in thousands)							(in thousands)
Illinois	53	14	54	(73.6)	%	(74.1)	%	3,734	3,594	3,548	(3.7)	%	1.3	%
Georgia	3	3	15	—	%	(80.0)	%	1,454	1,396	1,294	(4.0)	%	7.9	%

(*)Normal represents the 10-year average from January 1, 2011 through September 30, 2020 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, 2021 and 2020:

	September 30,
	2021		2020		2021 vs. 2020
	(in thousands, except market share %)				(% change)
Gas distribution operations	4,283		4,258		0.6	%
Gas marketing services
Energy customers(*)	603		659		(8.5)	%
Market share of energy customers in Georgia	28.9	%	28.9	%	—	%

(*)Gas marketing services' customers are primarily located in Georgia and Illinois. September 30, 2020 also includes 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 customer growth and uses a variety of targeted marketing programs to attract new customers and to retain existing customers.

Cost of Natural Gas

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$58	81.7	$289	44.2

Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. Cost of natural gas at gas distribution operations represented 78% and 85% of total cost of natural gas for the third quarter and year-to-date 2021, 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 2021, cost of natural gas was $129 million compared to $71 million for the corresponding period in 2020. The increase reflects higher gas cost recovery driven by a 103% increase in natural gas prices in the third quarter 2021 compared to the corresponding period in 2020.

For year-to-date 2021, cost of natural gas was $943 million compared to $654 million for the corresponding period in 2020. The increase reflects higher volumes sold due to colder weather and higher gas cost recovery for year-to-date 2021 compared to the corresponding period in 2020. The increase also reflects a 69% increase in natural gas prices for year-to-date 2021 compared to the corresponding period in 2020.

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

	Third Quarter		2021 vs. 2020		Year-to-Date		2021 vs. 2020
	2021	2020			2021	2020
Gas distribution operations (mmBtu in millions)
Firm	74	68	8.8	%	465	425	9.4	%
Interruptible	23	21	9.5		73	67	9.0
Total	97	89	9.0	%	538	492	9.3	%
Wholesale gas services (mmBtu in millions/day)
Daily physical sales	—	7.1	(100.0)	%	6.6	6.8	(2.9)	%
Gas marketing services (mmBtu in millions)
Firm:
Georgia	3	3	—	%	26	21	23.8	%
Illinois	—	1	(100.0)		5	6	(16.7)
Other	2	2	—		10	9	11.1
Interruptible large commercial and industrial	3	3	—		10	10	—
Total	8	9	(11.1)	%	51	46	10.9	%

Other Operations and Maintenance Expenses

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$21	9.7	$82	11.8

In the third quarter 2021, other operations and maintenance expenses were $238 million compared to $217 million for the corresponding period in 2020. The increase was primarily due to higher compensation primarily at distribution operations and bad debt expenses. For year-to-date 2021, other operations and maintenance expenses were $776 million compared to $694 million for the corresponding period in 2020. The increase was primarily due to higher compensation expenses primarily at distribution operations and wholesale gas services.

Depreciation and Amortization

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$8	6.4	$28	7.6

In the third quarter 2021, depreciation and amortization was $133 million compared to $125 million for the corresponding period in 2020. For year-to-date 2021, depreciation and amortization was $396 million compared to $368 million for the corresponding period in 2020. The increases were primarily due to continued infrastructure investments at the natural gas distribution utilities.

Taxes Other Than Income Taxes

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$1	2.9	$12	7.8

For year-to-date 2021, taxes other than income taxes were $166 million compared to $154 million for the corresponding period in 2020. The increase primarily reflects an increase in revenue tax expenses as a result of higher natural gas revenues at Nicor Gas. These revenue tax expenses are passed directly to customers and have no impact on net income.

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(Gain) Loss on Dispositions, Net

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$121	N/M	$129	N/M

N/M - Not meaningful

In the third quarter and year-to-date 2021, gain on dispositions was $121 million and $127 million, respectively, and primarily related to the $121 million gain on the sale of Sequent recorded in the third quarter 2021. The year-to-date 2021 gain also includes $5 million of contingent payment from the sale of Pivotal LNG recorded in the second quarter 2021. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

Earnings from Equity Method Investments

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(8)	(24.2)	$(92)	(86.8)

In the third quarter 2021, earnings from equity method investments was $25 million compared to $33 million for the corresponding period in 2020. The decrease was primarily due to lower earnings at SNG resulting from lower revenues and an impairment charge related to the PennEast Pipeline project.

For year-to-date 2021, earnings from equity method investments was $14 million compared to $106 million for the corresponding period in 2020. The decrease was primarily due to pre-tax impairment charges totaling $84 million related to the PennEast Pipeline project and lower earnings at SNG resulting from lower revenues.

See Notes (C) and (E) to the Condensed Financial Statements herein under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, for additional information.

Other Income (Expense), Net

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$1	8.3	$(99)	N/M

N/M - Not meaningful

For year-to-date 2021, other income (expense), net was $66 million of expense compared to $33 million of income for the corresponding period in 2020. The change was largely due to charitable contributions of $101 million in the second quarter 2021.

Income Taxes

Third Quarter 2021 vs. Third Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$130	N/M	$126	128.6

N/M - Not meaningful

In the third quarter 2021, income taxes were $133 million compared to $3 million for the corresponding period in 2020. For year-to-date 2021, income taxes were $224 million compared to $98 million for the corresponding period in 2020. The increases were primarily the result of $85 million in additional tax expense resulting from changes in state apportionment rates as a result of the sale of Sequent, $28 million of tax expense related to the sale of Sequent, and higher pre-tax earnings at wholesale gas services and gas distribution operations. Partially offsetting the year-to-date 2021 increase was $18 million of tax benefit resulting from the impairment charge in the second quarter 2021

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at gas pipeline investments related to the PennEast Pipeline project. See Notes (C) and (E) to the Condensed Financial Statements herein under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, as well as Note (G) to the Condensed Financial Statements herein for additional information.

Segment Information

Operating revenues, 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 2021						Third Quarter 2020
	Operating Revenues		Operating Expenses		Net Income (Loss)		Operating Revenues		Operating Expenses		Net Income (Loss)
	(in millions)						(in millions)
Gas distribution operations	$	556	$	459	$	45	$	479	$	384	$	46
Gas pipeline investments	8		3		10		8		3		23
Wholesale gas services	—		(120)		94		(51)		11		(45)
Gas marketing services	52		52		(2)		39		45		(3)
All other	11		25		(91)		8		11		(7)
Intercompany eliminations	(4)		(4)		—		(6)		(6)		—
Consolidated	$	623	$	415	$	56	$	477	$	448	$	14

	Year-To-Date 2021						Year-To-Date 2020
	Operating Revenues		Operating Expenses		Net Income (Loss)		Operating Revenues		Operating Expenses		Net Income (Loss)
	(in millions)						(in millions)
Gas distribution operations	$	2,466	$	1,936	$	308	$	2,086	$	1,609	$	284
Gas pipeline investments	24		9		3		24		9		74
Wholesale gas services	188		(53)		108		(19)		40		(45)
Gas marketing services	311		226		60		272		194		59
All other	29		60		(90)		24		45		(12)
Intercompany eliminations	(24)		(24)		—		(25)		(25)		—
Consolidated	$	2,994	$	2,154	$	389	$	2,362	$	1,872	$	360

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.

In the third quarter and year-to-date 2021, net income decreased $1 million, or 2.2%, and increased $24 million, or 8.5%, respectively, when compared to the corresponding periods in 2020. In the third quarter and year-to-date 2021,

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operating revenue increased $77 million and $380 million, respectively, when compared to the corresponding periods in 2020 primarily due to higher gas cost recovery, rate increases for Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas and continued investment in infrastructure replacement. Gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas. In the third quarter and year-to-date 2021, operating expenses increased $75 million and $327 million, respectively, when compared to the corresponding periods in 2020 primarily due to increases of $44 million and $245 million, respectively, in cost of gas as a result of higher natural gas prices and higher volumes sold, higher depreciation resulting from additional assets placed in service, higher taxes other than income taxes due to higher pass through taxes, and higher compensation expenses. In the third quarter and year-to-date 2021, other income and expense decreased $4 million and $8 million, respectively, when compared to the corresponding periods in 2020, primarily due to a decrease in non-service cost-related retirement benefits income. In the third quarter and year-to-date 2021, interest expense, net of amounts capitalized increased $6 million and $16 million, respectively, when compared to the corresponding periods in 2020 primarily due to additional debt issued to finance continued investments. In the third quarter and year-to-date 2021, income taxes decreased $7 million and increased $5 million, respectively, when compared to the corresponding periods in 2020, primarily due to changes in pre-tax earnings and a lower estimated tax rate.

See Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K 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 Note (E) to the Condensed Financial Statements under "Southern Company Gas" herein and Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information. Also see Note (C) to the Condensed Financial Statements under "Other Matters – Southern Company Gas" herein for information regarding the September 2021 cancellation of the PennEast Pipeline project.

In the third quarter 2021, net income decreased $13 million, or 56.5%, compared to the corresponding period in 2020. The decrease primarily relates to an impairment charge related to the PennEast Pipeline project.

For year-to-date 2021, net income decreased $71 million, or 95.9% when compared to the corresponding period in 2020. The decrease was primarily due to pre-tax impairment charges totaling $84 million ($67 million after tax) related to the equity method investment in the PennEast Pipeline project, as well as lower earnings at SNG due to lower revenues.

Wholesale Gas Services

Prior to the sale of Sequent on July 1, 2021, wholesale gas services was 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 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 increased, wholesale gas services was positioned to capture significant value and generate stronger results. Operating expenses primarily reflect employee compensation and benefits. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for information regarding the sale of Sequent on July 1, 2021.

In the third quarter 2021, net income increased $139 million, or 308.9%, compared to the corresponding period in 2020. The sale of Sequent on July 1, 2021 resulted in $94 million of net income in the third quarter 2021. In the third quarter 2020, wholesale gas services had $51 million of commercial activity and derivative losses and $11 million in operating expenses, which resulted in a net loss of $45 million.

For year-to-date 2021, net income increased $153 million, or 340.0% when compared to the corresponding period in 2020. The increase primarily relates to a $207 million increase in operating revenue and a $121 million gain on the sale of Sequent, partially offset by a $28 million increase in operating expenses primarily related to an increase in

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variable compensation, a $101 million decrease in other income and (expense) related to higher charitable contributions, and a $47 million increase in income tax expense due to higher pre-tax earnings.

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. Due to the sale of Sequent on July 1, 2021, the change in the third quarter 2021 reflects the commercial activities and derivative losses in the third quarter 2020. The increase in commercial activity for year-to-date 2021 compared to the corresponding period in 2020 was primarily due to natural gas price volatility that was generated by cold weather, particularly in the Midwest and Texas, resulting in wider 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 2021 resulted in storage derivative losses. Transportation and forward commodity derivative losses in 2021 were a result of widening transportation spreads.

Gas Marketing Services

Gas marketing services provides energy-related products and services to natural gas markets and participants in customer choice programs that were approved in various states to increase competition. These programs allow customers to choose their natural gas supplier while the local distribution utility continues to provide distribution and transportation services. Gas marketing services is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts.

In the third quarter and year-to-date 2021, operating revenue increased $13 million and $39 million, respectively, when compared to the corresponding periods in 2020. These increases primarily relate to higher natural gas prices and increased retail price spreads. In the third quarter and year-to-date 2021, cost of sales increased $10 million and $39 million, respectively, when compared to the corresponding periods in 2020 primarily due to higher natural gas prices.

All Other

All other includes natural gas storage businesses, including Jefferson Island through its sale on December 1, 2020, fuels operations through the sale of Southern Company Gas' interest in Pivotal LNG on March 24, 2020, 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.

In the third quarter 2021, net loss increased $84 million and for year-to-date 2021, net income decreased $78 million when compared to the corresponding periods in 2020. The changes primarily relate to additional tax expense due to changes in state apportionment rates as a result of the sale of Sequent.

See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information on the sale of its interest in Pivotal LNG and the sale of Jefferson Island. Also see Notes (G) and (K) to the Condensed Financial Statements herein.

FUTURE EARNINGS POTENTIAL

Each Registrant's results of operations are not necessarily indicative of its future earnings potential. The level of the Registrants' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Registrants' primary businesses of selling electricity and/or distributing natural gas, as described further herein.

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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. For Georgia Power, completing construction of Plant Vogtle Units 3 and 4 and related cost recovery proceedings is another major factor.

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

Global and U.S. economic conditions have been significantly affected by a series of demand and supply shocks that caused a global and national economic recession in 2020. Most prominently, the COVID-19 pandemic has negatively impacted global supply chains and business operations as suppliers continue to experience difficulties keeping up with strong demand for factory goods, which is being driven by low business inventories. In addition, rising inflation in 2021 has resulted in increasing costs for many goods and services. The combination of rising inoculation rates in the U.S. population and the federal COVID-19 relief package contributed to increased economic recovery in 2021; however, fiscal support of business and personal incomes is declining. The drivers, speed, and depth of the 2020 economic contraction were 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. Retail electric revenues attributable to changes in sales increased in the first nine months of 2021 when compared to the corresponding period in 2020 primarily due to the normalization of economic activity; however, retail electric sales continued to be negatively impacted by the COVID-19 pandemic when compared to pre-pandemic trends. Recovery is expected to continue through the remainder of 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 2021.

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, availability of tax credits, 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 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, and Southern Company Gas' ability 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 business to capture value from locational and seasonal spreads. Additionally, changes in commodity prices, primarily driven by tight gas supplies and diminished gas production, subject a portion of Southern Company Gas' operations to earnings variability. 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. However, if economic conditions continue to improve, the demand for natural gas may increase, which may cause natural gas prices to rise and drive higher volatility in the natural gas markets on a longer-term basis.

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Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather, competition, developing new and maintaining existing energy contracts and associated load requirements with wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, government incentives to reduce overall energy usage, the prices of electricity and natural 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. See Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein for additional information.

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

Environmental Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" in Item 7 and Note 3 to the financial statements under "Environmental Remediation" in Item 8 of the Form 10-K, as well as Note (C) to the Condensed Financial Statements under "Environmental Remediation" herein, for additional information.

Environmental Laws and Regulations

Water Quality

On July 26, 2021, the EPA announced its intent to further revise the ELG Rules, with a proposed rule expected in the fall of 2022. The ultimate outcome of this matter cannot be determined at this time; however, any revisions could require changes in the traditional electric operating companies' compliance strategies.

On October 13, 2021, in accordance with the ELG Rules' requirement for electric utilities to identify compliance plans either through certain compliance pathways or by permanently ceasing combustion of coal by certain deadlines, Alabama Power and Georgia Power each submitted initial notices of planned participation (NOPP) for applicable units with its state permitting authority, as detailed further below.

Alabama Power submitted its NOPP to the Alabama Department of Environmental Management indicating plans to retire Plant Barry Unit 5 (700 MWs) and to cease using coal and begin operating solely on natural gas at Plant Barry Unit 4 (350 MWs) and Plant Gaston Unit 5 (880 MWs). Alabama Power, as agent for SEGCO, which is equally owned by Alabama Power and Georgia Power, indicated plans to retire Plant Gaston Units 1 through 4 (1,000 MWs). These plans are expected to be completed on or before the compliance date of December 31, 2028. The NOPP submittals are subject to the review of the Alabama Department of Environmental Management. Retirement of Plant Barry Unit 5 could occur as early as 2023, subject to completion of the acquisition of the Calhoun Generating Station and certain operating conditions. See Note 7 to the financial statements under "SEGCO" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Alabama Power – Calhoun Generating Station Acquisition" herein for additional information.

The assets for which Alabama Power has indicated retirement, due to early closure or repowering of the unit to natural gas, have net book values totaling approximately $1.5 billion (excluding capitalized asset retirement costs

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which are recovered through Rate CNP Compliance) at September 30, 2021. Based on an Alabama PSC order, Alabama Power is authorized to establish a regulatory asset to record the unrecovered investment costs, including the plant asset balance and the costs associated with site removal and closure, associated with future unit retirements caused by environmental regulations (Environmental Accounting Order). Under the Environmental Accounting Order, the regulatory asset would be amortized and recovered over an affected unit's remaining useful life, as established prior to the decision regarding early retirement, through Rate CNP Compliance. See Note 2 to the financial statements under "Alabama Power – Rate CNP Compliance" and " – Environmental Accounting Order" in Item 8 of the Form 10-K for additional information.

Georgia Power submitted its NOPP to the Georgia Environmental Protection Division indicating plans to retire Plant Wansley Units 1 and 2 (926 MWs based on 53.5% ownership), Plant Bowen Units 1 and 2 (1,400 MWs), and Plant Scherer Unit 3 (614 MWs based on 75% ownership) on or before the compliance date of December 31, 2028. Georgia Power intends to pursue compliance with the ELG Rules for Plant Scherer Units 1 and 2 (137 MWs based on 8.4% ownership) through the voluntary incentive program by no later than December 31, 2028. Georgia Power intends to comply with the ELG Rules for Plant Bowen Units 3 and 4 through the generally applicable requirements by December 31, 2025; therefore, no NOPP submission was required for these units. The NOPP submittals and generally applicable requirements are subject to the review of the Georgia Environmental Protection Division.

The units for which Georgia Power has indicated early retirement plans have net book values totaling approximately $2.2 billion (excluding capitalized asset retirement costs which are recovered through the ECCR tariff) at September 30, 2021. A final decision regarding the future operation of Georgia Power's impacted units and the timing of any retirements will be subject to review by the Georgia PSC in Georgia Power's next IRP, which is required to be filed by January 31, 2022.

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

Coal Combustion Residuals

Based on requirements for closure and monitoring of landfills and ash ponds pursuant to the CCR Rule and applicable state rules, the traditional electric operating companies have periodically updated, and expect to continue periodically updating, their related cost estimates and ARO liabilities for each CCR unit as additional information related to ash pond closure methodologies, schedules, and/or costs becomes available. Some of these updates have been, and future updates may 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 (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for information regarding increases in AROs recorded during the third quarter 2021 at Alabama Power, Georgia Power, and Mississippi Power.

Regulatory Matters

See OVERVIEW – "Recent Developments" and Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for a discussion of regulatory matters related to Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas, including items that could impact the applicable registrants' future earnings, cash flows, and/or financial condition.

Alabama Power

On August 11, 2021, the Alabama PSC issued an order approving an extension of Alabama Power's Renewable Generation Certificate (RGC) through September 16, 2027. The RGC authorizes Alabama Power to procure up to 500 MWs of capacity and energy from renewable energy resources and to separately market the related energy and environmental attributes to customers and other third parties. Alabama Power has four solar projects under the RGC totaling approximately 170 MWs.

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Georgia Power

In 2021, as authorized in its 2019 IRP, Georgia Power requested and received certification from the Georgia PSC for 970 MWs of utility-scale PPAs for solar generation resources, which are expected to be in operation by the end of 2023. The ultimate outcome of this matter cannot be determined at this time.

Construction Programs

The Subsidiary Registrants are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system 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 Note (B) to the Condensed Financial Statements under "Georgia Power – 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.

See Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein under "Southern Power" for additional information 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 Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information on Southern Company Gas' construction program.

See FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" herein for additional information regarding the Registrants' capital requirements for their construction programs.

General Litigation and Other Matters

The Registrants are involved in various matters being litigated and/or regulatory and other matters that could affect future earnings, cash flows, and/or financial condition. The ultimate outcome of such pending or potential litigation against each Registrant and any subsidiaries or regulatory and other matters cannot be determined at this time; however, for current proceedings and/or matters not specifically reported herein or in Notes (B) and (C) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings and/or matters would have a material effect on such Registrant's financial statements. See Notes (B) and (C) to the Condensed Financial Statements for a discussion of various contingencies, including matters being litigated, regulatory matters, and other matters which may affect future earnings potential.

Alabama Power

On March 10, 2021, Alabama Power executed a coordinated planning and operations agreement with PowerSouth, with a minimum term of 10 years. The agreement, which includes combined operations (including joint commitment and dispatch), is expected to create energy cost savings and enhanced system reliability for both parties. Projected revenues are expected to offset any increased administrative costs incurred by Alabama Power; therefore, no material impact to net income is expected. Alabama Power has the right to participate in a portion of PowerSouth's future incremental load growth. All regulatory approvals have been received and the agreement was implemented on September 1, 2021.

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ACCOUNTING POLICIES

See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES in Item 7 of the Form 10-K for a complete discussion of the Registrants' critical accounting policies and estimates, as well as recently issued accounting standards.

Application of Critical Accounting Policies and Estimates

The Registrants prepare their financial statements in accordance with GAAP. Significant accounting policies are described in the notes to the financial statements in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on the Registrants' results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements.

As a result of the sale of Sequent on July 1, 2021, Southern Company and Southern Company Gas no longer consider valuations regarding derivatives and hedging activities to be a critical accounting estimate. Except as described herein, there were no other significant changes to the Registrants' critical accounting policies and estimates during the nine months ended September 30, 2021. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for information regarding the sale of Sequent.

Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4

(Southern Company and Georgia Power)

Following milestone extensions in January 2021, Southern Nuclear has been performing additional construction remediation work necessary to ensure quality and design standards are met as system turnovers are completed to support hot functional testing, which was completed in July 2021, and fuel load for Unit 3. As a result of challenges including, but not limited to, construction productivity, construction remediation work, the pace of system turnovers, spent fuel pool repairs, and the timeframe and duration for hot functional and other testing, at the end of the second quarter 2021, Southern Nuclear further extended certain milestone dates, including the fuel load for Unit 3, from those established in January 2021. Through the third quarter 2021, the project continued to face challenges including, but not limited to, construction productivity, construction remediation work, and the pace of system turnovers. As a result of these continued challenges, at the end of the third quarter 2021, Southern Nuclear further extended certain milestone dates, including fuel load for Unit 3, from those established at the end of the second quarter 2021. The site work plan currently targets fuel load for Unit 3 in the first quarter 2022 and an in-service date of May 2022 and primarily depends on significant improvements in overall construction productivity and production levels, the volume of construction remediation work, the pace of system and area turnovers, and the progression of startup and other testing. As the site work plan includes minimal margin to these milestone dates, an in-service date in the third quarter 2022 for Unit 3 is projected, although any further delays could result in a later in-service date.

As the result of productivity challenges, at the end of the second quarter 2021, Southern Nuclear also further extended milestone dates for Unit 4 from those established in January 2021. These productivity challenges continued into the third quarter 2021 and some craft and support resources were diverted temporarily to support construction efforts on Unit 3. As a result of these factors, at the end of the third quarter 2021, Southern Nuclear further extended the milestone dates for Unit 4 from those established at the end of the second quarter 2021. The site work plan targets an in-service date of March 2023 for Unit 4 and primarily depends on overall construction productivity and production levels significantly improving as well as appropriate levels of craft laborers, particularly electricians and pipefitters, being added and maintained. As the site work plan includes minimal margin to the milestone dates, an in-service date in the second quarter 2023 for Unit 4 is projected, although any further delays could result in a later in-service date.

As of March 31, 2021, approximately $84 million of the construction contingency established in the fourth quarter 2020 was assigned to the base capital cost forecast for costs primarily associated with the schedule extension for Unit 3 to December 2021, construction productivity, support resources, and construction remediation work. Georgia

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Power increased its total capital cost forecast as of March 31, 2021 by adding $48 million to the remaining construction contingency. As of June 30, 2021, all of the remaining construction contingency previously established and an additional $341 million was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units 3 and 4, construction remediation work for Unit 3, and construction productivity and support resources for Units 3 and 4. Georgia Power also increased its total capital cost forecast as of June 30, 2021 by adding $119 million to replenish construction contingency. As a result of the factors discussed above, during the third quarter 2021, all of the remaining construction contingency previously established in the second quarter 2021 and an additional $127 million was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units 3 and 4, construction productivity and support resources for Units 3 and 4, and construction remediation work for Unit 3. Georgia Power also increased its total capital cost forecast as of September 30, 2021 by adding $137 million to replenish construction contingency. Georgia Power's revised base capital cost forecast and contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 is $9.34 billion and $0.14 billion, respectively, for a total capital cost forecast of $9.48 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds).

After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded pre-tax charges to income in the first quarter 2021, the second quarter 2021, and the third quarter 2021 of $48 million ($36 million after tax), $460 million ($343 million after tax), and $264 million ($197 million after tax), respectively, for the increases in the total project capital cost forecast. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.

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 "Georgia Power – Nuclear Construction" 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, 2021. The Registrants intend to continue to monitor their access to short-term and long-term capital markets as well as their bank credit arrangements to meet future capital and liquidity needs. See "Cash Requirements," "Sources of Capital," and "Financing Activities" herein and Note (K) to the Condensed Financial Statements herein for additional information.

At the end of the third quarter 2021, the market price of Southern Company's common stock was $61.97 per share (based on the closing price as reported on the NYSE) and the book value was $27.07 per share, representing a market-to-book ratio of 229%, compared to $61.43, $26.48, and 232%, respectively, at the end of 2020. Southern Company's common stock dividend for the third quarter 2021 was $0.66 per share compared to $0.64 per share in the third quarter 2020.

Cash Requirements

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" in Item 7 of the Form 10-K for a description of the Registrants' significant cash requirements.

The Registrants' significant cash requirements include estimated capital expenditures associated with their construction programs. 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

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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 impacts of the COVID-19 pandemic could also impair the ability to develop, construct, and operate facilities, as discussed further in Item 1A of the Form 10-K. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, expenditures associated with Southern Power's planned acquisitions may vary due to market opportunities and the execution of its growth strategy. See Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein under "Southern Power" for additional information regarding Southern Power's plant acquisitions and construction projects.

The construction program of Georgia Power includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Georgia Power – Nuclear Construction" for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures.

In October 2021, Alabama Power's Board of Directors approved updates to its construction program that is currently estimated to total $1.9 billion for 2022, $1.8 billion for 2023, and $1.7 billion for each of 2024, 2025, and 2026. These amounts include capital expenditures related to Plant Barry Unit 8, nuclear fuel, and 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 any future regulation of CO2 emissions from fossil fuel-fired electric generating units. 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 on the construction of Plant Barry Unit 8.

Long-term debt maturities and the interest payable on long-term debt each represent a significant cash requirement for the Registrants. See "Financing Activities" herein for information on changes in the Registrants' long-term debt balances since December 31, 2020.

Sources of Capital

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" in Item 7 of the Form 10-K for additional information. Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt and equity issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. Southern Company does not expect to issue any equity in the capital markets through 2025 but may issue equity through its stock plans during this time. See Note 8 to the financial statements under "Equity Units" in Item 8 of the Form 10-K for information on stock purchase contracts associated with Southern Company's equity units.

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 amount, type, and timing of any financings in 2021, as well as in subsequent years, will be contingent on investment opportunities and the Registrants' capital requirements and will depend upon prevailing market conditions, regulatory approvals (for certain of the Subsidiary Registrants), and other factors. See "Cash Requirements" and "Financing Activities" herein for additional information.

Southern Power utilizes tax equity partnerships as one of its financing sources, where the tax partner takes significantly all of the federal tax benefits. These tax equity partnerships are consolidated in Southern Power's

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financial statements and are accounted for using HLBV methodology to allocate partnership gains and losses. During the first nine months of 2021, Southern Power obtained tax equity funding for the Deuel Harvest wind facility, the Garland and Tranquillity battery energy storage facilities, and existing tax equity partnerships totaling $256 million. See Note 1 to the financial statements under "General" in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.

By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. At September 30, 2021, 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.

Certain Registrants' current liabilities frequently exceed their current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. The Registrants generally plan to refinance long-term debt as it matures. The following table shows the amount by which current liabilities exceeded current assets at September 30, 2021 for the applicable Registrants:

At September 30, 2021	Southern Company		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Current liabilities in excess of current assets	$	1,585	$	1,152	$	5	$	743	$	92

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, 2021, the Registrants' unused committed credit arrangements with banks were as follows:

At September 30, 2021	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	$	1,250	$	1,726	$	250	$	568	$	1,747	$	30	$	7,570

(a)At September 30, 2021, Southern Power also had two continuing letters of credit facilities for standby letters of credit, of which $24 million was unused. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.

(b)Includes $1.047 billion and $700 million at Southern Company Gas Capital and Nicor Gas, respectively.

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

A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support at September 30, 2021 was approximately $1.6 billion (comprised of approximately $854 million at Alabama Power, $672 million at Georgia Power, and $34 million at Mississippi Power). In addition, at September 30, 2021, Georgia Power and Mississippi Power had approximately $262 million and $50 million, respectively, of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months.

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See Note 8 to the financial statements in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements herein under "Bank Credit Arrangements" for additional information.

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, 2021				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	$	707	0.4	%	$	1,331	0.3	%	$	1,716
Alabama Power	—		—		7		0.1		70
Georgia Power	—		—		81		0.2		310
Mississippi Power	—		—		—		—		—
Southern Power	27		0.2		66		0.2		123
Southern Company Gas:
Southern Company Gas Capital	$	72	0.2	%	$	325	0.2	%	$	484
Nicor Gas	590		0.4		451		0.5		590
Southern Company Gas Total	$	662	0.4	%	$	776	0.4	%

(*)Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2021.

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Analysis of Cash Flows

Net cash flows provided from (used for) operating, investing, and financing activities for the nine months ended September 30, 2021 and 2020 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, 2021
Operating activities	$	5,081	$	1,419	$	2,350	$	159	$	750	$	757
Investing activities	(5,850)		(1,335)		(2,572)		(182)		(753)		(966)
Financing activities	1,802		56		505		130		33		222
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)

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 decreased $139 million for the nine months ended September 30, 2021 as compared to the corresponding period in 2020 primarily due to decreased fuel cost recovery at the traditional electric operating companies resulting from an increase in the cost of fuel and under recovered natural gas costs at Southern Company Gas resulting from Winter Storm Uri, partially offset by the timing of vendor payments and customer bill credits issued in 2020 at Georgia Power.

The net cash used for investing activities for the nine months ended September 30, 2021 was primarily related to the Subsidiary Registrants' construction programs.

The net cash provided from financing activities for the nine months ended September 30, 2021 was primarily related to net issuances of long-term debt, partially offset by common stock dividend payments.

Alabama Power

Net cash provided from operating activities increased $190 million for the nine months ended September 30, 2021 as compared to the corresponding period in 2020 primarily due to an increase in retail revenues associated with a Rate RSE adjustment effective in January 2021 and higher customer usage, as well as the timing of fossil fuel stock purchases, partially offset by decreased fuel cost recovery.

The net cash used for investing activities for the nine months ended September 30, 2021 was primarily related to gross property additions.

The net cash provided from financing activities for the nine months ended September 30, 2021 was primarily related to capital contributions from Southern Company and the net issuance of long-term debt, partially offset by common stock dividend payments.

Georgia Power

Net cash provided from operating activities increased $225 million for the nine months ended September 30, 2021 as compared to the corresponding period in 2020 primarily due to customer bill credits issued in 2020 associated

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with Tax Reform and 2018 earnings in excess of the allowed retail ROE range, the timing of vendor payments, lower income tax payments, and the timing of customer receivable collections and fossil fuel stock purchases, partially offset by decreased fuel cost recovery.

The net cash used for investing activities for the nine months ended September 30, 2021 was primarily related to gross property additions, including a total of approximately $830 million related to the construction of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information on construction of Plant Vogtle Units 3 and 4.

The net cash provided from financing activities for the nine months ended September 30, 2021 was primarily related 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.

Mississippi Power

Net cash provided from operating activities decreased $27 million for the nine months ended September 30, 2021 as compared to the corresponding period in 2020 primarily due to decreased fuel cost recovery and the timing of receivable collections, partially offset by the timing of vendor payments.

The net cash used for investing activities for the nine months ended September 30, 2021 was primarily related to gross property additions.

The net cash provided from financing activities for the nine months ended September 30, 2021 was primarily related to the issuance of senior notes and capital contributions from Southern Company, partially offset by debt redemptions, common stock dividend payments, and a decrease in commercial paper borrowings.

Southern Power

Net cash provided from operating activities decreased $24 million for the nine months ended September 30, 2021 as compared to the corresponding period in 2020 primarily due to a decrease in the utilization of tax credits in 2021.

The net cash used for investing activities for the nine months ended September 30, 2021 was primarily related to the acquisition of the Deuel Harvest wind facility and ongoing construction activities. See Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.

The net cash provided from financing activities for the nine months ended September 30, 2021 was primarily related to the issuance of senior notes and net capital contributions from noncontrolling interests, partially offset by a return of capital to Southern Company, common stock dividend payments, and net repayments of commercial paper.

Southern Company Gas

Net cash provided from operating activities decreased $365 million for the nine months ended September 30, 2021 as compared to the corresponding period in 2020 primarily due to natural gas cost under recovery, reflecting an increase in the cost of gas purchased during Winter Storm Uri, and the timing of customer receivable collections, partially offset by the timing of vendor payments.

The net cash used for investing activities for the nine months ended September 30, 2021 was primarily related to construction of transportation and distribution assets recovered through base rates and infrastructure investment recovered through replacement programs at gas distribution operations, partially offset by proceeds from dispositions.

The net cash provided from financing activities for the nine months ended September 30, 2021 was primarily related to net issuances of long-term and short-term debt and capital contributions from Southern Company, partially offset by common stock dividend payments.

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Significant Balance Sheet Changes

Southern Company

Significant balance sheet changes for the nine months ended September 30, 2021 included:

•an increase of $3.5 billion in long-term debt (including securities due within one year) related to new issuances;

•an increase of $3.2 billion in total property, plant, and equipment primarily related to the Subsidiary Registrants' construction programs (net of pre-tax charges totaling $772 million recorded during 2021 at Georgia Power for estimated probable losses associated with the construction of Plant Vogtle Units 3 and 4);

•an increase of $1.0 billion in total stockholders' equity primarily related to net income, partially offset by common stock dividend payments;

•an increase of $1.0 billion in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Southern Company" herein;

•increases of $0.9 billion and $0.5 billion in AROs and regulatory assets associated with AROs, respectively, primarily related to cost estimate updates at the traditional electric operating companies for ash pond facilities;

•an increase of $0.7 billion in accumulated deferred income taxes primarily related to the utilization and expected further utilization of tax credits in 2021;

•decreases of $0.5 billion each in energy marketing receivables and payables due to Southern Company Gas' sale of Sequent; and

•an increase of $0.4 billion in natural gas cost under recovery, primarily resulting from Southern Company Gas' cost of gas purchased during Winter Storm Uri.

See "Financing Activities" herein and Notes (A), (B), (G), and (K) to the Condensed Financial Statements herein for additional information.

Alabama Power

Significant balance sheet changes for the nine months ended September 30, 2021 included:

•an increase of $1.1 billion in common stockholder's equity primarily due to capital contributions from Southern Company;

•an increase of $916 million in total property, plant, and equipment primarily related to construction of distribution and transmission facilities, increases to AROs, construction of Plant Barry Unit 8, and the installation of equipment to comply with environmental standards;

•an increase of $349 million in AROs primarily related to cost estimate updates for ash pond facilities; and

•an increase of $190 million in long-term debt (including securities due within one year) primarily due to a net increase in outstanding senior notes.

See "Financing Activities – Alabama Power" herein and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

Georgia Power

Significant balance sheet changes for the nine months ended September 30, 2021 included:

•an increase of $1.2 billion in total property, plant, and equipment primarily related to the construction of generation, transmission, and distribution facilities, including $217 million for Plant Vogtle Units 3 and 4 (net of pre-tax charges totaling $772 million recorded during 2021 for estimated probable losses);

•an increase of $0.9 billion in common stockholder's equity primarily due to capital contributions from Southern Company;

•an increase of $0.8 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;

•increases of $0.5 billion and $0.3 billion in AROs and regulatory assets associated with AROs, respectively, primarily due to cost estimate updates for ash pond closures; and

•an increase of $0.3 billion in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Georgia Power" herein.

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, 2021 included:

•an increase of $166 million in long-term debt (including securities due within one year) primarily due to the issuance of senior notes, partially offset by the redemption of revenue bonds and bank term loans;

•an increase of $121 million in common stockholder's equity related to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company; and

•an increase of $107 million in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Mississippi Power" herein.

See "Financing Activities – Mississippi Power" herein for additional information.

Southern Power

Significant balance sheet changes for the nine months ended September 30, 2021 included:

•an increase of $495 million in property, plant, and equipment in service primarily due to the acquisition of the Deuel Harvest wind facility;

•an increase of $323 million in long-term debt (including securities due within one year) primarily related to the issuance of senior notes;

•a decrease of $262 million in accumulated deferred income tax assets primarily related to the utilization of ITCs in 2021; and

•a decrease of $148 million in notes payable due to net repayments of commercial paper.

See "Financing Activities – Southern Power" herein and Notes (G) and (K) to the Condensed Financial Statements herein for additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

Southern Company Gas

Significant balance sheet changes for the nine months ended September 30, 2021 included:

•an increase of $776 million in total property, plant, and equipment primarily related to the construction of transportation and distribution assets recovered through base rates and infrastructure investment recovered through replacement programs;

•decreases of $516 million in energy marketing receivables and $494 million in energy marketing trade payables due to the sale of Sequent;

•an increase of $432 million in natural gas cost under recovery reflecting an increase in the cost of gas purchased during Winter Storm Uri;

•an increase of $338 million in notes payable due to issuances of short-term debt and an increase in commercial paper borrowings;

•an increase of $306 million in accumulated deferred income taxes primarily due to the increase in natural gas cost under recovery, as discussed above, and changes in state apportionment rates as a result of the sale of Sequent;

•a decrease of $265 million in customer accounts receivable due to the timing of collections; and

•an increase of $187 million in long-term debt (including securities due within one year) primarily due to net issuances of senior notes and first mortgage bonds.

See "Financing Activities – Southern Company Gas" herein and Notes (B) and (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

Financing Activities

The following table outlines the Registrants' long-term debt financing activities for the first nine months of 2021:

	Issuances/Reofferings						Maturities, Redemptions, and Repurchases
Company	Senior Notes		Revenue Bonds		Other Long-Term Debt		Senior Notes		Revenue Bonds		Other Long-Term Debt(a)
	(in millions)
Southern Company parent	$	1,000	$	—	$	2,476	$	1,500	$	—	$	—
Alabama Power	600		—		—		200		—		207
Georgia Power	750		122		371		325		69		83
Mississippi Power	525		—		—		—		270		75
Southern Power	400		—		—		—		—		—
Southern Company Gas	450		—		100		300		—		30
Other	—		—		—		—		—		8
Elimination(b)	—		—		—		—		—		(7)
Southern Company	$	3,725	$	122	$	2,947	$	2,325	$	339	$	396

(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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

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 2021, Southern Company issued approximately 3.3 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $62 million.

In January 2021, Southern Company borrowed $25 million pursuant to a short-term uncommitted bank credit arrangement, which it repaid in March 2021.

In February 2021, Southern Company issued $600 million aggregate principal amount of Series 2021A 0.60% Senior Notes due February 26, 2024 and $400 million aggregate principal amount of Series 2021B 1.75% Senior Notes due March 15, 2028.

In May 2021, Southern Company issued $1.0 billion aggregate principal amount of Series 2021A 3.75% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due September 15, 2051.

Also in May 2021, Southern Company redeemed all of its $1.5 billion aggregate principal amount of 2.35% Senior Notes due July 1, 2021.

In September 2021, Southern Company issued €1.25 billion (approximately $1.476 billion) aggregate principal amount of Series 2021B 1.875% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due September 15, 2081. Southern Company's obligations under these notes were effectively converted to fixed-rate U.S. dollars at issuance for the first six years through cross-currency swaps, mitigating foreign currency exchange risk associated with the interest and principal payments during this period. See Note (J) to the Condensed Financial Statements under "Foreign Currency Derivatives" herein for additional information.

Subsequent to September 30, 2021, Southern Company redeemed all $800 million aggregate principal amount of its Series 2016A 5.25% Junior Subordinated Notes due October 1, 2076.

Alabama Power

In March 2021, Alabama Power extended the maturity dates from March 2021 to March 2026 on its three bank term loan agreements with an aggregate principal amount of $45 million, bearing interest based on three-month LIBOR.

In June 2021, Alabama Power repaid at maturity $200 million aggregate principal amount of its Series 2011B 3.950% Senior Notes.

Also in June 2021, Alabama Power issued $600 million aggregate principal amount of Series 2021A 3.125% Senior Notes due July 15, 2051.

In July 2021, Alabama Power redeemed all of its approximately $206 million aggregate principal amount of Series E Junior Subordinated Notes due October 1, 2042. The Series E Junior Subordinated Notes were held by an affiliated trust, Alabama Power Capital Trust V, which applied the redemption proceeds to the simultaneous redemption of (i) its Flexible Trust Preferred Securities totaling approximately $200 million, which were guaranteed by Alabama Power, and (ii) shares of its common securities totaling approximately $6 million that were held by Alabama Power.

Subsequent to September 30, 2021, Alabama Power repaid at maturity $65 million aggregate principal amount of The Industrial Development Board of the Town of Columbia (Alabama) Tax Exempt Variable Rate Demand Revenue Bonds (Alabama Power Company Project), Series 1997.

Georgia Power

In February 2021, Georgia Power issued $750 million aggregate principal amount of Series 2021A 3.25% Senior Notes due March 15, 2051. An amount equal to the net proceeds of the senior notes is being allocated to finance or

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

refinance, in whole or in part, one or more renewable energy projects and/or expenditures and programs related to enabling opportunities for diverse and small businesses/suppliers.

In March 2021, Georgia Power redeemed all $325 million aggregate principal amount of its Series 2016B 2.40% Senior Notes due April 1, 2021.

Also in March 2021, Georgia Power extended the maturity date of its $125 million term loan from June 2021 to June 2022.

In June 2021, Georgia Power purchased and held approximately $69 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2008. In August 2021, Georgia Power reoffered these bonds to the public.

Also in June 2021, Georgia Power made additional borrowings under the FFB Credit Facilities in an aggregate principal amount of $371 million at an interest rate of 2.434% 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, 2021, Georgia Power made principal amortization payments of $75 million under the FFB Credit Facilities. At September 30, 2021, the outstanding principal balance under the FFB Credit Facilities was $4.9 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.

In August 2021, Georgia Power reoffered to the public $53 million aggregate principal amount of Development Authority of Floyd County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Hammond Project), First Series 2010, which it had previously purchased and held.

Mississippi Power

In June 2021, Mississippi Power issued $200 million aggregate principal amount of Series 2021A Floating Rate Senior Notes due June 28, 2024 and $325 million aggregate principal amount of Series 2021B 3.10% Senior Notes due July 30, 2051. An amount equal to the net proceeds of the Series 2021B Senior Notes is being allocated to finance or refinance, in whole or in part, one or more renewable energy projects and/or expenditures and programs related to enabling opportunities for diverse and small businesses/suppliers.

In July 2021, Mississippi Power redeemed all $270 million aggregate principal amount of its Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 20, 2021 at par plus accrued interest and a make-whole premium.

Also in July 2021, Mississippi Power repaid its $60 million and $15 million floating rate bank term loans, with maturity dates in December 2021 and January 2022, respectively.

Subsequent to September 30, 2021, Mississippi Power repaid $25 million previously borrowed under its $125 million revolving credit arrangement that matures in March 2023.

Southern Power

In January 2021, Southern Power issued $400 million aggregate principal amount of Series 2021A 0.90% Senior Notes due January 15, 2026. An amount equal to the net proceeds of the senior notes was allocated to finance or refinance, in whole or in part, one or more renewable energy projects.

Subsequent to September 30, 2021, Southern Power announced the planned redemption on November 15, 2021 of all $300 million aggregate principal amount of its Series 2016E 2.500% Senior Notes due December 15, 2021.

Southern Company Gas

In February 2021, Atlanta Gas Light repaid at maturity $30 million aggregate principal amount of 9.1% medium-term notes.

In March 2021, Nicor Gas entered into three short-term floating rate bank loans in an aggregate principal amount of $300 million, each bearing interest based on one-month LIBOR.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

In June 2021, Southern Company Gas Capital redeemed all $300 million aggregate principal amount of its 3.50% Senior Notes due September 15, 2021.

In August 2021, Nicor Gas issued in a private placement $50 million aggregate principal amount of 1.42% Series First Mortgage Bonds due August 31, 2026 and $50 million aggregate principal amount of 2.19% Series First Mortgage Bonds due August 31, 2033. Nicor Gas also entered into an agreement to issue in a private placement additional first mortgage bonds with aggregate principal amounts of $100 million, which were issued subsequent to September 30, 2021, and $100 million and $75 million expected to be issued in August 2022 and October 2022, respectively.

In September 2021, Southern Company Gas Capital, as borrower, and Southern Company Gas, as guarantor, issued $450 million aggregate principal amount of Series 2021A 3.15% Senior Notes due September 30, 2051.

Credit Rating Risk

At September 30, 2021, the Registrants did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain Registrants to BBB and/or Baa2 or below. These contracts are primarily for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and, for Georgia Power, construction of new generation at Plant Vogtle Units 3 and 4.

The maximum potential collateral requirements under these contracts at September 30, 2021 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	$	43	$	1	$	—	$	—	$	42	$	—
At BBB- and/or Baa3	416		2		61		1		354		—
At BB+ and/or Ba1 or below	1,934		394		953		308		1,195		5

(*)Southern Power has PPAs that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPAs require credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade. Southern Power had $105 million of cash collateral posted related to PPA requirements at September 30, 2021.

The amounts in the previous table for the traditional electric operating companies and Southern Power include certain agreements that could require collateral if either Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Registrants to access capital markets and would be likely to impact the cost at which they do so.

On October 27, 2021, S&P downgraded the Southern Company issuer credit rating to BBB+ from A-. Due to S&P's consolidated rating methodology, the downgrade of Southern Company's issuer credit rating resulted in the downgrade of the senior unsecured long-term debt rating of Alabama Power and the long-term issuer rating of Nicor Gas to A- from A, the senior unsecured long-term debt ratings of Atlanta Gas Light, Georgia Power, Mississippi Power, and Southern Company Gas Capital to BBB+ from A-, and the senior unsecured long-term debt ratings of Southern Company and Southern Power to BBB from BBB+. S&P revised its credit rating outlook for Southern Company and its subsidiaries 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 2021. For an in-depth discussion of Southern Company

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

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 Notes (I) and (J) to the Condensed Financial Statements herein for information relating to derivative instruments. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for information regarding Southern Company Gas' sale of Sequent on July 1, 2021.

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 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 of Southern Company Gas' non-regulated operations (primarily Sequent until its sale on July 1, 2021) 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.

The changes in net fair value of Southern Company Gas' energy-related derivative contracts for the periods presented are provided in the table below.

	Third Quarter 2021		Third Quarter 2020		Year-To-Date 2021		Year-To-Date 2020
	(in millions)
Contracts outstanding at beginning of period, assets (liabilities), net	$	(44)	$	49	$	101	$	70
Contracts realized or otherwise settled	(10)		(31)		(68)		(130)
Current period changes(*)	62		—		(25)		78
Sale of Sequent	76		—		76		—
Contracts outstanding at the end of period, assets (liabilities), net	$	84	$	18	$	84	$	18
Netting of cash collateral	(20)		70		(20)		70
Cash collateral and net fair value of contracts outstanding at end of period	$	64	$	88	$	64	$	88

(*)Current period changes also include the fair value of new contracts entered into during the period, if any.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk.

During the nine months ended September 30, 2021, 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. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for information regarding Southern Company Gas' sale of Sequent on July 1, 2021. 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, Southern Power's, or Southern Company Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the third quarter 2021 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting.

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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. The Registrants' threshold for disclosing material environmental legal proceedings involving a governmental authority where potential monetary sanctions are involved is $1 million.

Item 1A. Risk Factors.

See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the Registrants. There have been no material changes to these risk factors from those previously disclosed in the Form 10-K.

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)	-	Twelfth Supplemental Indenture to Subordinated Note Indenture dated as of September 16, 2021, providing for the issuance of the Series 2021B 1.875% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due September 15, 2081. (Designated in Form 8-K dated September 13, 2021, File No. 1-3526, as Exhibit 4.4)
		Southern Company Gas
		(f)1	-	Southern Company Gas Capital Corporation's Series 2021A 3.15% Senior Notes due September 30, 2051, Form of Note. (Designated in Form 8-K dated September 7, 2021, File No. 1-14174, as Exhibit 4.1)
		(f)2	-	First Supplemental Indenture to Indenture dated as of September 9, 2021 providing for amendments to the Indenture. (Designated in Form 8-K dated September 7, 2021, File No. 1-14174, as Exhibit 4.2)
		(f)3	-	Southern Company Gas' Guarantee related to the Series 2021A 3.15% Senior Notes due September 30, 2051, Form of Guarantee. (Designated in Form 8-K dated September 7, 2021, File No. 1-14174, as Exhibit 4.3)
	*	(f)4	-	Supplemental Indenture dated as of August 10, 2021 of Northern Illinois Gas Company to U.S. Bank National Association under Indenture dated as of January 1, 1954.
		(10) Material Contracts
		Southern Company
#	*	(a)	-	Consulting Agreement between SCS and Andrew W. Evans dated August 23, 2021.
		(24) Power of Attorney and Resolutions
		Southern Company
		(a)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2020, File No. 1-3526 as Exhibit 24(a).)
	*	(a)2	-	Power of Attorney of Daniel S. Tucker.
		Alabama Power
		(b)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2020, File No. 1-3164 as Exhibit 24(b).)

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	Georgia Power
	(c)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2020, File No. 1-6468 as Exhibit 24(c)1.)
*	(c)2	-	Power of Attorney of Aaron P. Abramovitz.
	Mississippi Power
	(d)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2020, File No. 001-11229 as Exhibit 24(d)1.)
	Southern Power
	(e)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2020, File No. 001-37803 as Exhibit 24(e)1.)
	Southern Company Gas
	(f)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2020, File No. 1-14174 as Exhibit 24(f)1.)
	(f)2	-	Power of Attorney of David P. Poroch. (Designated in the Form 10-K for the year ended December 31, 2020, File No. 1-14174 as Exhibit 24(f)2.)
	(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.

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	Southern Company Gas
*	(f)1	-	Certificate of Southern Company Gas' Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(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	Daniel S. Tucker
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: November 3, 2021

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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: November 3, 2021

167

    Table of Contents                                Index to Financial Statements

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	Christopher C. Womack
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	Aaron P. Abramovitz
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: November 3, 2021

168

    Table of Contents                                Index to Financial Statements

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: November 3, 2021

169

    Table of Contents                                Index to Financial Statements

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
	Chairman and 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: November 3, 2021

170

    Table of Contents                                Index to Financial Statements

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	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: November 3, 2021

171

EX-4.F4

Exhibit 4(f)4

When recorded return to:
Michael M. Roth, Esq.
Ice Miller LLP
2300 Cabot Drive
Suite 455
Lisle, IL 60532
	Space Above this Line Reserved for Recorder’s Use Only

Supplemental Indenture

Made as of August 10, 2021, to be Effective August 31, 2021
____________________

Northern Illinois Gas Company

to

U.S. Bank National Association

Trustee under Indenture dated as of

January 1, 1954

and

Supplemental Indentures Thereto

____________________

FIRST MORTGAGE BONDS 1.42% SERIES DUE AUGUST 31, 2026

FIRST MORTGAGE BONDS 1.77% SERIES DUE OCTOBER 28, 2028

FIRST MORTGAGE BONDS 2.21% SERIES DUE AUGUST 31, 2032

FIRST MORTGAGE BONDS 2.19% SERIES DUE AUGUST 31, 2033

FIRST MORTGAGE BONDS 3.18% SERIES DUE OCTOBER 27, 2062

This Supplemental Indenture, made as of August 10, 2021 and effective August 31, 2021, between Northern Illinois Gas Company, a corporation organized and existing under the laws of the State of Illinois (hereinafter called the “Company”), and U.S. Bank National Association (hereinafter called the “Trustee”), as successor Trustee under an Indenture dated as of January 1, 1954, as modified by the Indenture of Adoption, dated February 9, 1954 and the Indenture of Release, dated February 9, 1954, and as supplemented by Supplemental Indentures dated (or made effective) April 1, 1956, June 1, 1959, July 1, 1960, June 1, 1963, July 1, 1963, August 1, 1964, August 1, 1965, May 1, 1966, August 1, 1966, July 1, 1967, June 1, 1968, December 1, 1969, August 1, 1970, June 1, 1971, July 1, 1972, July 1, 1973, April 1, 1975, April 30, 1976 (two Supplemental Indentures bearing that date), July 1, 1976, August 1, 1976, December 1, 1977, January 15, 1979, December 1, 1981, March 1, 1983, October 1, 1984, December 1, 1986, March 15, 1988, July 1, 1988, July 1, 1989, July 15, 1990, August 15, 1991, July 15, 1992, February 1, 1993, March 15, 1993, May 1, 1993, July 1, 1993, August 15, 1994, October 15, 1995, May 10, 1996, August 1, 1996, June 1, 1997, October 15, 1997, February 15, 1998, June 1, 1998, February 1, 1999, February 1, 2001, May 15, 2001, August 15, 2001, December 15, 2001, December 1, 2003 (three Supplemental Indentures bearing that date), December 15, 2006, August 15, 2008, July 30, 2009, February 1, 2011, October 26, 2012, June 23, 2016, August 10, 2017, August 16, 2018, August 30, 2019 and August 31, 2020, such Indenture dated as of January 1, 1954, as so modified and supplemented, being hereinafter called the “Indenture.”

Witnesseth:

Whereas, the Indenture provides for the issuance from time to time thereunder, in series, of bonds of the Company for the purposes and subject to the limitations therein specified; and

Whereas, the Company desires, by this Supplemental Indenture, to create five additional series of bonds to be issuable under the Indenture, such bonds to be designated, respectively, (a) “First Mortgage Bonds 1.42% Series due August 31, 2026” (hereinafter called the “2026 Series”), (b) “First Mortgage Bonds 1.77% Series due October 28, 2028” (hereinafter called the “2028 Series”), (c) “First Mortgage Bonds 2.21% Series due August 31, 2032” (hereinafter called the “2032 Series”), (d) “First Mortgage Bonds 2.19% Series due August 31, 2033” (hereinafter called the “2033 Series”), and (e) “First Mortgage Bonds 3.18% Series due October 27, 2062” (hereinafter called the “2062 Series”; the 2026 Series, the 2028 Series, the 2032 Series, the 2033 Series and the 2062 Series, hereinafter called, collectively, the “bonds of this Supplemental Indenture”), and the terms and provisions to be contained in the bonds of this Supplemental Indenture or to be otherwise applicable thereto to be as set forth in this Supplemental Indenture; and

Whereas, the forms, respectively, of the bonds of this Supplemental Indenture, and the Trustee’s certificate to be endorsed on all bonds of this Supplemental Indenture, are to be substantially as follows:

[Remainder of Page Intentionally Left Blank]

1

(Form of Face of Bond of 2026 Series)

NO. RU-2021-A-__	$________
Ill. Commerce Commission Nos. 6834 and 6856	CUSIP No._____________

Northern Illinois Gas Company

First Mortgage Bond 1.42% Series due August 31, 2026

Northern Illinois Gas Company, an Illinois corporation (hereinafter called the “Company”), for value received, hereby promises to pay to                      or registered assigns, the sum of                           Dollars, on August 31, 2026, and to pay to the registered owner hereof interest on said sum from the date hereof until said sum shall be paid, at the rate of 1.42% per annum, payable semi-annually on the twentieth day of February and the twentieth day of August in each year, beginning on February 20, 2022, except that the interest payment otherwise payable on August 20, 2026 will be payable on August 31, 2026. Both the principal of and the interest on this bond shall be payable at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of the registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York, in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts. Any installment of interest on this bond may, at the Company’s option, be paid by mailing checks for such interest payable to or upon the written order of the person entitled thereto to the address of such person as it appears on the registration books.

So long as there is no existing default in the payment of interest on this bond, the interest so payable on any interest payment date will be paid to the person in whose name this bond is registered on February 5 or August 5 (whether or not a business day), as the case may be, next preceding such interest payment date. If and to the extent that the Company shall default in the payment of interest due on such interest payment date, such defaulted interest shall be paid to the person in whose name this bond is registered on the record date fixed, in advance, by the Company for the payment of such defaulted interest.

Additional provisions of this bond are set forth on the reverse hereof.

This bond shall not be entitled to any security or benefit under the Indenture or be valid or become obligatory for any purpose unless and until it shall have been authenticated by the execution by the Trustee, or its successor in trust under the Indenture, of the certificate endorsed hereon.

2

In Witness Whereof, Northern Illinois Gas Company has caused this bond to be executed in its name by its Executive Vice President, Chief Financial Officer and Treasurer, manually or by facsimile signature, and has caused its corporate seal to be impressed hereon or a facsimile thereof to be imprinted hereon and to be attested by its Corporate Secretary, manually or by facsimile signature.

Dated: August 31, 2021

	Northern Illinois Gas Company By:___________________________________ Executive Vice President, Chief Financial Officer and Treasurer
Attest: ____________________________________     Corporate Secretary

3

(Form of Trustee’s Certificate of Authentication)

This bond is one of the bonds of the 2026 Series designated therein, referred to and described in the within-mentioned Supplemental Indenture dated as of August 10, 2021, effective August 31, 2021.

U.S. Bank National Association,
   Trustee

By:_________________________________
    Authorized Officer

Dated: August 31, 2021

4

(Form of Reverse Side of Bond of 2026 Series)

This bond is one, of the series hereinafter specified, of the bonds issued and to be issued in series from time to time under and in accordance with and secured by an Indenture dated as of January 1, 1954, to U.S. Bank National Association, as Trustee, as supplemented by certain indentures supplemental thereto, executed and delivered to the Trustee; and this bond is one of a series of such bonds, designated “Northern Illinois Gas Company First Mortgage Bond 1.42% Series due August 31, 2026” (herein called “bonds of this Series”), the issuance of which is provided for by a Supplemental Indenture dated as of August 10, 2021, effective August 31, 2021 (hereinafter called the “Supplemental Indenture”), executed and delivered by the Company to the Trustee. The term “Indenture”, as hereinafter used, means said Indenture dated as of January 1, 1954, and all indentures supplemental thereto (including, without limitation, the Supplemental Indenture) from time to time in effect. Reference is made to the Indenture for a description of the property mortgaged and pledged, the nature and extent of the security, the rights of the holders and registered owners of said bonds, of the Company and of the Trustee in respect of the security, and the terms and conditions governing the issuance and security of said bonds.

Any transferee, by its acceptance of a bond registered in its name (or the name of its nominee), shall be deemed to have made the representation set forth in Section 6.2 of the Bond Purchase Agreement dated as of August 10, 2021 among the Company and the purchasers listed on Schedule A attached thereto, as amended, restated, supplemented or otherwise modified from time to time.

With the consent of the Company and to the extent permitted by and as provided in the Indenture, modifications or alterations of the Indenture or of any supplemental indenture and of the rights and obligations of the Company and of the holders and registered owners of the bonds may be made, and compliance with any provision of the Indenture or of any supplemental indenture may be waived, by the affirmative vote of the holders and registered owners of not less than sixty-six and two-thirds per centum (66 2/3%) in principal amount of the bonds then outstanding under the Indenture, and by the affirmative vote of the holders and registered owners of not less than sixty-six and two-thirds per centum (66 2/3%) in principal amount of the bonds of any series then outstanding under the Indenture and affected by such modification or alteration, in case one or more but less than all of the series of bonds then outstanding under the Indenture are so affected, but in any case excluding bonds disqualified from voting by reason of the Company’s interest therein as provided in the Indenture; subject, however, to the condition, among other conditions stated in the Indenture, that no such modification or alteration shall be made which, among other things, will permit the extension of the time or times of payment of the principal of or the interest or the premium, if any, on this bond, or the reduction in the principal amount hereof or in the rate of interest or the amount of any premium hereon, or any other modification in the terms of payment of such principal, interest or premium, which terms of payment are unconditional, or, otherwise than as permitted by the Indenture, the creation of any lien ranking prior to or on a parity with the lien of the Indenture with respect to any of the mortgaged property, all as more fully provided in the Indenture.

The bonds of this Series may be called for redemption by the Company, as a whole at any time or in part from time to time, at a redemption price equal to 100% of the principal amount of the bonds of this Series to be redeemed plus accrued and unpaid interest on the principal amount

5

being redeemed to the date of redemption and the Make-Whole Amount (as defined in the Supplemental Indenture) applicable thereto.

Notice of each redemption shall be mailed to all registered owners not less than thirty nor more than forty-five days before the redemption date.

In case of certain completed defaults specified in the Indenture, the principal of this bond may be declared or may become due and payable in the manner and with the effect provided in the Indenture.

No recourse shall be had for the payment of the principal of or the interest or the premium, if any, on this bond, or for any claim based hereon, or otherwise in respect hereof or of the Indenture, to or against any incorporator, stockholder, officer or director, past, present or future, of the Company or of any predecessor or successor corporation, either directly or through the Company or such predecessor or successor corporation, under any constitution or statute or rule of law, or by the enforcement of any assessment or penalty, or otherwise, all such liability of incorporators, stockholders, directors and officers being waived and released by the registered owner hereof by the acceptance of this bond and being likewise waived and released by the terms of the Indenture, all as more fully provided therein.

This bond is transferable by the registered owner hereof, in person or by duly authorized attorney, at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of the registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York, upon surrender and cancellation of this bond; and thereupon a new registered bond or bonds without coupons of the same aggregate principal amount and series will, upon the payment of any transfer tax or taxes payable, be issued to the transferee in exchange herefor. The Company shall not be required to exchange or transfer this bond if this bond or a portion hereof has been selected for redemption.

The security represented by this certificate has not been registered under the Securities Act of 1933, as amended (the “Securities Act”), or qualified under any state securities laws and may not be transferred, sold or otherwise disposed of except while a registration statement is in effect or pursuant to an available exemption from registration under the Securities Act and applicable state securities laws.

(End of Form of Bond of 2026 Series)

6

(Form of Face of Bond of 2028 Series)

NO. RU-2021-B-__	$________
Ill. Commerce Commission Nos. 6857	CUSIP No._____________

Northern Illinois Gas Company

First Mortgage Bond 1.77% Series due October 28, 2028

Northern Illinois Gas Company, an Illinois corporation (hereinafter called the “Company”), for value received, hereby promises to pay to                      or registered assigns, the sum of                           Dollars, on October 28, 2028, and to pay to the registered owner hereof interest on said sum from the date hereof until said sum shall be paid, at the rate of 1.77% per annum, payable semi-annually on the twentieth day of April and the twentieth day of October in each year, beginning on April 20, 2022, except that the interest payment otherwise payable on October 20, 2028 will be payable on October 28, 2028. Both the principal of and the interest on this bond shall be payable at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of the registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York, in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts. Any installment of interest on this bond may, at the Company’s option, be paid by mailing checks for such interest payable to or upon the written order of the person entitled thereto to the address of such person as it appears on the registration books.

So long as there is no existing default in the payment of interest on this bond, the interest so payable on any interest payment date will be paid to the person in whose name this bond is registered on April 5 or October 5 (whether or not a business day), as the case may be, next preceding such interest payment date. If and to the extent that the Company shall default in the payment of interest due on such interest payment date, such defaulted interest shall be paid to the person in whose name this bond is registered on the record date fixed, in advance, by the Company for the payment of such defaulted interest.

Additional provisions of this bond are set forth on the reverse hereof.

This bond shall not be entitled to any security or benefit under the Indenture or be valid or become obligatory for any purpose unless and until it shall have been authenticated by the execution by the Trustee, or its successor in trust under the Indenture, of the certificate endorsed hereon.

7

In Witness Whereof, Northern Illinois Gas Company has caused this bond to be executed in its name by its Executive Vice President, Chief Financial Officer and Treasurer, manually or by facsimile signature, and has caused its corporate seal to be impressed hereon or a facsimile thereof to be imprinted hereon and to be attested by its Corporate Secretary, manually or by facsimile signature.

Dated: October 28, 2021

	Northern Illinois Gas Company By:__________________________________ Executive Vice President, Chief Financial Officer and Treasurer
Attest: _____________________________________     Corporate Secretary

8

(Form of Trustee’s Certificate of Authentication)

This bond is one of the bonds of the 2028 Series designated therein, referred to and described in the within-mentioned Supplemental Indenture dated as of August 10, 2021, effective August 31, 2021.

U.S. Bank National Association,
   Trustee

By:______________________________
    Authorized Officer

Dated: October 28, 2021

9

(Form of Reverse Side of Bond of 2028 Series)

This bond is one, of the series hereinafter specified, of the bonds issued and to be issued in series from time to time under and in accordance with and secured by an Indenture dated as of January 1, 1954, to U.S. Bank National Association, as Trustee, as supplemented by certain indentures supplemental thereto, executed and delivered to the Trustee; and this bond is one of a series of such bonds, designated “Northern Illinois Gas Company First Mortgage Bond 1.77% Series due October 28, 2028” (herein called “bonds of this Series”), the issuance of which is provided for by a Supplemental Indenture dated as of August 10, 2021, effective August 31, 2021 (hereinafter called the “Supplemental Indenture”), executed and delivered by the Company to the Trustee. The term “Indenture”, as hereinafter used, means said Indenture dated as of January 1, 1954, and all indentures supplemental thereto (including, without limitation, the Supplemental Indenture) from time to time in effect. Reference is made to the Indenture for a description of the property mortgaged and pledged, the nature and extent of the security, the rights of the holders and registered owners of said bonds, of the Company and of the Trustee in respect of the security, and the terms and conditions governing the issuance and security of said bonds.

Any transferee, by its acceptance of a bond registered in its name (or the name of its nominee), shall be deemed to have made the representation set forth in Section 6.2 of the Bond Purchase Agreement dated as of August 10, 2021 among the Company and the purchasers listed on Schedule A attached thereto, as amended, restated, supplemented or otherwise modified from time to time.

With the consent of the Company and to the extent permitted by and as provided in the Indenture, modifications or alterations of the Indenture or of any supplemental indenture and of the rights and obligations of the Company and of the holders and registered owners of the bonds may be made, and compliance with any provision of the Indenture or of any supplemental indenture may be waived, by the affirmative vote of the holders and registered owners of not less than sixty-six and two-thirds per centum (66 2/3%) in principal amount of the bonds then outstanding under the Indenture, and by the affirmative vote of the holders and registered owners of not less than sixty-six and two-thirds per centum (66 2/3%) in principal amount of the bonds of any series then outstanding under the Indenture and affected by such modification or alteration, in case one or more but less than all of the series of bonds then outstanding under the Indenture are so affected, but in any case excluding bonds disqualified from voting by reason of the Company’s interest therein as provided in the Indenture; subject, however, to the condition, among other conditions stated in the Indenture, that no such modification or alteration shall be made which, among other things, will permit the extension of the time or times of payment of the principal of or the interest or the premium, if any, on this bond, or the reduction in the principal amount hereof or in the rate of interest or the amount of any premium hereon, or any other modification in the terms of payment of such principal, interest or premium, which terms of payment are unconditional, or, otherwise than as permitted by the Indenture, the creation of any lien ranking prior to or on a parity with the lien of the Indenture with respect to any of the mortgaged property, all as more fully provided in the Indenture.

The bonds of this Series may be called for redemption by the Company, as a whole at any time or in part from time to time, at a redemption price equal to 100% of the principal amount of the bonds of this Series to be redeemed plus accrued and unpaid interest on the principal amount

10

being redeemed to the date of redemption and the Make-Whole Amount (as defined in the Supplemental Indenture) applicable thereto.

Notice of each redemption shall be mailed to all registered owners not less than thirty nor more than forty-five days before the redemption date.

In case of certain completed defaults specified in the Indenture, the principal of this bond may be declared or may become due and payable in the manner and with the effect provided in the Indenture.

No recourse shall be had for the payment of the principal of or the interest or the premium, if any, on this bond, or for any claim based hereon, or otherwise in respect hereof or of the Indenture, to or against any incorporator, stockholder, officer or director, past, present or future, of the Company or of any predecessor or successor corporation, either directly or through the Company or such predecessor or successor corporation, under any constitution or statute or rule of law, or by the enforcement of any assessment or penalty, or otherwise, all such liability of incorporators, stockholders, directors and officers being waived and released by the registered owner hereof by the acceptance of this bond and being likewise waived and released by the terms of the Indenture, all as more fully provided therein.

This bond is transferable by the registered owner hereof, in person or by duly authorized attorney, at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of the registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York, upon surrender and cancellation of this bond; and thereupon a new registered bond or bonds without coupons of the same aggregate principal amount and series will, upon the payment of any transfer tax or taxes payable, be issued to the transferee in exchange herefor. The Company shall not be required to exchange or transfer this bond if this bond or a portion hereof has been selected for redemption.

The security represented by this certificate has not been registered under the Securities Act of 1933, as amended (the “Securities Act”), or qualified under any state securities laws and may not be transferred, sold or otherwise disposed of except while a registration statement is in effect or pursuant to an available exemption from registration under the Securities Act and applicable state securities laws.

(End of Form of Bond of 2028 Series)

11

(Form of Face of Bond of 2032 Series)

NO. RU-2022-A-__	$________
Ill. Commerce Commission Nos. 6858	CUSIP No._____________

Northern Illinois Gas Company

First Mortgage Bond 2.21% Series due August 31, 2032

Northern Illinois Gas Company, an Illinois corporation (hereinafter called the “Company”), for value received, hereby promises to pay to                      or registered assigns, the sum of                           Dollars, on August 31, 2032, and to pay to the registered owner hereof interest on said sum from the date hereof until said sum shall be paid, at the rate of 2.21% per annum, payable semi-annually on the twentieth day of February and the twentieth day of August in each year, beginning on February 20, 2023, except that the interest payment otherwise payable on August 20, 2032 will be payable on August 31, 2032. Both the principal of and the interest on this bond shall be payable at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of the registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York, in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts. Any installment of interest on this bond may, at the Company’s option, be paid by mailing checks for such interest payable to or upon the written order of the person entitled thereto to the address of such person as it appears on the registration books.

So long as there is no existing default in the payment of interest on this bond, the interest so payable on any interest payment date will be paid to the person in whose name this bond is registered on February 5 or August 5 (whether or not a business day), as the case may be, next preceding such interest payment date. If and to the extent that the Company shall default in the payment of interest due on such interest payment date, such defaulted interest shall be paid to the person in whose name this bond is registered on the record date fixed, in advance, by the Company for the payment of such defaulted interest.

Additional provisions of this bond are set forth on the reverse hereof.

This bond shall not be entitled to any security or benefit under the Indenture or be valid or become obligatory for any purpose unless and until it shall have been authenticated by the execution by the Trustee, or its successor in trust under the Indenture, of the certificate endorsed hereon.

12

In Witness Whereof, Northern Illinois Gas Company has caused this bond to be executed in its name by its Executive Vice President, Chief Financial Officer and Treasurer, manually or by facsimile signature, and has caused its corporate seal to be impressed hereon or a facsimile thereof to be imprinted hereon and to be attested by its Corporate Secretary, manually or by facsimile signature.

Dated: August 31, 2022

	Northern Illinois Gas Company By:___________________________________ Executive Vice President, Chief Financial Officer and Treasurer
Attest: _____________________________________     Corporate Secretary

13

(Form of Trustee’s Certificate of Authentication)

This bond is one of the bonds of the 2032 Series designated therein, referred to and described in the within-mentioned Supplemental Indenture dated as of August 10, 2021, effective August 31, 2021.

U.S. Bank National Association,
   Trustee

By:________________________________
    Authorized Officer

Dated: August 31, 2022

14

(Form of Reverse Side of Bond of 2032 Series)

This bond is one, of the series hereinafter specified, of the bonds issued and to be issued in series from time to time under and in accordance with and secured by an Indenture dated as of January 1, 1954, to U.S. Bank National Association, as Trustee, as supplemented by certain indentures supplemental thereto, executed and delivered to the Trustee; and this bond is one of a series of such bonds, designated “Northern Illinois Gas Company First Mortgage Bond 2.21% Series due August 31, 2032” (herein called “bonds of this Series”), the issuance of which is provided for by a Supplemental Indenture dated as of August 10, 2021, effective August 31, 2021 (hereinafter called the “Supplemental Indenture”), executed and delivered by the Company to the Trustee. The term “Indenture”, as hereinafter used, means said Indenture dated as of January 1, 1954, and all indentures supplemental thereto (including, without limitation, the Supplemental Indenture) from time to time in effect. Reference is made to the Indenture for a description of the property mortgaged and pledged, the nature and extent of the security, the rights of the holders and registered owners of said bonds, of the Company and of the Trustee in respect of the security, and the terms and conditions governing the issuance and security of said bonds.

Any transferee, by its acceptance of a bond registered in its name (or the name of its nominee), shall be deemed to have made the representation set forth in Section 6.2 of the Bond Purchase Agreement dated as of August 10, 2021 among the Company and the purchasers listed on Schedule A attached thereto, as amended, restated, supplemented or otherwise modified from time to time.

With the consent of the Company and to the extent permitted by and as provided in the Indenture, modifications or alterations of the Indenture or of any supplemental indenture and of the rights and obligations of the Company and of the holders and registered owners of the bonds may be made, and compliance with any provision of the Indenture or of any supplemental indenture may be waived, by the affirmative vote of the holders and registered owners of not less than sixty-six and two-thirds per centum (66 2/3%) in principal amount of the bonds then outstanding under the Indenture, and by the affirmative vote of the holders and registered owners of not less than sixty-six and two-thirds per centum (66 2/3%) in principal amount of the bonds of any series then outstanding under the Indenture and affected by such modification or alteration, in case one or more but less than all of the series of bonds then outstanding under the Indenture are so affected, but in any case excluding bonds disqualified from voting by reason of the Company’s interest therein as provided in the Indenture; subject, however, to the condition, among other conditions stated in the Indenture, that no such modification or alteration shall be made which, among other things, will permit the extension of the time or times of payment of the principal of or the interest or the premium, if any, on this bond, or the reduction in the principal amount hereof or in the rate of interest or the amount of any premium hereon, or any other modification in the terms of payment of such principal, interest or premium, which terms of payment are unconditional, or, otherwise than as permitted by the Indenture, the creation of any lien ranking prior to or on a parity with the lien of the Indenture with respect to any of the mortgaged property, all as more fully provided in the Indenture.

The bonds of this Series may be called for redemption by the Company, as a whole at any time or in part from time to time, at a redemption price equal to 100% of the principal amount of the bonds of this Series to be redeemed plus accrued and unpaid interest on the principal amount

15

being redeemed to the date of redemption and the Make-Whole Amount (as defined in the Supplemental Indenture) applicable thereto.

Notice of each redemption shall be mailed to all registered owners not less than thirty nor more than forty-five days before the redemption date.

In case of certain completed defaults specified in the Indenture, the principal of this bond may be declared or may become due and payable in the manner and with the effect provided in the Indenture.

No recourse shall be had for the payment of the principal of or the interest or the premium, if any, on this bond, or for any claim based hereon, or otherwise in respect hereof or of the Indenture, to or against any incorporator, stockholder, officer or director, past, present or future, of the Company or of any predecessor or successor corporation, either directly or through the Company or such predecessor or successor corporation, under any constitution or statute or rule of law, or by the enforcement of any assessment or penalty, or otherwise, all such liability of incorporators, stockholders, directors and officers being waived and released by the registered owner hereof by the acceptance of this bond and being likewise waived and released by the terms of the Indenture, all as more fully provided therein.

This bond is transferable by the registered owner hereof, in person or by duly authorized attorney, at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of the registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York, upon surrender and cancellation of this bond; and thereupon a new registered bond or bonds without coupons of the same aggregate principal amount and series will, upon the payment of any transfer tax or taxes payable, be issued to the transferee in exchange herefor. The Company shall not be required to exchange or transfer this bond if this bond or a portion hereof has been selected for redemption.

The security represented by this certificate has not been registered under the Securities Act of 1933, as amended (the “Securities Act”), or qualified under any state securities laws and may not be transferred, sold or otherwise disposed of except while a registration statement is in effect or pursuant to an available exemption from registration under the Securities Act and applicable state securities laws.

(End of Form of Bond of 2032 Series)

16

(Form of Face of Bond of 2033 Series)

NO. RU-2021-C-__	$________
Ill. Commerce Commission Nos. 6859	CUSIP No._____________

Northern Illinois Gas Company

First Mortgage Bond 2.19% Series due August 31, 2033

Northern Illinois Gas Company, an Illinois corporation (hereinafter called the “Company”), for value received, hereby promises to pay to                      or registered assigns, the sum of                           Dollars, on August 31, 2033, and to pay to the registered owner hereof interest on said sum from the date hereof until said sum shall be paid, at the rate of 2.19% per annum, payable semi-annually on the twentieth day of February and the twentieth day of August in each year, beginning on February 20, 2022, except that the interest payment otherwise payable on August 20, 2033 will be payable on August 31, 2033. Both the principal of and the interest on this bond shall be payable at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of the registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York, in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts. Any installment of interest on this bond may, at the Company’s option, be paid by mailing checks for such interest payable to or upon the written order of the person entitled thereto to the address of such person as it appears on the registration books.

So long as there is no existing default in the payment of interest on this bond, the interest so payable on any interest payment date will be paid to the person in whose name this bond is registered on February 5 or August 5 (whether or not a business day), as the case may be, next preceding such interest payment date. If and to the extent that the Company shall default in the payment of interest due on such interest payment date, such defaulted interest shall be paid to the person in whose name this bond is registered on the record date fixed, in advance, by the Company for the payment of such defaulted interest.

Additional provisions of this bond are set forth on the reverse hereof.

This bond shall not be entitled to any security or benefit under the Indenture or be valid or become obligatory for any purpose unless and until it shall have been authenticated by the execution by the Trustee, or its successor in trust under the Indenture, of the certificate endorsed hereon.

17

In Witness Whereof, Northern Illinois Gas Company has caused this bond to be executed in its name by its Executive Vice President, Chief Financial Officer and Treasurer, manually or by facsimile signature, and has caused its corporate seal to be impressed hereon or a facsimile thereof to be imprinted hereon and to be attested by its Corporate Secretary, manually or by facsimile signature.

Dated: August 31, 2021

	Northern Illinois Gas Company By:___________________________________ Executive Vice President, Chief Financial Officer and Treasurer
Attest: ______________________________________     Corporate Secretary

18

(Form of Trustee’s Certificate of Authentication)

This bond is one of the bonds of the 2033 Series designated therein, referred to and described in the within-mentioned Supplemental Indenture dated as of August 10, 2021, effective August 31, 2021.

U.S. Bank National Association,
   Trustee

By: _________________________________
    Authorized Officer

Dated: August 31, 2021

19

(Form of Reverse Side of Bond of 2033 Series)

This bond is one, of the series hereinafter specified, of the bonds issued and to be issued in series from time to time under and in accordance with and secured by an Indenture dated as of January 1, 1954, to U.S. Bank National Association, as Trustee, as supplemented by certain indentures supplemental thereto, executed and delivered to the Trustee; and this bond is one of a series of such bonds, designated “Northern Illinois Gas Company First Mortgage Bond 2.19% Series due August 31, 2033” (herein called “bonds of this Series”), the issuance of which is provided for by a Supplemental Indenture dated as of August 10, 2021, effective August 31, 2021 (hereinafter called the “Supplemental Indenture”), executed and delivered by the Company to the Trustee. The term “Indenture”, as hereinafter used, means said Indenture dated as of January 1, 1954, and all indentures supplemental thereto (including, without limitation, the Supplemental Indenture) from time to time in effect. Reference is made to the Indenture for a description of the property mortgaged and pledged, the nature and extent of the security, the rights of the holders and registered owners of said bonds, of the Company and of the Trustee in respect of the security, and the terms and conditions governing the issuance and security of said bonds.

Any transferee, by its acceptance of a bond registered in its name (or the name of its nominee), shall be deemed to have made the representation set forth in Section 6.2 of the Bond Purchase Agreement dated as of August 10, 2021 among the Company and the purchasers listed on Schedule A attached thereto, as amended, restated, supplemented or otherwise modified from time to time.

With the consent of the Company and to the extent permitted by and as provided in the Indenture, modifications or alterations of the Indenture or of any supplemental indenture and of the rights and obligations of the Company and of the holders and registered owners of the bonds may be made, and compliance with any provision of the Indenture or of any supplemental indenture may be waived, by the affirmative vote of the holders and registered owners of not less than sixty-six and two-thirds per centum (66 2/3%) in principal amount of the bonds then outstanding under the Indenture, and by the affirmative vote of the holders and registered owners of not less than sixty-six and two-thirds per centum (66 2/3%) in principal amount of the bonds of any series then outstanding under the Indenture and affected by such modification or alteration, in case one or more but less than all of the series of bonds then outstanding under the Indenture are so affected, but in any case excluding bonds disqualified from voting by reason of the Company’s interest therein as provided in the Indenture; subject, however, to the condition, among other conditions stated in the Indenture, that no such modification or alteration shall be made which, among other things, will permit the extension of the time or times of payment of the principal of or the interest or the premium, if any, on this bond, or the reduction in the principal amount hereof or in the rate of interest or the amount of any premium hereon, or any other modification in the terms of payment of such principal, interest or premium, which terms of payment are unconditional, or, otherwise than as permitted by the Indenture, the creation of any lien ranking prior to or on a parity with the lien of the Indenture with respect to any of the mortgaged property, all as more fully provided in the Indenture.

The bonds of this Series may be called for redemption by the Company, as a whole at any time or in part from time to time, at a redemption price equal to 100% of the principal amount of the bonds of this Series to be redeemed plus accrued and unpaid interest on the principal amount

20

being redeemed to the date of redemption and the Make-Whole Amount (as defined in the Supplemental Indenture) applicable thereto.

Notice of each redemption shall be mailed to all registered owners not less than thirty nor more than forty-five days before the redemption date.

In case of certain completed defaults specified in the Indenture, the principal of this bond may be declared or may become due and payable in the manner and with the effect provided in the Indenture.

No recourse shall be had for the payment of the principal of or the interest or the premium, if any, on this bond, or for any claim based hereon, or otherwise in respect hereof or of the Indenture, to or against any incorporator, stockholder, officer or director, past, present or future, of the Company or of any predecessor or successor corporation, either directly or through the Company or such predecessor or successor corporation, under any constitution or statute or rule of law, or by the enforcement of any assessment or penalty, or otherwise, all such liability of incorporators, stockholders, directors and officers being waived and released by the registered owner hereof by the acceptance of this bond and being likewise waived and released by the terms of the Indenture, all as more fully provided therein.

This bond is transferable by the registered owner hereof, in person or by duly authorized attorney, at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of the registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York, upon surrender and cancellation of this bond; and thereupon a new registered bond or bonds without coupons of the same aggregate principal amount and series will, upon the payment of any transfer tax or taxes payable, be issued to the transferee in exchange herefor. The Company shall not be required to exchange or transfer this bond if this bond or a portion hereof has been selected for redemption.

The security represented by this certificate has not been registered under the Securities Act of 1933, as amended (the “Securities Act”), or qualified under any state securities laws and may not be transferred, sold or otherwise disposed of except while a registration statement is in effect or pursuant to an available exemption from registration under the Securities Act and applicable state securities laws.

(End of Form of Bond of 2033 Series)

21

(Form of Face of Bond of 2062 Series)

NO. RU-2022-B-__	$________
Ill. Commerce Commission Nos. 6860	CUSIP No._____________

Northern Illinois Gas Company

First Mortgage Bond 3.18% Series due October 27, 2062

Northern Illinois Gas Company, an Illinois corporation (hereinafter called the “Company”), for value received, hereby promises to pay to                      or registered assigns, the sum of                           Dollars, on October 27, 2062, and to pay to the registered owner hereof interest on said sum from the date hereof until said sum shall be paid, at the rate of 3.18% per annum, payable semi-annually on the twentieth day of April and the twentieth day of October in each year, beginning on April 20, 2023, except that the interest payment otherwise payable on October 20, 2062 will be payable on October 27, 2062. Both the principal of and the interest on this bond shall be payable at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of the registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York, in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts. Any installment of interest on this bond may, at the Company’s option, be paid by mailing checks for such interest payable to or upon the written order of the person entitled thereto to the address of such person as it appears on the registration books.

So long as there is no existing default in the payment of interest on this bond, the interest so payable on any interest payment date will be paid to the person in whose name this bond is registered on April 5 or October 5 (whether or not a business day), as the case may be, next preceding such interest payment date. If and to the extent that the Company shall default in the payment of interest due on such interest payment date, such defaulted interest shall be paid to the person in whose name this bond is registered on the record date fixed, in advance, by the Company for the payment of such defaulted interest.

Additional provisions of this bond are set forth on the reverse hereof.

This bond shall not be entitled to any security or benefit under the Indenture or be valid or become obligatory for any purpose unless and until it shall have been authenticated by the execution by the Trustee, or its successor in trust under the Indenture, of the certificate endorsed hereon.

22

In Witness Whereof, Northern Illinois Gas Company has caused this bond to be executed in its name by its Executive Vice President, Chief Financial Officer and Treasurer, manually or by facsimile signature, and has caused its corporate seal to be impressed hereon or a facsimile thereof to be imprinted hereon and to be attested by its Corporate Secretary, manually or by facsimile signature.

Dated: October 27, 2022

	Northern Illinois Gas Company By:___________________________________ Executive Vice President, Chief Financial Officer and Treasurer
Attest: _____________________________________     Corporate Secretary

23

(Form of Trustee’s Certificate of Authentication)

This bond is one of the bonds of the 2062 Series designated therein, referred to and described in the within-mentioned Supplemental Indenture dated as of August 10, 2021, effective August 31, 2021.

U.S. Bank National Association,
   Trustee

By:______________________________
    Authorized Officer

Dated: October 27, 2022

24

(Form of Reverse Side of Bond of 2062 Series)

This bond is one, of the series hereinafter specified, of the bonds issued and to be issued in series from time to time under and in accordance with and secured by an Indenture dated as of January 1, 1954, to U.S. Bank National Association, as Trustee, as supplemented by certain indentures supplemental thereto, executed and delivered to the Trustee; and this bond is one of a series of such bonds, designated “Northern Illinois Gas Company First Mortgage Bond 3.18% Series due October 27, 2062” (herein called “bonds of this Series”), the issuance of which is provided for by a Supplemental Indenture dated as of August 10, 2021, effective August 31, 2021 (hereinafter called the “Supplemental Indenture”), executed and delivered by the Company to the Trustee. The term “Indenture”, as hereinafter used, means said Indenture dated as of January 1, 1954, and all indentures supplemental thereto (including, without limitation, the Supplemental Indenture) from time to time in effect. Reference is made to the Indenture for a description of the property mortgaged and pledged, the nature and extent of the security, the rights of the holders and registered owners of said bonds, of the Company and of the Trustee in respect of the security, and the terms and conditions governing the issuance and security of said bonds.

Any transferee, by its acceptance of a bond registered in its name (or the name of its nominee), shall be deemed to have made the representation set forth in Section 6.2 of the Bond Purchase Agreement dated as of August 10, 2021 among the Company and the purchasers listed on Schedule A attached thereto, as amended, restated, supplemented or otherwise modified from time to time.

With the consent of the Company and to the extent permitted by and as provided in the Indenture, modifications or alterations of the Indenture or of any supplemental indenture and of the rights and obligations of the Company and of the holders and registered owners of the bonds may be made, and compliance with any provision of the Indenture or of any supplemental indenture may be waived, by the affirmative vote of the holders and registered owners of not less than sixty-six and two-thirds per centum (66 2/3%) in principal amount of the bonds then outstanding under the Indenture, and by the affirmative vote of the holders and registered owners of not less than sixty-six and two-thirds per centum (66 2/3%) in principal amount of the bonds of any series then outstanding under the Indenture and affected by such modification or alteration, in case one or more but less than all of the series of bonds then outstanding under the Indenture are so affected, but in any case excluding bonds disqualified from voting by reason of the Company’s interest therein as provided in the Indenture; subject, however, to the condition, among other conditions stated in the Indenture, that no such modification or alteration shall be made which, among other things, will permit the extension of the time or times of payment of the principal of or the interest or the premium, if any, on this bond, or the reduction in the principal amount hereof or in the rate of interest or the amount of any premium hereon, or any other modification in the terms of payment of such principal, interest or premium, which terms of payment are unconditional, or, otherwise than as permitted by the Indenture, the creation of any lien ranking prior to or on a parity with the lien of the Indenture with respect to any of the mortgaged property, all as more fully provided in the Indenture.

The bonds of this Series may be called for redemption by the Company, as a whole at any time or in part from time to time, at a redemption price equal to 100% of the principal amount of the bonds of this Series to be redeemed plus accrued and unpaid interest on the principal amount

25

being redeemed to the date of redemption and the Make-Whole Amount (as defined in the Supplemental Indenture) applicable thereto.

Notice of each redemption shall be mailed to all registered owners not less than thirty nor more than forty-five days before the redemption date.

In case of certain completed defaults specified in the Indenture, the principal of this bond may be declared or may become due and payable in the manner and with the effect provided in the Indenture.

No recourse shall be had for the payment of the principal of or the interest or the premium, if any, on this bond, or for any claim based hereon, or otherwise in respect hereof or of the Indenture, to or against any incorporator, stockholder, officer or director, past, present or future, of the Company or of any predecessor or successor corporation, either directly or through the Company or such predecessor or successor corporation, under any constitution or statute or rule of law, or by the enforcement of any assessment or penalty, or otherwise, all such liability of incorporators, stockholders, directors and officers being waived and released by the registered owner hereof by the acceptance of this bond and being likewise waived and released by the terms of the Indenture, all as more fully provided therein.

This bond is transferable by the registered owner hereof, in person or by duly authorized attorney, at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of the registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York, upon surrender and cancellation of this bond; and thereupon a new registered bond or bonds without coupons of the same aggregate principal amount and series will, upon the payment of any transfer tax or taxes payable, be issued to the transferee in exchange herefor. The Company shall not be required to exchange or transfer this bond if this bond or a portion hereof has been selected for redemption.

The security represented by this certificate has not been registered under the Securities Act of 1933, as amended (the “Securities Act”), or qualified under any state securities laws and may not be transferred, sold or otherwise disposed of except while a registration statement is in effect or pursuant to an available exemption from registration under the Securities Act and applicable state securities laws.

(End of Form of Bond of 2062 Series)

and

WHEREAS, all acts and things necessary to make this Supplemental Indenture, when duly executed and delivered, a valid, binding and legal instrument in accordance with its terms, and for the purposes herein expressed, have been done and performed, and the execution and delivery of this Supplemental Indenture have in all respects been duly authorized.

Now Therefore, in consideration of the premises and of the sum of one dollar paid by the Trustee to the Company, and for other good and valuable consideration, the receipt of which is hereby acknowledged, for the purpose of securing the due and punctual payment of the principal of and the interest and premium, if any, on all bonds which shall be issued under the Indenture,

26

and for the purpose of securing the faithful performance and observance of all the covenants and conditions set forth in the Indenture and in all indentures supplemental thereto, the Company by these presents does grant, bargain, sell, transfer, assign, pledge, mortgage, warrant and convey unto U.S. Bank National Association, as Trustee, and its successor or successors in the trust hereby created, all property, real and personal (other than property expressly excepted from the lien and operation of the Indenture), which, at the actual date of execution and delivery of this Supplemental Indenture, is solely used or held for use in the operation by the Company of its gas utility system and in the conduct of its gas utility business and all property, real and personal, used or useful in the gas utility business (other than property expressly excepted from the lien and operation of the Indenture) acquired by the Company after the actual date of execution and delivery of this Supplemental Indenture or (subject to the provisions of Section 16.03 of the Indenture) by any successor corporation after such execution and delivery, and it is further agreed by and between the Company and the Trustee as follows:

ARTICLE I.

Bonds of this Supplemental Indenture

Section 1.The bonds of this Supplemental Indenture shall, as hereinbefore recited, be designated as the Company’s (a) “First Mortgage Bonds 1.42% Series due August 31, 2026”, (b) “First Mortgage Bonds 1.77% Series due October 28, 2028”, (c) “First Mortgage Bonds 2.21% Series due August 31, 2032”, (d) “First Mortgage Bonds 2.19% Series due August 31, 2033”, and (e) “First Mortgage Bonds 3.18% Series due October 27, 2062”, as applicable. The bonds of the 2026 Series which may be issued and outstanding shall not exceed $50,000,000 in aggregate principal amount, exclusive of bonds of such series authenticated and delivered pursuant to Section 4.12 of the Indenture. The bonds of the 2028 Series which may be issued and outstanding shall not exceed $100,000,000 in aggregate principal amount, exclusive of bonds of such series authenticated and delivered pursuant to Section 4.12 of the Indenture. The bonds of the 2032 Series which may be issued and outstanding shall not exceed $100,000,000 in aggregate principal amount, exclusive of bonds of such series authenticated and delivered pursuant to Section 4.12 of the Indenture. The bonds of the 2033 Series which may be issued and outstanding shall not exceed $50,000,000 in aggregate principal amount, exclusive of bonds of such series authenticated and delivered pursuant to Section 4.12 of the Indenture. The bonds of the 2062 Series which may be issued and outstanding shall not exceed $75,000,000 in aggregate principal amount, exclusive of bonds of such series authenticated and delivered pursuant to Section 4.12 of the Indenture.

Section 2.The bonds of this Supplemental Indenture shall be registered bonds without coupons, and the form of each series of such bonds, and of the Trustee’s certificate of authentication to be endorsed on all bonds of this Supplemental Indenture, shall be substantially as hereinbefore recited, respectively.

27

Section 3.The bonds of this Supplemental Indenture shall be issued in the denomination of $500,000 each and in such integral multiple or multiples thereof (except for one bond per holder and registered owner as may be necessary to reflect any principal amount in excess of $500,000 not evenly divisible by $500,000) as shall be determined and authorized by the Board of Directors of the Company or by any officer of the Company authorized by the Board of Directors to make such determination, the authorization of the denomination of any bond to be conclusively evidenced by the execution thereof on behalf of the Company. The bonds of the 2026 Series shall be numbered RU-2021-A-1 and consecutively upwards, or in such other appropriate manner as shall be determined and authorized by the Board of Directors of the Company. The bonds of the 2028 Series shall be numbered RU-2021-B-1 and consecutively upwards, or in such other appropriate manner as shall be determined and authorized by the Board of Directors of the Company. The bonds of the 2032 Series shall be numbered RU-2022-A-1 and consecutively upwards, or in such other appropriate manner as shall be determined and authorized by the Board of Directors of the Company. The bonds of the 2033 Series shall be numbered RU-2021-C-1 and consecutively upwards, or in such other appropriate manner as shall be determined and authorized by the Board of Directors of the Company. The bonds of the 2062 Series shall be numbered RU-2022-B-1 and consecutively upwards, or in such other appropriate manner as shall be determined and authorized by the Board of Directors of the Company.

The bonds of the 2026 Series shall be dated August 31, 2021, except that each bond issued on or after the respective first payment of interest thereon shall be dated as of the date of the interest payment date thereof to which interest shall have been paid on the bonds of such series next preceding the date of issue, unless issued on an interest payment date to which interest shall have been so paid, in which event such bonds shall be dated as of the date of issue; provided, however, that bonds issued on or after February 5 and before the next succeeding February 20 or on or after August 5 and before the next succeeding August 20 shall be dated the next succeeding interest payment date if interest shall have been paid to such date. The bonds of the 2028 Series shall be dated October 28, 2021, except that each bond issued on or after the respective first payment of interest thereon shall be dated as of the date of the interest payment date thereof to which interest shall have been paid on the bonds of such series next preceding the date of issue, unless issued on an interest payment date to which interest shall have been so paid, in which event such bonds shall be dated as of the date of issue; provided, however, that bonds issued on or after April 5 and before the next succeeding April 20 or on or after October 5 and before the next succeeding October 20 shall be dated the next succeeding interest payment date if interest shall have been paid to such date. The bonds of the 2032 Series shall be dated August 31, 2022, except that each bond issued on or after the respective first payment of interest thereon shall be dated as of the date of the interest payment date thereof to which interest shall have been paid on the bonds of such series next preceding the date of issue, unless issued on an interest payment date to which interest shall have been so paid, in which event such bonds shall be dated as of the date of issue; provided, however, that bonds issued on or after February 5 and before the next succeeding February 20 or on or after August 5 and before the next succeeding August 20 shall be dated the next succeeding interest payment date if interest shall have been paid to such date. The bonds of the 2033 Series shall be dated August 31, 2021, except that each bond issued on or after the respective first payment of interest thereon shall be dated as of the date of the interest payment date thereof to which interest shall have been paid on the bonds of such series next preceding the date of issue, unless issued on an interest payment date to which interest shall have been so paid, in which event such bonds shall be dated as of the date of issue; provided,

28

however, that bonds issued on or after February 5 and before the next succeeding February 20 or on or after August 5 and before the next succeeding August 20 shall be dated the next succeeding interest payment date if interest shall have been paid to such date. The bonds of the 2062 Series shall be dated October 27, 2022, except that each bond issued on or after the respective first payment of interest thereon shall be dated as of the date of the interest payment date thereof to which interest shall have been paid on the bonds of such series next preceding the date of issue, unless issued on an interest payment date to which interest shall have been so paid, in which event such bonds shall be dated as of the date of issue; provided, however, that bonds issued on or after April 5 and before the next succeeding April 20 or on or after October 5 and before the next succeeding October 20 shall be dated the next succeeding interest payment date if interest shall have been paid to such date. The bonds of the 2026 Series shall mature on August 31, 2026 and shall bear interest at the rate of 1.42% per annum until the principal thereof shall be paid. The bonds of the 2028 Series shall mature on October 28, 2028 and shall bear interest at the rate of 1.77% per annum until the principal thereof shall be paid. The bonds of the 2032 Series shall mature on August 31, 2032 and shall bear interest at the rate of 2.21% per annum until the principal thereof shall be paid. The bonds of the 2033 Series shall mature on August 31, 2033 and shall bear interest at the rate of 2.19% per annum until the principal thereof shall be paid. The bonds of the 2062 Series shall mature on October 27, 2062 and shall bear interest at the rate of 3.18% per annum until the principal thereof shall be paid. Interest on the bonds of this Supplemental Indenture shall be calculated on the basis of a 360-day year consisting of twelve 30-day months. Interest on the bonds of the 2026 Series shall be payable semi-annually on the twentieth day of February and the twentieth day of August in each year, beginning February 20, 2022, except that the interest payment otherwise payable on August 20, 2026 will be payable on August 31, 2026. Interest on the bonds of the 2028 Series shall be payable semi-annually on the twentieth day of April and the twentieth day of October in each year, beginning April 20, 2022, except that the interest payment otherwise payable on October 20, 2028 will be payable on October 28, 2028. Interest on the bonds of the 2032 Series shall be payable semi-annually on the twentieth day of February and the twentieth day of August in each year, beginning February 20, 2023, except that the interest payment otherwise payable on August 20, 2032 will be payable on August 31, 2032. Interest on the bonds of the 2033 Series shall be payable semi-annually on the twentieth day of February and the twentieth day of August in each year, beginning February 20, 2022, except that the interest payment otherwise payable on August 20, 2033 will be payable on August 31, 2033. Interest on the bonds of the 2062 Series shall be payable semi-annually on the twentieth day of April and the twentieth day of October in each year, beginning April 20, 2023, except that the interest payment otherwise payable on October 20, 2062 will be payable on October 27, 2062. So long as there is no existing default in the payment of interest on the bonds of this Supplemental Indenture, such interest shall be payable to the person in whose name each such bond is registered on the respective record date (whether or not a business day), as the case may be, next preceding the respective interest payment dates; provided, however, if and to the extent that the Company shall default in the payment of interest due on such interest payment date, such defaulted interest shall be paid to the person in whose name each such bond is registered on the record date fixed, in advance, by the Company for the payment of such defaulted interest.Interest will accrue on overdue interest installments at the rate of (i) 1.42% per annum, with respect to the bonds of the 2026 Series, (ii) 1.77% per annum, with respect to the bonds of the 2028 Series, (iii) 2.21% per annum, with respect to the bonds of the 2032 Series,

29

(iv) 2.19% per annum, with respect to the bonds of the 2033 Series, and (v) 3.18% per annum, with respect to the bonds of the 2062 Series.

The principal of and interest and premium, if any, on the bonds of this Supplemental Indenture shall be payable in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts, and shall be payable at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of the registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York. Any installment of interest on the bonds of this Supplemental Indenture may, at the Company’s option, be paid by mailing checks for such interest payable to or upon the written order of the person entitled thereto to the address of such person as it appears on the registration books. The bonds of this Supplemental Indenture shall be registrable, transferable and exchangeable in the manner provided in Sections 4.08 and 4.09 of the Indenture, at either of such offices or agencies.

Section 4    The bonds of this Supplemental Indenture, upon the mailing of notice and in the manner provided in Section 7.01 of the Indenture (except that no published notice shall be required for the bonds of this Supplemental Indenture) and with the effect provided in Section 7.02 thereof, shall be redeemable at the option of the Company, as a whole at any time or in part from time to time, at a redemption price equal to 100% of the principal amount of the bonds of this Supplemental Indenture to be redeemed plus accrued and unpaid interest of the principal amount being redeemed to the date of redemption plus the Make-Whole Amount applicable thereto, as calculated by the Company. “Make-Whole Amount” means, with respect to any bond of this Supplemental Indenture, an amount equal to the excess, if any, of the Discounted Value of the Remaining Scheduled Payments with respect to the Called Principal of such bond of this Supplemental Indenture over the amount of such Called Principal, provided that the Make-Whole Amount may in no event be less than zero. For the purposes of determining the Make-Whole Amount, the following terms have the following meanings:

“Called Principal” means, with respect to any bond of this Supplemental Indenture, the principal of such bond of this Supplemental Indenture that is to be redeemed.

“Discounted Value” means, with respect to the Called Principal of any bond of this Supplemental Indenture, the amount obtained by discounting all Remaining Scheduled Payments with respect to such Called Principal from their respective scheduled due dates to the Settlement Date with respect to such Called Principal, in accordance with accepted financial practice and at a discount factor (applied on the same periodic basis as that on which interest on the bond of this Supplemental Indenture is payable) equal to the Reinvestment Yield with respect to such Called Principal.

“Reinvestment Yield” means, with respect to the Called Principal of any bond of this Supplemental Indenture, the sum of (x) 0.50% plus (y) the yield to maturity implied by the “Ask Yield(s)” reported as of 10:00 a.m. (New York City time) on the second Business Day preceding the Settlement Date with respect to such Called Principal, on the display designated as “Page PX1” (or such other display as may replace Page PX1) on Bloomberg Financial Markets for the most recently issued actively traded on-the-run U.S.

30

Treasury securities (“Reported”) having a maturity equal to the Remaining Average Life of such Called Principal as of such Settlement Date. If there are no such U.S. Treasury securities Reported having a maturity equal to such Remaining Average Life, then such implied yield to maturity will be determined by (a) converting U.S. Treasury bill quotations to bond equivalent yields in accordance with accepted financial practice and (b) interpolating linearly between the “Ask Yields” Reported for the applicable most recently issued actively traded on-the-run U.S. Treasury securities with the maturities (1) closest to and greater than such Remaining Average Life and (2) closest to and less than such Remaining Average Life. The Reinvestment Yield shall be rounded to the number of decimal places as appears in the interest rate of the applicable bond.

If such yields are not Reported or the yields Reported as of such time are not ascertainable (including by way of interpolation), then “Reinvestment Yield” means, with respect to the Called Principal of any bond of this Supplemental Indenture, the sum of (x) 0.50% plus (y) the yield to maturity implied by the U.S. Treasury constant maturity yields reported, for the latest day for which such yields have been so reported as of the second Business Day preceding the Settlement Date with respect to such Called Principal, in Federal Reserve Statistical Release H.15 (or any comparable successor publication) for the U.S. Treasury constant maturity having a term equal to the Remaining Average Life of such Called Principal as of such Settlement Date. If there is no such U.S. Treasury constant maturity having a term equal to such Remaining Average Life, such implied yield to maturity will be determined by interpolating linearly between (1) the U.S. Treasury constant maturity so reported with the term closest to and greater than such Remaining Average Life and (2) the U.S. Treasury constant maturity so reported with the term closest to and less than such Remaining Average Life. The Reinvestment Yield shall be rounded to the number of decimal places as appears in the interest rate of the applicable bond.

“Remaining Average Life” means, with respect to any Called Principal, the number of years obtained by dividing (a) such Called Principal into (b) the sum of the products obtained by multiplying (1) the principal component of each Remaining Scheduled Payment with respect to such Called Principal by (2) the number of years, computed on the basis of a 360-day year comprised of twelve 30-day months and calculated to the nearest two decimal places, that will elapse between the Settlement Date with respect to such Called Principal and the scheduled due date of such Remaining Scheduled Payment.

“Remaining Scheduled Payments” means, with respect to the Called Principal of any bond of this Supplemental Indenture, all payments of such Called Principal and interest thereon that would be due after the Settlement Date with respect to such Called Principal if no payment of such Called Principal were made prior to its scheduled due date, provided that if such Settlement Date is not a date on which interest payments are due to be made under the terms of the bond of this Supplemental Indenture, then the amount of the next succeeding scheduled interest payment will be reduced by the amount of interest accrued to such Settlement Date and required to be paid on such Settlement Date pursuant to the terms of this Supplemental Indenture.

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“Settlement Date” means, with respect to the Called Principal of any bond of this Supplemental Indenture, the date on which such Called Principal is to be redeemed.

Section 5.No sinking fund is to be provided for the bonds of this Supplemental Indenture.

Article II

Miscellaneous Provisions

Section 1.    This Supplemental Indenture is executed by the Company and the Trustee pursuant to the provisions of Section 4.02 of the Indenture and the terms and conditions hereof shall be deemed to be a part of the terms and conditions of the Indenture for any and all purposes. The Indenture, as heretofore modified and supplemented and as supplemented by this Supplemental Indenture, is in all respects ratified and confirmed.

Section 2.    This Supplemental Indenture shall bind and, subject to the provisions of Article XVI of the Indenture, inure to the benefit of the respective successors and assigns of the parties hereto.

Section 3.    Although this Supplemental Indenture is made as of August 10, 2021, effective August 31, 2021, it shall be effective only from and after the actual time of its execution and delivery by the Company and the Trustee on the date indicated by their respective acknowledgements hereto.

Section 4.    This Supplemental Indenture may be simultaneously executed in any number of counterparts, and all such counterparts executed and delivered, each as an original, shall constitute but one and the same instrument.

Section 5.    The recitals herein are deemed to be those of the Company and not of the Trustee. The Trustee makes no representations as to the validity or sufficiency of this Supplemental Indenture.

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In Witness Whereof, Northern Illinois Gas Company has caused this Supplemental Indenture to be executed in its name by its Executive Vice President, Chief Financial Officer and Treasurer and its corporate seal to be hereunto affixed and attested by its Corporate Secretary, and U.S. Bank National Association, as Trustee under the Indenture, has caused this Supplemental Indenture to be executed in its name by one of its authorized officers and attested by one of its authorized officers, all as of the day and year first above written.

Northern Illinois Gas Company By: /s/ David P. Poroch     Name: David P. Poroch Title:   Executive Vice President, Chief                  Financial Officer and Treasurer
	Attest: By:    /s/ Barbara P. Christopher             Name: Barbara P. Christopher     Title: Corporate Secretary

[Signature Page to 2021 Supplemental Indenture]

U.S. Bank National Association, as Trustee By: /s/ Jack Ellerin                 Name:    Jack Ellerin     Title:    Vice President
	Attest: By: /s/ J. David Dever             Name:    J. David Dever Title:    Vice President

[Signature Page to 2021 Supplemental Indenture]

STATE OF GEORGIA     }    SS:

COUNTY OF HENRY    }

I, Brenda G. Davis, a Notary Public in the State aforesaid, DO HEREBY CERTIFY that David P. Poroch, Executive Vice President, Chief Financial Officer and Treasurer of Northern Illinois Gas Company, an Illinois corporation, one of the parties described in and which executed the foregoing instrument, and Barbara P. Christopher, Corporate Secretary of said corporation, who are both personally known to me to be the same persons whose names are subscribed to the foregoing instrument as such Executive Vice President, Chief Financial Officer and Treasurer and Corporate Secretary, respectively, and who are both personally known to me to be the Executive Vice President, Chief Financial Officer and Treasurer and Corporate Secretary, respectively, of said corporation, personally appeared before me this day and severally acknowledged that they signed, sealed, executed and delivered said instrument as their free and voluntary act as such Executive Vice President, Chief Financial Officer and Treasurer and Corporate Secretary, respectively, of said corporation, and as the free and voluntary act of said corporation, for the uses and purposes therein set forth.

GIVEN under my hand and notarial seal as of the date listed below.

Dated: August 10, 2021

/s/ Brenda G. Davis

Notary Public

My Commission expires: August 17, 2021.

State of Georgia    )
): ss

County of Fulton    )

On the 11th day of August in the year 2021, before me, the undersigned, personally appeared, Jack Ellerin, a Vice President of U.S. Bank National Association, and J. David Dever, a Vice President of U.S. Bank National Association, personally known to me or proved to me on the basis of satisfactory evidence to be the individuals whose names are subscribed to the within instrument and acknowledged to me that they executed the same in their respective capacities, and that by their signatures on the instrument, the individuals executed the instrument.

    /s/ Felicia H. Powell        
Felicia H. Powell

Notary Public

State of Georgia

County of Fulton

Expiration Date: June 21, 2022

Recording Data

This Supplemental Indenture was recorded on the following dates in the office of the Recorder of Deeds in certain counties in the State of Illinois, as follows:

County	Document No.	Date Recorded
Cook	2123028438	08/18/2021
Adams	2021R-07718	08/13/2021
Boone	2021R05910	08/13/2021
Bureau	2021R03610	08/12/2021
Carroll	2021R-2080	08/13/2021
Champaign	2021R19397	08/12/2021
DeKalb	2021010800	08/18/2021
DeWitt	260687	08/12/2021
DuPage	R2021-123007	08/16/2021
Ford	277212	08/17/2021
Grundy	606300	08/13/2021
Hancock	2021-2277	08/16/2021
Henderson	2021183779	08/19/2021
Henry	20-2105147	08/13/2021
Iroquois	21R3204	08/16/2021
Jo Daviess	417287	08/13/2021
Kane	2021K061846	08/12/2021
Kankakee	202111147	08/13/2021
Kendall	202100021439	08/12/2021
Lake	7818793	08/19/2021
LaSalle	2021-12823	08/16/2021
Lee	2021004256	08/12/2021
Livingston	2021R-04015	08/13/2021
McHenry	2021R0044398	08/13/2021
McLean	2021-00020419	08/23/2021
Mercer	2021-403118	08/13/2021
Ogle	202105946	08/13/2021
Piatt	375360	08/16/2021
Pike	2021-2160	08/16/2021
Rock Island	2021-15046	08/16/2021
Stephenson	202100184461	08/13/2021
Tazewell	202100015029	08/13/2021
Vermillion	21-06274	08/13/2021
Whiteside	2021-05704	08/13/2021
Will	R2021090052	08/13/2021
Winnebago	2021028704	08/13/2021
Woodford	2104316	08/13/2021

EX-10.A

Exhibit 10(a)

CONSULTING AGREEMENT

This CONSULTING AGREEMENT (“Agreement”) is entered into by and between Southern Company Services, Inc. (the “Company”) and Andrew W. Evans (“Executive”).

WITNESSETH:

WHEREAS, Executive is currently employed by the Company as Executive Vice President and Chief Financial Officer of The Southern Company (“Southern”);

WHEREAS, Executive desires to retire from employment with the Company;

WHEREAS, the Company desires to retain Executive following his retirement to provide certain consulting services to the Company, and Executive desires to provide such consulting services to the Company, all subject to the terms and conditions set forth herein; and

WHEREAS, Executive has had access to highly confidential and proprietary information of the Company, including but not limited to, employee information, customer information, competitive information, market information, and other information concerning the business and internal operations of the Company.

NOW THEREFORE, for and in consideration of the premises, the mutual covenants and agreements contained herein, and for other good and valuable consideration, the receipt, sufficiency and adequacy of which are hereby acknowledged, the parties hereby agree as follows:

1.Status of Employment.

Executive will cease serving as Executive Vice President and Chief Financial Officer of Southern, effective September 1, 2021 (the “Transition Date”), but will remain an employee of the Company and serve as a senior advisor to the Chief Executive Officer (the “CEO”) of Southern until Executive’s termination of employment with the Company effective December 31, 2021 or such earlier date as determined by Executive or the Company hereunder (the “Separation Date,” and the period commencing on the Transition Date and ending on the Separation Date, the “Transition Period”). As of the Transition Date, Executive will terminate from all positions Executive holds as an officer or director of the Company and the Company’s subsidiaries and affiliates and promptly execute any documents and take any actions as may be necessary or reasonably requested by the Company to effectuate or memorialize Executive’s termination from all such positions with the Company and its subsidiaries and affiliates. Executive shall render services as may be requested by the CEO through the Separation Date and thereafter during the Consulting Term (as defined herein) from such location or locations as he determines in his sole discretion unless otherwise mutually agreed in writing.

2.Compensation During Transition Period.

Notwithstanding Executive’s change in position on the Transition Date, during the Transition Period, Executive will continue to be eligible for the same compensation and benefits to which he would have been eligible as Executive Vice President and Chief Financial Officer of Southern,

including a base salary at the rate in effect for Executive on the date hereof. For the avoidance of doubt, notwithstanding Executive’s termination of employment effective as of the Separation Date, Executive will be eligible to receive any payout earned with respect to 2021 under the annual cash incentive program in which Executive currently participates based on actual performance for the full performance period (with any personal objectives deemed achieved at no less than 100% of target performance and otherwise consistent with goal funding for the annual cash incentive program), subject to and in accordance with the terms of the applicable annual incentive program (the “Annual Incentive Payment”). For the avoidance of doubt, and subject to the terms and conditions of the applicable plan documents and any award agreements, Executive is currently retiree eligible with respect to (i) his outstanding Company PSUs and RSUs and (ii) his respective accrued benefits and accounts under the Company’s tax-qualified and non-qualified defined benefit and defined contribution plans and nothing hereunder is intended to affect his entitlements thereunder on or following the Separation Date. Executive may participate in the Company’s retiree medical plan in accordance with the terms of such plan if he timely makes an election to do so in accordance with the terms thereof.

3.Termination of Employment.

Executive agrees that he will forfeit all rights to unpaid compensation under this Agreement (other than earned and unpaid base salary and accrued and vested benefits), and no Consulting Services (as defined below) will be provided by Executive under this Agreement, if Executive’s employment with the Company is terminated prior to the end of the Transition Period by the Company for Cause or by Executive other than following a material breach of this Agreement by the Company which is not cured by the Company within 30 after receiving written notice from Executive of the occurrence of such breach, and other than due to Executive’s termination due to death or physical or mental impairment that renders Executive unable to perform the services required hereunder (“Disability”). For purposes of this Agreement, “Cause” means that (i) Executive fails to follow the reasonable lawful directions of the CEO of Southern in performing Executive’s duties under this Agreement after notice of such failure is provided to Executive and 30 days elapse following such notice without Executive curing such failure, (ii) Executive materially violates Southern’s Code of Ethics as an employee or comparable principles as a consultant, or (iii) Executive materially violates Section 9, 10 or 11 of this Agreement, unless in each case, Executive promptly cures the event constituting Cause, if capable of cure. If Executive’s employment is terminated by the Company other than due to Cause, or if Executive dies or becomes Disabled before the end of the Transition Period, Executive will be released from any obligation to provide Consulting Services and will be entitled to the following benefits:

(a)No later than 30 days following the termination of employment, the Company will pay Executive a lump sum amount in cash equal to the base salary that would have been received by Executive for the remainder of the Transition Period (to the extent unpaid) plus the full amount of the Consulting Fee for the entire Consulting Term (as each term is defined below); and

(b)No later than March 15, 2022, the Company will pay Executive the Annual Incentive Payment (to the extent earned).

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4.Engagement as an Independent Consultant.

During the period commencing on the day immediately after the Separation Date and ending on the second anniversary of the Separation Date (the “Consulting Term”), the Company hereby agrees to engage Executive as an independent contractor, and Executive hereby accepts such engagement as an independent contractor, upon the terms and conditions set forth in this Agreement (the “Consulting Arrangement”).

5.Duties.

Unless otherwise detailed in a specific letter or memorandum, Executive will manage, perform and provide professional consulting services and advice (“Consulting Services”) as may be mutually agreed upon by the CEO of Southern and Executive from time to time. Executive will be available to provide Consulting Services for the Company during the Consulting Term. The parties expect that Executive’s work, on average, will not exceed 20 hours per month during the Consulting Term. Except as otherwise agreed to by the parties, during the Consulting Term Executive may sit on other company boards of directors or become employed with another employer on a full or part-time basis, subject to Executive’s compliance with Sections 9, 10 and 11 of this Agreement. Nothing in this Agreement shall restrict Executive from serving on the board of directors of any of the subsidiaries of Southern.

6.Executive as an Independent Contractor.

During the Consulting Term, Executive will at all times be and remain an independent contractor. Executive will be free to exercise Executive’s own judgment as to the manner and method of providing the Consulting Services to the Company, subject to applicable laws and requirements reasonably imposed by the Company. Executive acknowledges and agrees that, during the Consulting Term, Executive will not be treated as an employee of the Company or any of its affiliates for purposes of federal, state, local or foreign income tax withholding, nor unless otherwise specifically provided by law, for purposes of the Federal Insurance Contributions Act, the Social Security Act, the Federal Unemployment Tax Act or any Worker’s Compensation law of any state or country and for purposes of benefits provided to employees of the Company or any of its affiliates under any employee benefit plan. Executive acknowledges and agrees that as an independent contractor, Executive will be required, during the Consulting Term, to pay any applicable taxes on the fees paid to Executive.

7.Consulting Fee; Reimbursement.

As payment for the Consulting Services rendered pursuant to this Agreement, the Company will pay, and Executive will accept, a consulting fee at the rate of $250,000 per year (the “Consulting Fee”). The payment of the Consulting Fee will be made in substantially equal installments on the first day of each month of the Consulting Term, or soon as practicable after such date. The Company will reimburse Executive for all reasonable and documented expenses incurred by Executive in the performance of Executive’s duties under the Consulting Arrangement, provided that all significant expenses to be incurred by Executive in connection with the Consulting Arrangement will require the prior approval of the CEO of Southern.

8.Termination.

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Either party may terminate the Consulting Arrangement in writing upon 30 days written notice to the other party. The Consulting Arrangement will terminate automatically on the death or Disability of Executive. If the Consulting Arrangement is terminated prior to the end of the Consulting Term by the Company for Cause or by Executive (other than following a material breach of this Agreement which is not cured by the Company within 30 after receiving written notice from Executive of the occurrence of such breach), any remaining unpaid Consulting Fee installments will be forfeited. If the Consulting Arrangement is terminated prior to the end of the Consulting Term by the Company without Cause or due to Executive’s death or Disability, the Company will pay Executive (or Executive’s estate) a lump sum amount in cash equal to the portion of the Consulting Fee for the full Consulting Term that is unpaid as of the date of such termination. Such amount will be paid to Executive no later than 30 days after the date the Consulting Arrangement is terminated.

9.Confidential Information; Non-Disparagement.

(a)Without the prior written consent of the Company, Executive agrees hereby not to disclose or use, directly or indirectly (except as may be required for the performance of duties assigned by the Company or one of its affiliates or as may be required by law or regulation or by a court of competent jurisdiction), any trade secret or other confidential information pertaining to the conduct of the Company's business, unless and until such trade secret or confidential information is in the public domain. The Company’s business, as that term is used herein, includes, but is not limited to, the Company’s and any of its affiliates’ records, processes, methods, data, reports, information, documents, equipment, training manuals, customer lists and business secrets. Except as may be compelled by a court of competent jurisdiction or as may otherwise be required by law or regulation, Executive shall take no action during the two-year period following the Separation Date (including without limitation the making of any oral or written statement) which action materially and directly damages the reputation of Southern or any of its subsidiaries.

(b)Notwithstanding anything herein to the contrary, nothing in this Agreement will prevent Executive from providing truthful testimony under oath in a judicial or administrative proceeding or prevent Executive from providing information to a federal, state, or local agency in connection with the lawful exercise of such agency’s functions. Moreover, nothing in this Agreement is intended to prohibit Executive from engaging in protected activities under applicable law or regulation (including protected activities described in Section 211 of the Energy Reorganization Act). Executive further understands nothing in this Agreement limits Executive’s ability to file a charge or complaint with the Securities and Exchange Commission or any other federal, state or local government agency or commission (“Government Agencies”). Nothing in this Agreement limits Executive’s ability to communicate with any Government Agencies or otherwise participate in any investigation or proceeding that may be conducted by the Government Agency, including providing documents or information without notice to the Company. This Agreement does not limit Executive’s right to receive an award for information provided to any Government Agency.

(c)U.S. DEFEND TRADE SECRETS ACT NOTICE OF IMMUNITY. The U.S. Defend

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Trade Secrets Act of 2016 (“DTSA”) provides that an individual shall not be held criminally or civilly liable under any federal or state trade secret law for the disclosure of a trade secret that (1) is made (A) in confidence to a federal, state, or local government official, either directly or indirectly, or to an attorney; and (B) solely for the purpose of reporting or investigating a suspected violation of law or (2) is made in a complaint or other document filed in a lawsuit or other proceeding, if such filing is made under seal. In addition, the DTSA provides that an individual who files a lawsuit for retaliation by an employer for reporting a suspected violation of law may disclose the trade secret to the attorney of the individual and use the trade secret information in the court proceeding, if the individual (x) files any document containing the trade secret under seal and (y) does not disclose the trade secret, except pursuant to court order.

10.Non-Solicitation.

During the period commencing on the date hereof and ending on December 31, 2023 (or, if earlier, either (i) the date that is 30 days after the Company receives written notice from Executive that the Company has materially breached this Agreement if such breach is not cured by the Company within such 30-day period or (ii) the date that is two years after the last day of Executive’s service with the Company), Executive will not, directly or indirectly, for himself or on behalf of any person or entity, solicit or attempt to solicit any of Southern’s or its subsidiaries’ employees to leave their employment with Southern or any such subsidiary. The provisions of this Section 10 shall only apply to those persons employed by Southern or its subsidiaries at the time of the solicitation or attempted solicitation, shall not restrict the hiring of any person which occurred without any recruitment or solicitation by Executive (including by reason of placing a general advertisement to hire which is not targeted at the employees of Southern or any subsidiary), and shall not prevent Executive from responding to contacts initiated by such employees or providing references if requested by any such employee.

11.Other Limitations.

Executive agrees that during the period commencing on the date hereof and ending on December 31, 2023 (or, if earlier, either (i) the date that is 30 days after the Company receives written notice from Executive that the Company has materially breached this Agreement if such breach is not cured by the Company within such 30-day period or (ii) the date that is two years after the last day of Executive’s service with the Company), neither Executive nor anyone acting on Executive’s behalf, will, directly or indirectly, (a) attempt to facilitate (1) the acquisition of securities, assets or indebtedness of Southern or any of its affiliates, (2) any tender offer or business combination involving Southern, its affiliates or any of their respective assets, (3) any recapitalization, restructuring or other extraordinary transaction with respect to Southern or its subsidiaries, or (4) any solicitation of proxies or consents to vote any securities of Southern or its subsidiaries; (b) form or participate in any group with respect to Southern’s securities or act in concert with any person in respect of Southern’s securities; (c) otherwise act, alone or in concert with others, to seek control over the management, Board of Directors or policies of Southern or seek a position on the Board of Directors of Southern; or (d) enter into any discussions or arrangements with any third party regarding any of the above. Notwithstanding the foregoing, the Company

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hereby agrees that this provision will not apply to the following: (1) Executive’s acquisition of any security, asset, or indebtedness of Southern pursuant to the terms of his employment, Southern’s benefit plans or this Agreement; (2) the purchase, sale or transfer in the ordinary course by Executive or anyone acting on his behalf after the Separation Date (and not pursuant to this Agreement or Southern’s benefit plans) of voting securities of Southern so long as, immediately after any such purchase, sale or transfer, Executive and everyone acting on his behalf do not collectively beneficially own more than one percent of any outstanding class of voting securities or securities convertible into voting securities of Southern; (3) the exercise by Executive or anyone acting on his behalf of any voting rights available to Executive or anyone acting on his behalf that are also available to Southern stockholders generally pursuant to any transaction described above, provided that Executive or anyone acting on his behalf has not then either directly, indirectly, or as a member of a group, made, effected, initiated, solicited proxies on behalf of, or caused such transaction to occur or otherwise violated these provisions; and (4) participating in any class action lawsuit involving securities of Southern or any affiliate.

12.Remedies.

The parties represent and agree that any disclosure or use of any trade secrets or confidential information by Executive except as otherwise permitted under this Agreement or authorized by the Company in writing, or any other violation of Section 9, 10 or 11, would be wrongful and cause immediate, significant, continuing and irreparable injury and damage to the Company that is not fully compensable by monetary damages. Should Executive breach or threaten to breach any provisions of Section 9, 10 or 11, the Company will be entitled to obtain immediate relief and remedies in a court of competent jurisdiction (including but not limited to damages, preliminary or permanent injunctive relief and an accounting for all profits and benefits arising out of Executive’s breach), cumulative of and in addition to any other rights or remedies to which Company may be entitled by this Agreement, at law or in equity. Without limiting the Company’s right to obtain injunctive relief, Executive’s maximum liability for damages with respect to any breach or threatened breach of Section 9, 10 or 11 shall be limited to $2,000,000.

13.Return of Materials.

By no later than the end of the Consulting Term, Executive agrees to return to the Company all property of the Company or any other affiliate of Southern, including but not limited to data, lists, information, memoranda, documents, identification cards, parking cards, keys, computers, fax machines, pagers, phones, files, and any and all written or descriptive materials of any kind belonging or relating to the Company or any other affiliate of Southern, including, without limitation, any originals, copies, and abstracts containing any work product, intellectual property, confidential information, and trade secrets in Executive’s possession or control. For the avoidance of doubt, Executive may make a copy of and retain his contacts list, calendar, personal correspondence and any records needed to file his personal income tax returns.

14.Laws, Regulations and Public Ordinances.

Executive will comply with all federal, state, and local statutes, regulations, and public ordinances governing Executive’s Consulting Services hereunder and will indemnify, defend and

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hold the Company harmless from any and all liability, damage, cost, fine, penalty, fee, and expense arising from Executive’s failure to do so.

15.Notices.

All notices required, necessary or desired to be given pursuant to this Agreement will be in writing and will be effective when delivered or on the third day following the date upon which such notice is deposited, postage prepaid, in the United States mail, certified return receipt requested, and addressed to the party at the address set forth below:

If to Executive: Andrew W. Evans
[Home address on file] If to the Company: Southern Company Services, Inc. 30 Ivan Allen Jr. Blvd., NW Atlanta, GA 30308 Attention: General Counsel

16.Waiver of Breach.

The waiver of a breach of any provision of the Agreement will not operate or be construed as a waiver of any other breach. Each of the parties to the Agreement will be entitled to enforce its or his rights under the Agreement, specifically, to recover damages by reason of any breach of any provision of the Agreement and to exercise all other rights existing in its or his favor.

17.Assignment by Executive.

Executive may not assign, transfer or subcontract any of Executive’s rights or obligations under this Agreement to any party without the prior written consent of the Company. Executive’s obligations under this Agreement will be binding on Executive’s successors and permitted assigns. Any assignment, transfer or subcontracting in violation of this provision will be null and void.

18.Governing Law.

This Agreement will be construed and enforced in accordance with the laws of the State of Georgia.

19.Severability.

The unenforceability or invalidity of any particular provision of the Agreement will not affect its other provisions, and to the extent necessary to give such other provisions effect, they will be deemed severable. If any provision of the Agreement is determined by any court of law or equity with jurisdiction over this matter to be unreasonable or unenforceable, in whole or in part, as written, the parties hereby consent to and affirmatively request that said court reform the provision so as to be reasonable and enforceable and that said court enforce the provision as reformed. Executive acknowledges and agrees that the covenants and agreements contained in the Agreement will be construed as covenants and agreements independent of each other or any other contract between the parties hereto and that the existence of any claim or cause of action by Executive against the

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Company or any other affiliate of Southern, whether predicated upon the Agreement or any other contract, will not constitute a defense to the enforcement by the Company or any other affiliate of Southern of the covenants and agreements.

20.Interpretation.

The judicial body interpreting the Agreement will not construe the terms of the Agreement more strictly against one party, it being agreed that both parties and/or their attorneys or agents have negotiated and participated in the preparation hereof.

21.Certain Tax Matters.

If any reimbursements or in-kind benefits provided by the Company pursuant to this Agreement would constitute deferred compensation for purposes of Section 409A of the Internal Revenue Code of 1986, as amended, such reimbursements or in-kind benefits will be subject to the following rules: (a) the amounts to be reimbursed, or the in-kind benefits to be provided, will be determined pursuant to the terms of the applicable benefit plan, policy or agreement and shall be limited to Executive’s lifetime and the lifetime of Executive’s eligible dependents; (b) the amount eligible for reimbursement, or the in-kind benefits provided, during any calendar year may not affect the expenses eligible for reimbursement, or the in-kind benefits provided, in any other calendar year; (c) any reimbursement of an eligible expense shall be made on or before the last day of the calendar year following the calendar year in which the expense was incurred; and (d) Executive’s right to an in-kind benefit or reimbursement is not subject to liquidation or exchange for cash or another benefit.

22.Survival.

Notwithstanding any expiration or termination of this Agreement, the provisions of Sections 9 through 21 hereof will survive and remain in full force and effect, as will any other provision hereof that, by its terms or reasonable interpretation thereof, sets forth obligations that extend beyond the termination of this Agreement.

23.Counterparts.

This Agreement may be executed in separate counterparts, each of which shall be deemed to be an original and both of which taken together shall constitute one and the same agreement.

24.Indemnification.

Executive shall be continue to be indemnified by the Company and its affiliates for his services hereunder (including during the Consulting Term) on the same basis that he is currently indemnified by such parties notwithstanding that he will cease to be an executive officer of the Company as of the Transition Date. Executive shall continue to be covered by any applicable directors’ and officers’ liability insurance policy through the Transition Date, including any “tail” insurance coverage provided thereunder.

25.Legal Fee Reimbursement.

The Company shall promptly reimburse Executive for the legal fees that he has incurred in connection with the review, negotiation and drafting of this Agreement provided that he provides the

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Company with a copy of the written invoice from his counsel evidencing same.

26.Entire Agreement.

This Agreement embodies the entire agreement of the parties and supersedes all prior agreements or arrangements between the parties hereto relating to the subject matter hereof, including any severance program or policy of the Company for which Executive may have otherwise been eligible. This Agreement may not be modified or amended except by a written instrument signed by both Executive and an authorized representative of the Company.

[Signatures are on following page.]

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IN WITNESS WHEREOF, the undersigned have executed the Agreement on the dates set forth below.

COMPANY

Signature:   /s/Thomas A. Fanning

Printed Name: Thomas A. Fanning

Title: Chairman, President and Chief Executive Officer of

The Southern Company

Date:  August 23, 2021

EXECUTIVE

Signature:  /s/Andrew Evans

Date:  23 Aug 21

EX-24.A2

Exhibit 24(a)2

October 1, 2021

Myra C. Bierria and Melissa K. Caen

Ms. Bierria and Ms. Caen:

    As an officer of The Southern Company, I hereby make, constitute, and appoint you my true and lawful Attorney in my name, place, and stead, to sign and cause to be filed with the Securities and Exchange Commission the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2021 and any necessary or appropriate amendment or amendments to such report, to the Company’s other Quarterly Reports on Form 10-Q filed during 2021 or to the Company’s Annual Report on Form 10-K for the year ended December 31, 2020, such report or amendments to such reports to be accompanied in each case by any necessary or appropriate exhibits or schedules thereto.

Yours very truly,

/s/Daniel S. Tucker

Daniel S. Tucker

EX-24.C2

Exhibit 24(c)2

September 27, 2021

Ms. Melissa K. Caen

Southern Company Services, Inc.

30 Ivan Allen Jr. Blvd.

Atlanta, GA 30308

Ms. Caen:

As an officer of Georgia Power Company, I hereby make, constitute, and appoint you my true and lawful Attorney in my name, place, and stead, to sign and cause to be filed with the Securities and Exchange Commission the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2021 and any necessary or appropriate amendment or amendments to such report, to the Company’s other Quarterly Reports on Form 10-Q filed during 2021 or to the Company’s Annual Report on Form 10-K for the year ended December 31, 2020, to be accompanied in each case by any necessary or appropriate exhibits or schedules thereto.

Yours very truly,

/s/Aaron P. Abramovitz

Aaron P. Abramovitz

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:  November 3, 2021

/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, Daniel S. Tucker, 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: November 3, 2021

/s/Daniel S. Tucker

Daniel S. Tucker

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:  November 3, 2021

/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:  November 3, 2021

/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, Christopher C. Womack, 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:  November 3, 2021

/s/Christopher C. Womack

Christopher C. Womack

Chairman, President and Chief Executive Officer

EX-31.C2

Exhibit 31(c)2

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Aaron P. Abramovitz, 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:  November 3, 2021

/s/Aaron P. Abramovitz

Aaron P. Abramovitz

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:  November 3, 2021

/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:  November 3, 2021

/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:   November 3, 2021

/s/Christopher Cummiskey

Christopher Cummiskey

Chairman and 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:  November 3, 2021

/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:  November 3, 2021

/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, David P. Poroch, 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:  November 3, 2021

/s/David P. Poroch

David P. Poroch

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, 2021, 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, 2021, 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, 2021, 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/Daniel S. Tucker

Daniel S. Tucker

Executive Vice President and
Chief Financial Officer

November 3, 2021

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, 2021, 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, 2021, 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, 2021, 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

November 3, 2021

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, 2021, 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, 2021, 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, 2021, fairly presents, in all material respects, the financial condition and results of operations of Georgia Power Company.

/s/Christopher C. Womack

Christopher C. Womack

Chairman, President and Chief Executive Officer

/s/Aaron P. Abramovitz

Aaron P. Abramovitz

Executive Vice President, Chief Financial Officer and Treasurer

November 3, 2021

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, 2021, 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, 2021, 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, 2021, 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

November 3, 2021

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, 2021, 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-K of Southern Power Company for the quarter ended September 30, 2021, 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, 2021, fairly presents, in all material respects, the financial condition and results of operations of Southern Power Company.

/s/Christopher Cummiskey

Christopher Cummiskey

Chairman and Chief Executive Officer

/s/Elliott L. Spencer

Elliott L. Spencer

Senior Vice President, Chief Financial Officer and Treasurer

November 3, 2021

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, 2021, 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, 2021, 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, 2021, 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/David P. Poroch

David P. Poroch

Executive Vice President, Chief Financial

Officer and Treasurer

November 3, 2021

XML

Cover Page	9 Months Ended
	Sep. 30, 2021 shares
Document Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2021
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 Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)	1,059,803,931
Entity Central Index Key	0000092122
Amendment Flag	false
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
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 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
Series 2021B 1.875% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2081
Document Information [Line Items]
Title of 12(b) Security	Series 2021B 1.875% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2081
Trading Symbol	SO 81
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 Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)	30,537,500
Entity Central Index Key	0000003153
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 Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)	9,261,500
Entity Central Index Key	0000041091
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 Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)	1,121,000
Entity Central Index Key	0000066904
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 Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)	1,000
Entity Central Index Key	0001160661
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 Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)	100
Entity Central Index Key	0001004155

XML

Condensed Consolidated Statements of Income (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Operating Revenues:
Operating revenues	$ 6,238	$ 5,620	$ 17,346	$ 15,258
Operating Expenses:
Other operations and maintenance	1,446	1,286	4,257	3,785
Depreciation and amortization	896	889	2,658	2,619
Taxes other than income taxes	312	304	969	932
Estimated loss on Plant Vogtle Units 3 and 4	264	0	772	149
(Gain) loss on dispositions, net	(125)	0	(179)	(39)
Total operating expenses	4,515	3,785	13,317	11,102
Operating Income	1,723	1,835	4,029	4,156
Other Income and (Expense):
Allowance for equity funds used during construction	49	38	140	106
Earnings from equity method investments	30	33	35	105
Interest expense, net of amounts capitalized	(451)	(443)	(1,352)	(1,343)
Impairment of leveraged leases	0	0	(7)	(154)
Other income (expense), net	131	113	297	319
Total other income and (expense)	(241)	(259)	(887)	(967)
Earnings Before Income Taxes	1,482	1,576	3,142	3,189
Income taxes (benefit)	372	293	550	443
Consolidated Net Income	1,110	1,283	2,592	2,746
Dividends on preferred stock of subsidiaries	4	4	11	11
Net income (loss) attributable to noncontrolling interests	5	28	(27)	3
Net Income	$ 1,101	$ 1,251	$ 2,608	$ 2,732
Earnings per share -
Basic (in dollars per share)	$ 1.04	$ 1.18	$ 2.46	$ 2.58
Diluted (in dollars per share)	$ 1.03	$ 1.18	$ 2.44	$ 2.57
Average number of shares of common stock outstanding (in millions)
Basic (in shares)	1,061	1,058	1,060	1,058
Diluted (in shares)	1,068	1,064	1,067	1,064
Retail electric revenues
Operating Revenues:
Operating revenues	$ 4,551	$ 4,243	$ 11,492	$ 10,503
Wholesale electric revenues
Operating Revenues:
Operating revenues	731	584	1,822	1,473
Other electric revenues
Operating Revenues:
Operating revenues	179	164	525	484
Natural gas
Operating Revenues:
Operating revenues	623	477	2,994	2,362
Operating Expenses:
Total cost of sales	129	71	943	654
Other
Operating Revenues:
Operating revenues	154	152	513	436
Operating Expenses:
Total cost of sales	71	72	255	201
Fuel
Operating Expenses:
Total cost of sales	1,234	933	2,930	2,190
Purchased power
Operating Expenses:
Total cost of sales	288	230	712	611
Alternative revenue programs
Operating Revenues:
Operating revenues	(1)	(1)	3	6
ALABAMA POWER CO
Operating Revenues:
Operating revenues	1,904	1,729	5,019	4,445
Operating Expenses:
Other operations and maintenance	401	387	1,175	1,078
Depreciation and amortization	214	205	640	606
Taxes other than income taxes	99	103	303	311
Total operating expenses	1,208	1,109	3,332	2,962
Operating Income	696	620	1,687	1,483
Other Income and (Expense):
Allowance for equity funds used during construction	14	12	38	34
Interest expense, net of amounts capitalized	(84)	(84)	(252)	(255)
Other income (expense), net	29	30	93	78
Total other income and (expense)	(41)	(42)	(121)	(143)
Earnings Before Income Taxes	655	578	1,566	1,340
Income taxes (benefit)	152	130	366	307
Consolidated Net Income	503	448	1,200	1,033
Dividends on preferred stock of subsidiaries	4	4	11	11
Net Income	499	444	1,189	1,022
ALABAMA POWER CO | Retail electric revenues
Operating Revenues:
Operating revenues	1,651	1,575	4,357	4,003
ALABAMA POWER CO | Wholesale electric revenues
Operating Revenues:
Operating revenues	107	73	285	184
ALABAMA POWER CO | Wholesale revenues, affiliates
Operating Revenues:
Operating revenues	53	11	109	36
ALABAMA POWER CO | Other
Operating Revenues:
Operating revenues	93	70	268	222
ALABAMA POWER CO | Fuel
Operating Expenses:
Total cost of sales	373	306	927	721
ALABAMA POWER CO | Purchased power
Operating Expenses:
Total cost of sales	76	64	173	153
ALABAMA POWER CO | Purchased power, affiliates
Operating Expenses:
Total cost of sales	45	44	114	93
GEORGIA POWER CO
Operating Revenues:
Operating revenues	2,856	2,617	7,050	6,371
Operating Expenses:
Other operations and maintenance	544	483	1,558	1,411
Depreciation and amortization	345	358	1,025	1,064
Taxes other than income taxes	130	123	365	344
Estimated loss on Plant Vogtle Units 3 and 4	264	0	772	149
Total operating expenses	2,176	1,620	5,842	4,596
Operating Income	680	997	1,208	1,775
Other Income and (Expense):
Allowance for equity funds used during construction	33	22	94	63
Interest expense, net of amounts capitalized	(106)	(106)	(315)	(322)
Other income (expense), net	42	32	124	93
Total other income and (expense)	(31)	(52)	(97)	(166)
Earnings Before Income Taxes	649	945	1,111	1,609
Income taxes (benefit)	113	172	81	198
Consolidated Net Income	536	773	1,030	1,411
GEORGIA POWER CO | Retail electric revenues
Operating Revenues:
Operating revenues	2,652	2,435	6,465	5,870
GEORGIA POWER CO | Wholesale electric revenues
Operating Revenues:
Operating revenues	63	34	143	85
GEORGIA POWER CO | Other
Operating Revenues:
Operating revenues	141	148	442	416
GEORGIA POWER CO | Fuel
Operating Expenses:
Total cost of sales	432	368	1,088	826
GEORGIA POWER CO | Purchased power
Operating Expenses:
Total cost of sales	173	146	461	409
GEORGIA POWER CO | Purchased power, affiliates
Operating Expenses:
Total cost of sales	288	142	573	393
MISSISSIPPI POWER CO
Operating Revenues:
Operating revenues	378	336	988	895
Operating Expenses:
Other operations and maintenance	85	62	230	202
Depreciation and amortization	46	47	138	135
Taxes other than income taxes	33	31	96	90
Total operating expenses	309	249	815	711
Operating Income	69	87	173	184
Other Income and (Expense):
Interest expense, net of amounts capitalized	(16)	(14)	(45)	(45)
Other income (expense), net	7	6	27	19
Total other income and (expense)	(9)	(8)	(18)	(26)
Earnings Before Income Taxes	60	79	155	158
Income taxes (benefit)	10	12	22	20
Consolidated Net Income	50	67	133	138
MISSISSIPPI POWER CO | Retail electric revenues
Operating Revenues:
Operating revenues	248	232	670	630
MISSISSIPPI POWER CO | Wholesale electric revenues
Operating Revenues:
Operating revenues	60	61	178	164
MISSISSIPPI POWER CO | Wholesale revenues, affiliates
Operating Revenues:
Operating revenues	62	36	120	82
MISSISSIPPI POWER CO | Other
Operating Revenues:
Operating revenues	8	7	20	19
MISSISSIPPI POWER CO | Fuel
Operating Expenses:
Total cost of sales	139	103	330	266
MISSISSIPPI POWER CO | Purchased power
Operating Expenses:
Total cost of sales	6	6	21	18
SOUTHERN POWER CO
Operating Revenues:
Operating revenues	679	523	1,610	1,337
Operating Expenses:
Other operations and maintenance	94	89	308	245
Depreciation and amortization	132	129	383	367
Taxes other than income taxes	12	10	35	29
Loss on sales-type lease	15	0	15	0
(Gain) loss on dispositions, net	0	0	(39)	(39)
Total operating expenses	553	384	1,328	1,000
Operating Income	126	139	282	337
Other Income and (Expense):
Interest expense, net of amounts capitalized	(36)	(36)	(111)	(114)
Other income (expense), net	2	13	10	19
Total other income and (expense)	(34)	(23)	(101)	(95)
Earnings Before Income Taxes	92	116	181	242
Income taxes (benefit)	9	14	(3)	27
Consolidated Net Income	83	102	184	215
Net income (loss) attributable to noncontrolling interests	5	28	(27)	3
Net Income	78	74	211	212
SOUTHERN POWER CO | Wholesale electric revenues
Operating Revenues:
Operating revenues	503	418	1,231	1,047
SOUTHERN POWER CO | Wholesale revenues, affiliates
Operating Revenues:
Operating revenues	167	101	361	279
SOUTHERN POWER CO | Other
Operating Revenues:
Operating revenues	9	4	18	11
SOUTHERN POWER CO | Fuel
Operating Expenses:
Total cost of sales	259	137	540	346
SOUTHERN POWER CO | Purchased power
Operating Expenses:
Total cost of sales	41	19	86	52
SOUTHERN Co GAS
Operating Revenues:
Operating revenues	$ 623	$ 477	$ 2,994	$ 2,362
Operating Expenses:
Cost, Product and Service [Extensible Enumeration]	Natural gas	Natural gas	Natural gas	Natural gas
Other operations and maintenance	$ 238	$ 217	$ 776	$ 694
Depreciation and amortization	133	125	396	368
Taxes other than income taxes	36	35	166	154
(Gain) loss on dispositions, net	(121)	0	(127)	2
Total operating expenses	415	448	2,154	1,872
Operating Income	208	29	840	490
Other Income and (Expense):
Earnings from equity method investments	25	33	14	106
Interest expense, net of amounts capitalized	(57)	(57)	(175)	(171)
Other income (expense), net	13	12	(66)	33
Total other income and (expense)	(19)	(12)	(227)	(32)
Earnings Before Income Taxes	189	17	613	458
Income taxes (benefit)	133	3	224	98
Consolidated Net Income	56	14	389	360
SOUTHERN Co GAS | Natural gas
Operating Revenues:
Operating revenues	624	478	2,991	2,356
Operating Expenses:
Total cost of sales	129	71	943	654
SOUTHERN Co GAS | Alternative revenue programs
Operating Revenues:
Operating revenues	$ (1)	$ (1)	$ 3	$ 6

XML

Condensed Consolidated Statements of Income (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Operating revenues	$ 6,238	$ 5,620	$ 17,346	$ 15,258
Alternative revenue programs
Operating revenues	(1)	(1)	3	6
SOUTHERN Co GAS
Operating revenues	623	477	2,994	2,362
Revenue taxes collected	12	10	89	79
SOUTHERN Co GAS | Alternative revenue programs
Operating revenues	$ (1)	$ (1)	$ 3	$ 6

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Net income (loss)	$ 1,110	$ 1,283	$ 2,592	$ 2,746
Qualifying hedges:
Changes in fair value, net of tax	1	49	(15)	(26)
Reclassification adjustment for amounts included in net income, net of tax	31	(32)	81	(3)
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	4	3	10	6
Total other comprehensive income (loss)	36	20	76	(23)
Comprehensive Income	1,146	1,303	2,668	2,723
Dividends on preferred stock of subsidiaries	4	4	11	11
Comprehensive income (loss) attributable to noncontrolling interests	5	28	(27)	3
Comprehensive Income (Loss) Attributable to Parent	1,137	1,271	2,684	2,709
ALABAMA POWER CO
Net income (loss)	503	448	1,200	1,033
Qualifying hedges:
Changes in fair value, net of tax	4	0	3	0
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)	5	1	6	3
Comprehensive Income	508	449	1,206	1,036
Dividends on preferred stock of subsidiaries	4	4	11	11
GEORGIA POWER CO
Net income (loss)	536	773	1,030	1,411
Qualifying hedges:
Changes in fair value, net of tax	0	0	0	(2)
Reclassification adjustment for amounts included in net income, net of tax	2	2	5	4
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	2	2	5	2
Comprehensive Income	538	775	1,035	1,413
MISSISSIPPI POWER CO
Net income (loss)	50	67	133	138
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	50	67	134	139
SOUTHERN POWER CO
Net income (loss)	83	102	184	215
Qualifying hedges:
Changes in fair value, net of tax	(21)	44	(48)	(6)
Reclassification adjustment for amounts included in net income, net of tax	27	(36)	66	(24)
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	1	0	2	2
Total other comprehensive income (loss)	7	8	20	(28)
Comprehensive Income	90	110	204	187
Comprehensive income (loss) attributable to noncontrolling interests	5	28	(27)	3
Comprehensive Income (Loss) Attributable to Parent	85	82	231	184
SOUTHERN Co GAS
Net income (loss)	56	14	389	360
Qualifying hedges:
Changes in fair value, net of tax	23	4	32	(17)
Reclassification adjustment for amounts included in net income, net of tax	(2)	1	1	7
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	21	5	33	(10)
Comprehensive Income	$ 77	$ 19	$ 422	$ 350

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Qualifying hedges:
Changes in fair value, tax	$ 1	$ 17	$ (4)	$ (9)
Reclassification adjustment for amounts included in net income, tax	10	(11)	27	(1)
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, tax	1	1	4	3
ALABAMA POWER CO
Qualifying hedges:
Changes in fair value, tax	1	0	1	0
Reclassification adjustment for amounts included in net income, tax	0	0	1	1
GEORGIA POWER CO
Qualifying hedges:
Changes in fair value, tax	0	0	0	(1)
Reclassification adjustment for amounts included in net income, tax	1	0	2	2
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	(7)	15	(16)	(2)
Reclassification adjustment for amounts included in net income, tax	9	(13)	22	(8)
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, tax	0	0	1	0
SOUTHERN Co GAS
Qualifying hedges:
Changes in fair value, tax	8	1	11	(6)
Reclassification adjustment for amounts included in net income, tax	$ 0	$ 0	$ 1	$ 2

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020
Operating Activities:
Net income	$ 2,592	$ 2,746
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	2,944	2,903
Deferred income taxes	89	(196)
Utilization of federal investment tax credits	256	319
Allowance for equity funds used during construction	(140)	(106)
Pension, postretirement, and other employee benefits	(218)	(190)
Settlement of asset retirement obligations	(341)	(315)
Stock based compensation expense	134	99
Estimated loss on Plant Vogtle Units 3 and 4	772	149
Storm damage accruals	166	171
Impairment charges	91	154
(Gain) loss on dispositions, net	(171)	(36)
Retail fuel cost under recovery – long-term	(209)	0
Other, net	(7)	(14)
Changes in certain current assets and liabilities —
-Receivables	2	125
-Materials and supplies	(91)	(141)
-Natural gas cost under recovery	(432)	0
-Other current assets	(160)	(119)
-Accounts payable	(45)	(428)
-Accrued taxes	288	289
-Accrued compensation	(93)	(183)
-Accrued interest	(110)	(52)
-Retail fuel cost over recovery	(150)	158
-Customer refunds	(58)	(226)
-Other current liabilities	(168)	7
Net cash provided from operating activities	5,081	5,220
Investing Activities:
Business acquisitions, net of cash acquired	(345)	(81)
Property additions	(5,222)	(5,365)
Nuclear decommissioning trust fund purchases	(1,301)	(714)
Nuclear decommissioning trust fund sales	1,297	708
Proceeds from dispositions	160	987
Cost of removal, net of salvage	(282)	(233)
Payments pursuant to LTSAs	(145)	(139)
Other investing activities	(12)	(55)
Net cash used for investing activities	(5,850)	(4,892)
Financing Activities:
Decrease in notes payable	(203)	(1,534)
Proceeds —
Long-term debt	6,793	7,543
Common stock	62	63
Short-term borrowings	325	615
Redemptions and repurchases —
Long-term debt	(3,060)	(2,472)
Short-term borrowings	(25)	(840)
Capital contributions from noncontrolling interests	415	173
Distributions to noncontrolling interests	(204)	(164)
Payment of common stock dividends	(2,077)	(2,008)
Other financing activities	(224)	(299)
Net cash provided from financing activities	1,802	1,077
Net Change in Cash, Cash Equivalents, and Restricted Cash	1,033	1,405
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	1,068	1,978
Cash, Cash Equivalents, and Restricted Cash at End of Period	2,101	3,383
Cash paid during the period for —
Interest, net of amounts capitalized	1,417	1,346
Income taxes, net	92	66
Noncash transactions —
Accrued property additions at end of period	915	917
Contributions from noncontrolling interests	89	9
Contributions of wind turbine equipment	82	17
Right-of-use assets obtained under finance leases	92	166
ALABAMA POWER CO
Operating Activities:
Net income	1,200	1,033
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	748	731
Deferred income taxes	104	71
Allowance for equity funds used during construction	(38)	(34)
Pension, postretirement, and other employee benefits	(74)	(71)
Settlement of asset retirement obligations	(152)	(157)
Other, net	(51)	33
Changes in certain current assets and liabilities —
-Receivables	(128)	(130)
-Fossil fuel stock	91	4
-Prepayments	(24)	(32)
-Materials and supplies	(13)	(55)
-Retail fuel cost under recovery	(79)	0
-Other current assets	(19)	(35)
-Accounts payable	(230)	(248)
-Accrued taxes	178	142
-Accrued compensation	(37)	(55)
-Retail fuel cost over recovery	(18)	74
-Other current liabilities	(77)	(76)
Net cash provided from operating activities	1,419	1,229
Investing Activities:
Property additions	(1,235)	(1,460)
Nuclear decommissioning trust fund purchases	(536)	(213)
Nuclear decommissioning trust fund sales	536	213
Cost of removal, net of salvage	(93)	(68)
Change in construction payables, net	12	(46)
Other investing activities	(19)	(17)
Net cash used for investing activities	(1,335)	(1,591)
Proceeds —
Senior notes	600	600
Pollution control revenue bonds	0	87
Redemptions and repurchases —
Pollution control revenue bonds	0	(87)
Other long-term debt	(206)	0
Senior notes	(200)	0
Capital contributions from parent company	630	649
Payment of common stock dividends	(738)	(718)
Other financing activities	(30)	(26)
Net cash provided from financing activities	56	505
Net Change in Cash, Cash Equivalents, and Restricted Cash	140	143
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	530	894
Cash, Cash Equivalents, and Restricted Cash at End of Period	670	1,037
Cash paid during the period for —
Interest, net of amounts capitalized	246	249
Income taxes, net	183	203
Noncash transactions —
Accrued property additions at end of period	178	154
Right-of-use assets obtained under leases	2	65
GEORGIA POWER CO
Operating Activities:
Net income	1,030	1,411
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	1,164	1,206
Deferred income taxes	(299)	(167)
Allowance for equity funds used during construction	(94)	(63)
Pension, postretirement, and other employee benefits	(112)	(98)
Settlement of asset retirement obligations	(154)	(130)
Estimated loss on Plant Vogtle Units 3 and 4	772	149
Storm damage accruals	160	160
Retail fuel cost under recovery – long-term	(203)	0
Other, net	88	11
Changes in certain current assets and liabilities —
-Receivables	(85)	(168)
-Fossil fuel stock	77	4
-Materials and supplies	(60)	(74)
-Other current assets	(51)	(69)
-Accounts payable	164	25
-Accrued taxes	154	44
-Retail fuel cost over recovery	(113)	84
-Customer refunds	(5)	(162)
-Other current liabilities	(83)	(38)
Net cash provided from operating activities	2,350	2,125
Investing Activities:
Property additions	(2,411)	(2,519)
Nuclear decommissioning trust fund purchases	(766)	(500)
Nuclear decommissioning trust fund sales	761	495
Proceeds from dispositions	4	143
Cost of removal, net of salvage	(99)	(93)
Change in construction payables, net	(68)	(14)
Payments pursuant to LTSAs	(38)	(44)
Contributions in aid of construction	71	18
Other investing activities	(26)	(12)
Net cash used for investing activities	(2,572)	(2,526)
Financing Activities:
Decrease in notes payable	(60)	(115)
Proceeds —
Senior notes	750	1,500
Pollution control revenue bonds	122	53
FFB loan	371	519
Short-term borrowings	0	250
Redemptions and repurchases —
Short-term borrowings	0	(375)
Pollution control revenue bonds	(69)	(148)
Senior notes	(325)	(950)
FFB loan	(75)	(55)
Capital contributions from parent company	1,054	1,379
Payment of common stock dividends	(1,237)	(1,156)
Other financing activities	(26)	(35)
Net cash provided from financing activities	505	867
Net Change in Cash, Cash Equivalents, and Restricted Cash	283	466
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	9	52
Cash, Cash Equivalents, and Restricted Cash at End of Period	292	518
Cash paid during the period for —
Interest, net of amounts capitalized	325	316
Income taxes, net	237	311
Noncash transactions —
Accrued property additions at end of period	477	523
Right-of-use assets obtained under operating leases	3	30
MISSISSIPPI POWER CO
Operating Activities:
Net income	133	138
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	161	142
Settlement of asset retirement obligations	(18)	(16)
Other, net	(20)	(11)
Changes in certain current assets and liabilities —
-Receivables	(19)	(3)
-Other current assets	(9)	(7)
-Accounts payable	(12)	(54)
-Accrued taxes	(20)	15
-Retail fuel cost over recovery	(19)	0
-Other current liabilities	(18)	(18)
Net cash provided from operating activities	159	186
Investing Activities:
Property additions	(135)	(174)
Change in construction payables, net	(11)	7
Payments pursuant to LTSAs	(21)	(20)
Other investing activities	(15)	(13)
Net cash used for investing activities	(182)	(200)
Financing Activities:
Decrease in notes payable	(25)	0
Proceeds —
Senior notes	525	0
Pollution control revenue bonds	0	34
Short-term borrowings	0	40
Other long-term debt	0	100
Redemptions and repurchases —
Short-term borrowings	0	(40)
Pollution control revenue bonds	0	(41)
Other revenue bonds	(270)	0
Other long-term debt	(75)	0
Senior notes	0	(275)
Capital contributions from parent company	103	80
Return of capital to parent company	0	(74)
Payment of common stock dividends	(118)	(37)
Other financing activities	(10)	(1)
Net cash provided from financing activities	130	(214)
Net Change in Cash, Cash Equivalents, and Restricted Cash	107	(228)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	39	286
Cash, Cash Equivalents, and Restricted Cash at End of Period	146	58
Cash paid during the period for —
Interest, net of amounts capitalized	53	49
Income taxes, net	11	9
Noncash transactions —
Accrued property additions at end of period	23	42
SOUTHERN POWER CO
Operating Activities:
Net income	184	215
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	402	386
Deferred income taxes	(16)	(59)
Utilization of federal investment tax credits	237	318
Amortization of investment tax credits	(44)	(44)
(Gain) loss on dispositions, net	(39)	(39)
Other, net	14	(16)
Changes in certain current assets and liabilities —
-Receivables	(117)	(28)
-Prepaid income taxes	63	74
-Other current assets	(5)	(17)
-Accounts payable	55	(12)
-Accrued taxes	15	21
-Other current liabilities	1	(25)
Net cash provided from operating activities	750	774
Investing Activities:
Business acquisitions, net of cash acquired	(345)	(81)
Property additions	(355)	(135)
Proceeds from dispositions	22	663
Change in construction payables, net	(22)	(12)
Payments pursuant to LTSAs	(61)	(61)
Other investing activities	8	50
Net cash used for investing activities	(753)	424
Financing Activities:
Decrease in notes payable	(148)	(449)
Proceeds —
Senior notes	400	0
Redemptions and repurchases —
Short-term borrowings	0	(100)
Senior notes	0	(300)
Return of capital to parent company	(271)	0
Capital contributions from noncontrolling interests	415	173
Distributions to noncontrolling interests	(204)	(164)
Purchase of membership interests from noncontrolling interests	0	(60)
Payment of common stock dividends	(153)	(151)
Other financing activities	(6)	(9)
Net cash provided from financing activities	33	(1,060)
Net Change in Cash, Cash Equivalents, and Restricted Cash	30	138
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	183	279
Cash, Cash Equivalents, and Restricted Cash at End of Period	213	417
Cash paid during the period for —
Interest, net of amounts capitalized	118	123
Income taxes, net	(235)	(278)
Noncash transactions —
Accrued property additions at end of period	53	44
Contributions from noncontrolling interests	89	9
Contributions of wind turbine equipment	82	17
Right-of-use assets obtained under operating leases	66	30
SOUTHERN Co GAS
Operating Activities:
Net income	389	360
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	396	368
Deferred income taxes	289	(1)
Mark-to-market adjustments	147	104
Impairment of PennEast Pipeline investment	84	0
(Gain) loss on dispositions, net	(127)	2
Natural gas cost under recovery – long-term	(79)	0
Other, net	32	(21)
Changes in certain current assets and liabilities —
-Receivables	311	403
-Prepaid income taxes	(148)	(19)
-Natural gas cost under recovery	(432)	0
-Other current assets	(78)	(1)
-Accounts payable	30	(75)
-Other current liabilities	(57)	2
Net cash provided from operating activities	757	1,122
Investing Activities:
Property additions	(1,045)	(1,045)
Proceeds from dispositions	126	178
Cost of removal, net of salvage	(74)	(60)
Investment in unconsolidated subsidiaries	(3)	(79)
Other investing activities	30	33
Net cash used for investing activities	(966)	(973)
Financing Activities:
Increase in notes payable	38
Decrease in notes payable		(500)
Proceeds —
Senior notes	450	500
Short-term borrowings	300	0
First mortgage bonds	100	150
Redemptions and repurchases —
Senior notes	(300)	0
Medium-term notes	(30)	0
Capital contributions from parent company	63	215
Payment of common stock dividends	(397)	(399)
Other financing activities	(2)	(3)
Net cash provided from financing activities	222	(37)
Net Change in Cash, Cash Equivalents, and Restricted Cash	13	112
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	19	49
Cash, Cash Equivalents, and Restricted Cash at End of Period	32	161
Cash paid during the period for —
Interest, net of amounts capitalized	173	162
Income taxes, net	85	45
Noncash transactions —
Accrued property additions at end of period	$ 146	$ 146

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020
Interest capitalized	$ 68	$ 61
ALABAMA POWER CO
Interest capitalized	11	11
GEORGIA POWER CO
Interest capitalized	47	34
SOUTHERN POWER CO
Interest capitalized	5	10
SOUTHERN Co GAS
Interest capitalized	$ 6	$ 5

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Current Assets:
Cash and cash equivalents	$ 2,078	$ 1,065
Receivables —
Customer accounts	1,831	1,753
Energy marketing	0	516
Unbilled revenues	535	672
Other accounts and notes	611	512
Accumulated provision for uncollectible accounts	(72)	(118)
Materials and supplies	1,504	1,478
Fossil fuel for generation	386	550
Natural gas for sale	368	460
Prepaid expenses	329	276
Assets from risk management activities, net of collateral	365	147
Regulatory assets – asset retirement obligations	233	214
Natural gas cost under recovery	432	0
Other regulatory assets	792	810
Other current assets	282	282
Total current assets	9,674	8,617
Property, Plant, and Equipment:
In service	114,166	110,516
Less: Accumulated depreciation	33,723	32,397
Plant in service, net of depreciation	80,443	78,119
Nuclear fuel, at amortized cost	805	818
Construction work in progress	9,611	8,697
Total property, plant, and equipment	90,859	87,634
Other Property and Investments:
Goodwill	5,280	5,280
Nuclear decommissioning trusts, at fair value	2,446	2,303
Equity investments in unconsolidated subsidiaries	1,278	1,362
Other intangible assets, net of amortization	455	487
Leveraged leases	575	556
Miscellaneous property and investments	586	398
Total other property and investments	10,620	10,386
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,724	1,802
Deferred charges related to income taxes	815	796
Unamortized loss on reacquired debt	263	280
Regulatory assets – asset retirement obligations, deferred	5,418	4,934
Other regulatory assets, deferred	6,902	7,198
Other deferred charges and assets	1,586	1,288
Total deferred charges and other assets	16,708	16,298
Total Assets	127,861	122,935
Current Liabilities:
Securities due within one year	3,286	3,507
Notes payable	707	609
Energy marketing trade payables	0	494
Accounts payable —
Accounts payable	2,229	2,312
Customer deposits	493	487
Accrued taxes —
Accrued income taxes	149	130
Other accrued taxes	797	699
Accrued interest	404	513
Accrued compensation	908	1,025
Asset retirement obligations	690	585
Operating lease obligations	246	241
Other regulatory liabilities	555	509
Other current liabilities	795	968
Total current liabilities	11,259	12,079
Long-term Debt	48,843	45,073
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	8,916	8,175
Deferred credits related to income taxes	5,485	5,767
Accumulated deferred ITCs	2,230	2,235
Employee benefit obligations	1,849	2,213
Operating lease obligations, deferred	1,495	1,611
Asset retirement obligations, deferred	10,919	10,099
Accrued environmental remediation	203	216
Other cost of removal obligations	2,164	2,211
Other regulatory liabilities, deferred	351	251
Other deferred credits and liabilities	637	480
Total deferred credits and other liabilities	34,249	33,258
Total Liabilities	94,351	90,410
Redeemable Preferred Stock of Subsidiaries	291	291
Common Stockholder's Equity (See accompanying statements)	33,219	32,234
Total Liabilities and Stockholders' Equity	127,861	122,935
ALABAMA POWER CO
Current Assets:
Cash and cash equivalents	670	530
Receivables —
Customer accounts	497	429
Unbilled revenues	151	152
Affiliated	53	31
Other accounts and notes	101	66
Accumulated provision for uncollectible accounts	(18)	(43)
Materials and supplies	556	546
Fossil fuel for generation	144	235
Prepaid expenses	65	42
Other regulatory assets	289	226
Other current assets	107	33
Total current assets	2,615	2,247
Property, Plant, and Equipment:
In service	32,787	31,816
Less: Accumulated depreciation	10,298	10,009
Plant in service, net of depreciation	22,489	21,807
Nuclear fuel, at amortized cost	241	270
Construction work in progress	1,129	866
Total property, plant, and equipment	23,859	22,943
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,259	1,157
Equity investments in unconsolidated subsidiaries	57	63
Miscellaneous property and investments	129	131
Total other property and investments	1,445	1,351
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	119	151
Deferred charges related to income taxes	238	235
Regulatory assets – asset retirement obligations, deferred	1,580	1,441
Other regulatory assets, deferred	2,100	2,162
Other deferred charges and assets	348	273
Total deferred charges and other assets	4,385	4,262
Total Assets	32,304	30,803
Current Liabilities:
Securities due within one year	616	311
Accounts payable —
Affiliated	299	316
Other	370	545
Customer deposits	106	104
Accrued taxes —
Accrued taxes	331	152
Accrued interest	79	90
Accrued compensation	191	212
Asset retirement obligations	308	254
Other regulatory liabilities	72	108
Other current liabilities	122	107
Total current liabilities	2,494	2,199
Long-term Debt	8,443	8,558
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,425	3,273
Deferred credits related to income taxes	1,973	2,016
Accumulated deferred ITCs	89	94
Employee benefit obligations	136	214
Operating lease obligations, deferred	69	119
Asset retirement obligations, deferred	4,015	3,720
Other cost of removal obligations	261	335
Other regulatory liabilities, deferred	139	124
Other deferred credits and liabilities	66	50
Total deferred credits and other liabilities	10,173	9,945
Total Liabilities	21,110	20,702
Redeemable Preferred Stock	291	291
Common Stockholder's Equity (See accompanying statements)	10,903	9,810
Total Liabilities and Stockholders' Equity	32,304	30,803
GEORGIA POWER CO
Current Assets:
Cash and cash equivalents	292	9
Receivables —
Customer accounts	689	621
Unbilled revenues	258	233
Joint owner accounts	106	123
Affiliated	41	21
Other accounts and notes	46	67
Accumulated provision for uncollectible accounts	(2)	(26)
Materials and supplies	647	592
Fossil fuel for generation	201	278
Regulatory assets – storm damage	102	213
Regulatory assets – asset retirement obligations	191	166
Other regulatory assets	243	248
Other current assets	255	143
Total current assets	3,069	2,688
Property, Plant, and Equipment:
In service	40,831	39,682
Less: Accumulated depreciation	12,743	12,251
Plant in service, net of depreciation	28,088	27,431
Nuclear fuel, at amortized cost	564	548
Construction work in progress	7,337	6,857
Total property, plant, and equipment	35,989	34,836
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,187	1,145
Equity investments in unconsolidated subsidiaries	50	51
Miscellaneous property and investments	66	63
Total other property and investments	1,303	1,259
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,193	1,308
Deferred charges related to income taxes	544	527
Regulatory assets – asset retirement obligations, deferred	3,607	3,291
Other regulatory assets, deferred	2,515	2,692
Other deferred charges and assets	712	479
Total deferred charges and other assets	8,571	8,297
Total Assets	48,932	47,080
Current Liabilities:
Securities due within one year	672	542
Notes payable	0	60
Accounts payable —
Affiliated	719	597
Other	761	753
Customer deposits	263	276
Accrued taxes —
Accrued taxes	457	407
Accrued interest	98	130
Accrued compensation	207	233
Asset retirement obligations	333	287
Operating lease obligations	153	151
Other regulatory liabilities	360	228
Over recovered fuel clause revenues	0	113
Other current liabilities	198	254
Total current liabilities	4,221	4,031
Long-term Debt	13,064	12,428
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,222	3,272
Deferred credits related to income taxes	2,386	2,588
Accumulated deferred ITCs	321	273
Employee benefit obligations	461	586
Operating lease obligations, deferred	1,008	1,156
Asset retirement obligations, deferred	6,432	5,978
Other deferred credits and liabilities	456	267
Total deferred credits and other liabilities	14,286	14,120
Total Liabilities	31,571	30,579
Common Stockholder's Equity (See accompanying statements)	17,361	16,501
Total Liabilities and Stockholders' Equity	48,932	47,080
MISSISSIPPI POWER CO
Current Assets:
Cash and cash equivalents	146	39
Receivables —
Customer accounts	46	34
Unbilled revenues	39	38
Affiliated	45	32
Other accounts and notes	27	32
Materials and supplies	71	65
Fossil fuel for generation	27	24
Assets from risk management activities, net of collateral	66	1
Other regulatory assets	54	60
Other current assets	11	19
Total current assets	532	344
Property, Plant, and Equipment:
In service	5,078	5,011
Less: Accumulated depreciation	1,568	1,545
Plant in service, net of depreciation	3,510	3,466
Construction work in progress	117	146
Total property, plant, and equipment	3,627	3,612
Other Property and Investments:
Total other property and investments	180	151
Deferred Charges and Other Assets:
Deferred charges related to income taxes	31	32
Regulatory assets – asset retirement obligations, deferred	231	201
Other regulatory assets, deferred	371	388
Accumulated deferred income taxes	119	129
Other deferred charges and assets	100	55
Total deferred charges and other assets	852	805
Total Assets	5,191	4,912
Current Liabilities:
Securities due within one year	76	406
Notes payable	0	25
Accounts payable —
Affiliated	88	63
Other	61	109
Accrued taxes —
Accrued taxes	94	114
Accrued interest	7	15
Accrued compensation	31	34
Asset retirement obligations	19	27
Other regulatory liabilities	104	49
Over recovered fuel clause revenues	7	34
Other current liabilities	50	40
Total current liabilities	537	916
Long-term Debt	1,509	1,013
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	464	447
Deferred credits related to income taxes	276	287
Employee benefit obligations	94	113
Asset retirement obligations, deferred	175	150
Other cost of removal obligations	194	194
Other regulatory liabilities, deferred	48	15
Other deferred credits and liabilities	31	35
Total deferred credits and other liabilities	1,282	1,241
Total Liabilities	3,328	3,170
Common Stockholder's Equity (See accompanying statements)	1,863	1,742
Total Liabilities and Stockholders' Equity	5,191	4,912
SOUTHERN POWER CO
Current Assets:
Cash and cash equivalents	192	182
Receivables —
Customer accounts	178	125
Affiliated	68	37
Other accounts and notes	53	27
Materials and supplies	103	157
Prepaid income taxes	15	11
Other current assets	56	36
Total current assets	665	575
Property, Plant, and Equipment:
In service	14,399	13,904
Less: Accumulated depreciation	3,122	2,842
Plant in service, net of depreciation	11,277	11,062
Construction work in progress	274	127
Total property, plant, and equipment	11,551	11,189
Other Property and Investments:
Intangible assets, net of amortization	288	302
Equity investments in unconsolidated subsidiaries	83	19
Net investment in sales-type lease	91	0
Total other property and investments	462	321
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	475	415
Prepaid LTSAs	191	155
Accumulated deferred income taxes	0	262
Income taxes receivable, non-current	33	25
Other deferred charges and assets	234	293
Total deferred charges and other assets	933	1,150
Total Assets	13,611	13,235
Current Liabilities:
Securities due within one year	994	299
Notes payable	27	175
Accounts payable —
Affiliated	110	65
Other	91	92
Accrued taxes —
Accrued income taxes	8	8
Other accrued taxes	27	22
Accrued interest	26	32
Other current liabilities	125	132
Total current liabilities	1,408	825
Long-term Debt	3,021	3,393
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	156	123
Accumulated deferred ITCs	1,629	1,672
Operating lease obligations, deferred	489	426
Other deferred credits and liabilities	201	165
Total deferred credits and other liabilities	2,475	2,386
Total Liabilities	6,904	6,604
Common Stockholder's Equity (See accompanying statements)	6,707	6,631
Total Liabilities and Stockholders' Equity	13,611	13,235
SOUTHERN Co GAS
Current Assets:
Cash and cash equivalents	29	17
Receivables —
Customer accounts	249	353
Energy marketing	0	516
Unbilled revenues	70	219
Affiliated	1	4
Other accounts and notes	39	51
Accumulated provision for uncollectible accounts	(37)	(40)
Natural gas for sale	368	460
Prepaid expenses	181	48
Assets from risk management activities, net of collateral	75	118
Natural gas cost under recovery	432	0
Other regulatory assets	137	102
Other current assets	44	38
Total current assets	1,588	1,886
Property, Plant, and Equipment:
In service	18,527	17,611
Less: Accumulated depreciation	5,004	4,821
Plant in service, net of depreciation	13,523	12,790
Construction work in progress	691	648
Total property, plant, and equipment	14,214	13,438
Other Property and Investments:
Goodwill	5,015	5,015
Equity investments in unconsolidated subsidiaries	1,174	1,290
Other intangible assets, net of amortization	40	51
Miscellaneous property and investments	20	19
Total other property and investments	6,249	6,375
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	72	81
Other regulatory assets, deferred	634	615
Other deferred charges and assets	201	235
Total deferred charges and other assets	907	931
Total Assets	22,958	22,630
Current Liabilities:
Securities due within one year	47	333
Notes payable	662	324
Energy marketing trade payables	0	494
Accounts payable —
Affiliated	42	56
Other	399	373
Customer deposits	106	90
Accrued taxes —
Accrued taxes	79	83
Accrued interest	68	58
Accrued compensation	87	106
Other regulatory liabilities	18	122
Temporary LIFO liquidation	18	0
Other current liabilities	154	150
Total current liabilities	1,680	2,189
Long-term Debt	6,766	6,293
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,571	1,265
Deferred credits related to income taxes	822	847
Employee benefit obligations	260	283
Operating lease obligations, deferred	60	67
Accrued environmental remediation	203	216
Other cost of removal obligations	1,675	1,649
Other deferred credits and liabilities	45	54
Total deferred credits and other liabilities	4,636	4,381
Total Liabilities	13,082	12,863
Common Stockholder's Equity (See accompanying statements)	9,876	9,767
Total Liabilities and Stockholders' Equity	$ 22,958	$ 22,630

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Other intangible assets, amortization	$ 296	$ 328
SOUTHERN POWER CO
Other intangible assets, amortization	104	89
SOUTHERN Co GAS
Other intangible assets, amortization	$ 142	$ 195

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, 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]
Consolidated net income (loss)	837				868		(31)
Net income (loss)													331			331		32			32		44	75		75		(31)	275		275
Net income after dividends on preferred stock								280			280
Capital contributions from parent company								612		612			502		502			76		76
Return of capital to parent company																		(37)		(37)									(2)	(2)
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)
Capital 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 after dividends on preferred stock	2,732																												360
Purchase of membership interests from noncontrolling interests																							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]
Consolidated net income (loss)	617				612		5
Net income (loss)													308			308		39			39		68	63		63		5	71		71
Net income after dividends on preferred stock								298			298
Capital contributions from parent company								1		1			1		1														200	200
Return of capital to parent company																		(37)		(37)
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)
Capital contributions from noncontrolling interests	165						165																165					165
Distributions to noncontrolling interests	(70)						(70)																(70)					(70)
Other	(12)			(13)	1																		(2)	(2)	(2)
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]
Consolidated 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 after dividends on preferred stock	1,251							444			444																		14
Capital contributions from parent company								40		40			880		880			6		6									30	30
Return of capital to parent company																							(4)	(4)	(4)
Other comprehensive income (loss)	20					20		1				1	2				2						8	8			8		5			5
Stock issued (in shares)		0
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)
Capital contributions from noncontrolling interests	2						2																2					2
Distributions to noncontrolling interests	(51)						(51)																(51)					(51)
Purchase of membership interests from noncontrolling interests																								5	5
Purchase of membership interests from noncontrolling interests	(55)						(60)																(55)					(60)
Other	1		$ 0	0	1	(1)	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)
Beginning balance (in shares) at Dec. 31, 2020		1,058	1						31					9					1
Beginning balance at Dec. 31, 2020	32,234	$ 5,268	$ (46)	11,834	11,311	(395)	4,262	9,810	$ 1,222	5,413	3,194	(19)	16,501	$ 398	12,361	3,789	(47)	1,742	$ 38	4,460	(2,754)	(2)	6,631	2,369	914	1,522	(67)	4,262	9,767	9,930	(141)	(22)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated net income (loss)	1,103				1,135		(32)
Net income (loss)													351			351		45			45		65	97		97		(32)	398		398
Net income after dividends on preferred stock								359			359
Capital contributions from parent company								602		602			332		332			100		100									57	57
Return of capital to parent company																							(271)	(271)	(271)
Other comprehensive income (loss)	28					28		1				1	2				2						16	16			16		4			4
Stock issued (in shares)		2
Stock issued	14	$ 5		9
Stock-based compensation	9			9
Cash dividends on common stock	(678)				(678)			(246)			(246)		(412)			(412)		(39)			(39)		(51)	(51)		(51)			(132)		(132)
Capital contributions from noncontrolling interests	403						403																403					403
Distributions to noncontrolling interests	(46)						(46)																(46)					(46)
Other	1			2			(1)																(3)	(2)	(2)	1	(1)	(1)
Ending balance (in shares) at Mar. 31, 2021		1,060	1						31					9					1
Ending balance at Mar. 31, 2021	33,068	$ 5,273	$ (46)	11,854	11,768	(367)	4,586	10,526	$ 1,222	6,015	3,307	(18)	16,774	$ 398	12,693	3,728	(45)	1,848	$ 38	4,560	(2,748)	(2)	6,744	2,158	641	1,569	(52)	4,586	10,094	9,987	125	(18)
Beginning balance (in shares) at Dec. 31, 2020		1,058	1						31					9					1
Beginning balance at Dec. 31, 2020	32,234	$ 5,268	$ (46)	11,834	11,311	(395)	4,262	9,810	$ 1,222	5,413	3,194	(19)	16,501	$ 398	12,361	3,789	(47)	1,742	$ 38	4,460	(2,754)	(2)	6,631	2,369	914	1,522	(67)	4,262	9,767	9,930	(141)	(22)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	2,592							1,200					1,030					133					184						389
Net income after dividends on preferred stock	2,608																												389
Purchase of membership interests from noncontrolling interests																							0
Ending balance (in shares) at Sep. 30, 2021		1,061	1						31					9					1
Ending balance at Sep. 30, 2021	33,219	$ 5,278	$ (46)	11,932	11,844	(319)	4,530	10,903	$ 1,222	6,050	3,644	(13)	17,361	$ 398	13,423	3,582	(42)	1,863	$ 38	4,565	(2,739)	(1)	6,707	2,177	643	1,581	(47)	4,530	9,876	10,014	(149)	11
Beginning balance (in shares) at Mar. 31, 2021		1,060	1						31					9					1
Beginning balance at Mar. 31, 2021	33,068	$ 5,273	$ (46)	11,854	11,768	(367)	4,586	10,526	$ 1,222	6,015	3,307	(18)	16,774	$ 398	12,693	3,728	(45)	1,848	$ 38	4,560	(2,748)	(2)	6,744	2,158	641	1,569	(52)	4,586	10,094	9,987	125	(18)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated net income (loss)	372				372
Net income (loss)													143			143		38			38		36	36		36			(65)		(65)
Net income after dividends on preferred stock								331			331
Capital contributions from parent company								26		26			40		40			2		2									25	25
Other comprehensive income (loss)	12					12		1				1	1				1						(3)	(3)			(3)		8			8
Stock issued	10	$ 1		9
Stock-based compensation	22			22
Cash dividends on common stock	(699)				(699)			(246)			(246)		(412)			(412)		(39)			(39)		(51)	(51)		(51)			(133)		(133)
Capital contributions from noncontrolling interests	29						29																29					29
Distributions to noncontrolling interests	(68)						(68)																(68)					(68)
Other	0		$ (2)	1	1			(1)			(1)							0			(1)	1	3	3	2		1
Ending balance (in shares) at Jun. 30, 2021		1,060	1						31					9					1
Ending balance at Jun. 30, 2021	32,746	$ 5,274	$ (48)	11,886	11,442	(355)	4,547	10,637	$ 1,222	6,041	3,391	(17)	16,546	$ 398	12,733	3,459	(44)	1,849	$ 38	4,562	(2,750)	(1)	6,690	2,143	643	1,554	(54)	4,547	9,929	10,012	(73)	(10)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated net income (loss)	1,106				1,101		5
Net income (loss)	1,110							503					536			536		50			50		83	78		78		5	56		56
Net income after dividends on preferred stock	1,101							499			499																		56
Capital contributions from parent company								9		9			690		690			3		3									2	2
Other comprehensive income (loss)	36					36		5				5	2				2						7	7			7		21			21
Stock issued (in shares)		1
Stock issued	38	$ 4		34
Stock-based compensation	22			22
Cash dividends on common stock	(700)				(700)			(246)			(246)		(413)			(413)		(39)			(39)		(51)	(51)		(51)			(132)		(132)
Capital contributions from noncontrolling interests	72						72																73					73
Distributions to noncontrolling interests	(94)						(94)																(95)					(95)
Other	(7)		$ 2	(10)	1	0	0	(1)	$ 0	0	0	(1)											1					1
Ending balance (in shares) at Sep. 30, 2021		1,061	1						31					9					1
Ending balance at Sep. 30, 2021	$ 33,219	$ 5,278	$ (46)	$ 11,932	$ 11,844	$ (319)	$ 4,530	$ 10,903	$ 1,222	$ 6,050	$ 3,644	$ (13)	$ 17,361	$ 398	$ 13,423	$ 3,582	$ (42)	$ 1,863	$ 38	$ 4,565	$ (2,739)	$ (1)	$ 6,707	$ 2,177	$ 643	$ 1,581	$ (47)	$ 4,530	$ 9,876	$ 10,014	$ (149)	$ 11

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Consolidated Statements of Stockholders' Equity (Unaudited) (Parenthetical) - $ / shares	3 Months Ended
	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020
Statement of Stockholders' Equity [Abstract]
Cash dividends (in dollars per share)	$ 0.66	$ 0.66	$ 0.64	$ 0.64	$ 0.64	$ 0.62

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Introduction

9 Months Ended

Sep. 30, 2021

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 at December 31, 2020 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, 2021 and 2020. 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, 2021 and December 31, 2020 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.

Other intangible assets were as follows:

	At September 30, 2021						At December 31, 2020
	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	$	(148)	$	64	$	212	$	(135)	$	77
Trade names	64		(36)		28		64		(31)		33
Storage and transportation contracts(*)	—		—		—		64		(64)		—
PPA fair value adjustments	390		(104)		286		390		(89)		301
Other	10		(8)		2		10		(9)		1
Total other intangible assets subject to amortization	$	676	$	(296)	$	380	$	740	$	(328)	$	412
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—		75		75		—		75
Total other intangible assets	$	751	$	(296)	$	455	$	815	$	(328)	$	487
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	390	$	(104)	$	286	$	390	$	(89)	$	301
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	156	$	(128)	$	28	$	156	$	(119)	$	37
Trade names	26		(14)		12		26		(12)		14
Wholesale gas services
Storage and transportation contracts(*)	—		—		—		64		(64)		—
Total other intangible assets subject to amortization	$	182	$	(142)	$	40	$	246	$	(195)	$	51

(*)See Note (K) under "Southern Company Gas" for information regarding the sale of Sequent.

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Nine Months Ended
	September 30, 2021
	(in millions)
Southern Company(a)	$	11	$	33
Southern Power(b)	5		15
Southern Company Gas(c)	4		11

(a)Includes $5 million and $15 million for the three and nine months ended September 30, 2021, respectively, recorded as a reduction to operating revenues.

(b)Recorded as a reduction to operating revenues.

(c)Relates to gas marketing services.

Cash, Cash Equivalents, and Restricted Cash

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amount shown in the condensed statements of cash flows for the applicable Registrants:

	Southern Company				Southern Power		Southern Company Gas
	September 30, 2021		December 31, 2020		September 30, 2021		September 30, 2021		December 31, 2020
	(in millions)				(in millions)		(in millions)
Cash and cash equivalents	$	2,078	$	1,065	$	192	$	29	$	17
Restricted cash(a):
Other current assets	3		2		—		3		2
Other deferred charges and assets	21		—		21		—		—
Total cash, cash equivalents, and restricted cash(b)	$	2,101	$	1,068	$	213	$	32	$	19

(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 may not add due to rounding.

Natural Gas for Sale

With the exception of Nicor Gas, Southern Company Gas records natural gas inventories on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated.

Southern Company Gas recorded no material adjustments to natural gas inventories for any period presented. Nicor Gas' inventory decrement at September 30, 2021 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, Georgia Power, and Mississippi Power during the first nine months of 2021 are shown in the following table. There were no material changes in AROs for the other Registrants during the first nine months of 2021.

	Southern Company		Alabama Power		Georgia Power		Mississippi Power
	(in millions)
Balance at December 31, 2020	$	10,684	$	3,974	$	6,265	$	176
Liabilities incurred	17		—		3		—
Liabilities settled	(341)		(152)		(154)		(18)
Accretion	304		116		176		6
Cash flow revisions	945		385		475		30
Balance at September 30, 2021	$	11,609	$	4,323	$	6,765	$	194

In August 2021, Alabama Power recorded an increase of approximately $385 million to its AROs related to the CCR Rule and the related state rule based on updated estimates for post-closure costs at its ash ponds and inflation rates.

In September 2021, Georgia Power recorded an increase of approximately $435 million to its AROs related to the CCR Rule and the related state rule based on updated estimates for inflation rates and the timing of closure activities.

In September 2021, Mississippi Power recorded an increase of approximately $30 million to its AROs related to the CCR Rule based on updated estimates for the timing of closure activities, post-closure costs at one of its ash ponds, and inflation rates.

The traditional electric operating companies have periodically updated, and expect to continue periodically updating, their related cost estimates and ARO liabilities for each CCR unit as additional information related to these assumptions becomes available. Some of these updates have been, and future updates may 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) under "Georgia Power – Rate Plan" for additional information. The ultimate outcome of these matters cannot be determined at this time.

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Regulatory Matters

9 Months Ended

Sep. 30, 2021

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, 2021 and December 31, 2020 were as follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2021		December 31, 2020
		(in millions)
Alabama Power
Rate CNP Compliance	Other regulatory liabilities, current	$	—	$	28
	Other regulatory liabilities, deferred	24		—
Rate CNP PPA	Other regulatory assets, deferred	88		58
Retail Energy Cost Recovery	Other regulatory liabilities, current	—		18
	Other regulatory assets, current	79		—
	Other regulatory assets, deferred	6		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	36		77
Georgia Power
Fuel Cost Recovery	Over recovered fuel clause revenues	$	—	$	113
	Other deferred charges and assets	203		—
Mississippi Power
Fuel Cost Recovery	Over recovered regulatory clause liabilities	$	5	$	24
Ad Valorem Tax	Other regulatory assets, current	12		11
	Other regulatory assets, deferred	39		41
Property Damage Reserve	Other regulatory liabilities, deferred	—		4
	Other regulatory assets, deferred	16		—
Southern Company Gas
Natural Gas Cost Recovery(*)	Other regulatory liabilities	$	—	$	88
	Natural gas cost under recovery	432		—
	Other regulatory assets, deferred	79		—

(*)The significant change during the nine months ended September 30, 2021 was primarily driven by an increase in the cost of gas purchased in February 2021 resulting from Winter Storm Uri.

Alabama Power

Certificate of Convenience and Necessity

Energy Alabama, Gasp, Inc., and the Sierra Club filed requests for reconsideration and rehearing with the Alabama PSC regarding the certificate of convenience and necessity (CCN) issued to Alabama Power in August 2020, which authorized, among other things, the construction of Plant Barry Unit 8 and the acquisition of the Central Alabama Generating Station. In December 2020, the Alabama PSC issued an order denying the requests. On January 7, 2021, Energy Alabama and Gasp, Inc. filed a judicial appeal regarding both the Alabama PSC's August 2020 CCN order and the December 2020 order denying reconsideration and rehearing. On March 9, 2021, the Circuit Court of Montgomery County, Alabama granted a motion by Alabama Power to intervene in the appeal. On August 27, 2021, the court affirmed both the August 2020 and December 2020 Alabama PSC orders. On October 7, 2021, Energy Alabama and Gasp, Inc. filed an unopposed motion for voluntary dismissal of their direct appeal previously

filed on January 7, 2021. This matter is now concluded. At September 30, 2021, expenditures associated with the construction of Plant Barry Unit 8 included in CWIP totaled approximately $222 million.

Plant Greene County

Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 5 under "Joint Ownership Agreements" in Item 8 of the Form 10-K for additional information.

On September 9, 2021, the Mississippi PSC issued an order confirming the conclusion of its review of Mississippi Power's 2021 IRP with no deficiencies identified. Mississippi Power's 2021 IRP includes a schedule to retire Mississippi Power's 40% ownership interest in Plant Greene County Units 1 and 2 in December 2025 and 2026, respectively, consistent with each unit's remaining useful life. The Plant Greene County unit retirements identified by Mississippi Power require the completion of transmission and system reliability improvements, as well as agreement by Alabama Power. Alabama Power will continue to monitor the status of the transmission and system reliability improvements. Currently, Alabama Power plans to retire Plant Greene County Units 1 and 2 at the dates indicated. The ultimate outcome of this matter cannot be determined at this time.

Rate NDR

Based on an order from the Alabama PSC, when Alabama Power's NDR balance falls below $50 million, a reserve establishment charge will be activated and the ongoing reserve maintenance charge will be concurrently suspended until the NDR balance reaches $75 million. At September 30, 2021, Alabama Power's NDR balance was $36 million. Effective with October 2021 billings, the reserve maintenance charge component of Rate NDR was suspended and the reserve establishment charge was activated. Alabama Power expects to collect approximately $4 million in the fourth quarter 2021 and $16 million annually under Rate NDR until the NDR balance is restored to $75 million.

Calhoun Generating Station Acquisition

On September 23, 2021, Alabama Power entered into an agreement to acquire all of the equity interests in Calhoun Power Company, LLC, which owns and operates a 743-MW winter peak, simple-cycle, combustion turbine generation facility in Calhoun County, Alabama (Calhoun Generating Station). The total purchase price associated with the acquisition is approximately $180 million, subject to working capital adjustments. The completion of the acquisition is subject to the satisfaction and waiver of certain conditions, including, among other customary conditions, approval by the Alabama PSC and the FERC, as well as the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act. Alabama Power expects to complete the transaction by September 30, 2022.

On October 28, 2021, Alabama Power filed a petition for a CCN with the Alabama PSC to procure additional generating capacity through the acquisition of the Calhoun Generating Station.

Upon certification, Alabama Power expects to recover costs associated with the Calhoun Generating Station through its existing rate structure, primarily Rate CNP New Plant, Rate CNP Compliance, Rate ECR, and Rate RSE.

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

Georgia Power

Rate Plan

Effective January 1, 2021, Georgia Power reduced its amortization of costs associated with CCR AROs by approximately $90 million as approved by the Georgia PSC in conjunction with Georgia Power's annual compliance filings.

In February 2020, the Georgia PSC denied a motion for reconsideration filed by the Sierra Club regarding the Georgia PSC's decision in the 2019 ARP allowing Georgia Power to recover compliance costs for CCR AROs, and, in December 2020, the Superior Court of Fulton County affirmed the decision of the Georgia PSC. On October 25,

2021, the Georgia Court of Appeals affirmed the Superior Court of Fulton County's December 2020 order. On November 3, 2021, the Sierra Club filed a motion for reconsideration with the Georgia Court of Appeals. The ultimate outcome of this matter cannot be determined at this time.

In accordance with the terms of the 2019 ARP, on October 1, 2021, Georgia Power filed the following tariff adjustments to become effective January 1, 2022 pending approval by the Georgia PSC:

•increase traditional base tariffs by approximately $192 million;

•decrease the ECCR tariff by approximately $12 million;

•decrease Demand-Side Management tariffs by approximately $25 million; and

•increase Municipal Franchise Fee tariffs by approximately $2 million.

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

See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.

Plant Vogtle Unit 3 and Common Facilities Rate Proceeding

On June 15, 2021, Georgia Power filed an application with the Georgia PSC to adjust retail base rates to include the portion of costs related to its investment in Plant Vogtle Unit 3 and the common facilities shared between Plant Vogtle Units 3 and 4 (Common Facilities) previously deemed prudent by the Georgia PSC ($2.38 billion), as well as the related costs of operation. On November 2, 2021, the Georgia PSC voted to approve Georgia Power's application as filed, with the following modifications pursuant to a stipulated agreement between Georgia Power and the staff of the Georgia PSC. Georgia Power will include in rate base $2.1 billion of the $2.38 billion previously deemed prudent by the Georgia PSC and will recover the related depreciation expense through retail base rates. Financing costs on the remaining portion of the total Unit 3 and the Common Facilities construction costs will continue to be recovered through the NCCR tariff or deferred. Georgia Power will defer as a regulatory asset the remaining depreciation expense (approximately $38 million annually) until Unit 4 costs are placed in retail base rates. In addition, the stipulated agreement clarified that following the prudency review, the remaining amount to be placed in retail base rates will be net of the proceeds from the Guarantee Settlement Agreement and will not be used to offset imprudent costs, if any.

The related increase in annual retail base rates of approximately $302 million also includes recovery of all projected operations and maintenance expenses for Unit 3 and the Common Facilities and other related costs of operation, partially offset by the related production tax credits, and will become effective the month after Unit 3 is placed in service. This increase will be partially offset by a decrease in the NCCR tariff of approximately $78 million expected to be effective January 1, 2022.

See "Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

Deferral of Incremental COVID-19 Costs

Since June 2021, Georgia Power has continued a review of bad debt amounts deferred under the Georgia PSC-approved methodology, including consideration of actual amounts repaid by customers from arrears and installment plans after the disconnection moratorium period ended in July 2020. As a result, Georgia Power has reduced the balance of deferred incremental costs by a total of approximately $23 million through September 30, 2021. At September 30, 2021, the incremental costs deferred totaled approximately $20 million, including approximately $1 million of incremental bad debt costs and $19 million of other incremental costs. The period over which these costs will be recovered is expected to be determined in Georgia Power's next base rate case. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. On October 12, 2021, Georgia Power filed a notification and plan with the Georgia PSC to implement an interim fuel rider and increase

fuel rates by 15% effective January 1, 2022, which is expected to increase annual billings by approximately $252 million. The Georgia PSC has 30 days from the filing to approve the plan; however, if the Georgia PSC elects to take no action, the new rates become effective as requested. Georgia Power is currently scheduled to file its next fuel case by February 28, 2023. The ultimate outcome of this matter cannot be determined at this time.

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 connection with the EPC Contractor's bankruptcy filing in March 2017, 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, including contingency, through September 2022 and June 2023, respectively, is as follows:

	(in millions)
Base project capital cost forecast(a)(b)	$	9,342
Construction contingency estimate	137
Total project capital cost forecast(a)(b)	9,479
Net investment at September 30, 2021(b)	(8,159)
Remaining estimate to complete	$	1,320

(a)    Includes approximately $570 million of costs that are not shared with the other Vogtle Owners. Excludes financing costs expected to be capitalized through AFUDC of approximately $318 million, of which $169 million had been accrued through September 30, 2021.

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

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.2 billion, of which $2.8 billion had been incurred through September 30, 2021.

As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers and related test results, and workforce statistics. Southern Nuclear establishes aggressive target values for monthly construction production and system turnover activities. Southern Nuclear's site work plans continue to reflect this approach in support of safely completing Units 3 and 4, while achieving the required construction quality.

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 tested positive for COVID-19, showed symptoms consistent with COVID-19, were being tested for COVID-19, or were in close contact with such persons; requiring self-quarantine; and adopting additional precautionary measures. Since March 2020, the number of active cases at the site has fluctuated and impacted productivity levels and pace of activity completion. Through June 2021, the site experienced an overall decline in the number of active cases since the peak in January 2021. During the third quarter 2021, the site experienced a similar peak in August 2021; however, the number of active cases since this peak has declined. The lower productivity levels and slower pace of activity completion experienced since March 2020 contributed to a backlog to the aggressive site work plan established at the beginning of 2020. Georgia Power estimates the productivity impacts of the COVID-19 pandemic have consumed approximately three to four months of schedule margin previously embedded in the site work plan for Unit 3 and Unit 4. In addition, the project continued to face challenges including, but not limited to, higher than expected absenteeism; overall construction and subcontractor labor productivity; system turnover and testing activities; and electrical equipment and commodity installation. As a result of these factors, in January 2021, Southern Nuclear further extended certain milestone dates, including the start of hot functional testing and fuel load for Unit 3, from those established in October 2020.

Following the January 2021 milestone extensions, Southern Nuclear has been performing additional construction remediation work necessary to ensure quality and design standards are met as system turnovers are completed to support hot functional testing, which was completed in July 2021, and fuel load for Unit 3. As a result of challenges including, but not limited to, construction productivity, construction remediation work, the pace of system turnovers, spent fuel pool repairs, and the timeframe and duration for hot functional and other testing, at the end of the second quarter 2021, Southern Nuclear further extended certain milestone dates, including the fuel load for Unit 3, from those established in January 2021. Through the third quarter 2021, the project continued to face challenges including, but not limited to, construction productivity, construction remediation work, and the pace of system turnovers. As a result of these continued challenges, at the end of the third quarter 2021, Southern Nuclear further extended certain milestone dates, including fuel load for Unit 3, from those established at the end of the second quarter 2021. The site work plan currently targets fuel load for Unit 3 in the first quarter 2022 and an in-service date of May 2022 and primarily depends on significant improvements in overall construction productivity and production levels, the volume of construction remediation work, the pace of system and area turnovers, and the progression of startup and other testing. As the site work plan includes minimal margin to these milestone dates, an in-service date in the third quarter 2022 for Unit 3 is projected, although any further delays could result in a later in-service date.

As the result of productivity challenges, at the end of the second quarter 2021, Southern Nuclear also further extended milestone dates for Unit 4 from those established in January 2021. These productivity challenges continued into the third quarter 2021 and some craft and support resources were diverted temporarily to support construction efforts on Unit 3. As a result of these factors, at the end of the third quarter 2021, Southern Nuclear further extended the milestone dates for Unit 4 from those established at the end of the second quarter 2021. The site work plan targets an in-service date of March 2023 for Unit 4 and primarily depends on overall construction productivity and production levels significantly improving as well as appropriate levels of craft laborers, particularly electricians and pipefitters, being added and maintained. As the site work plan includes minimal margin

to the milestone dates, an in-service date in the second quarter 2023 for Unit 4 is projected, although any further delays could result in a later in-service date.

As of March 31, 2021, approximately $84 million of the construction contingency established in the fourth quarter 2020 was assigned to the base capital cost forecast for costs primarily associated with the schedule extension for Unit 3 to December 2021, construction productivity, support resources, and construction remediation work. Georgia Power increased its total capital cost forecast as of March 31, 2021 by adding $48 million to the remaining construction contingency. As of June 30, 2021, all of the remaining construction contingency previously established and an additional $341 million was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units 3 and 4, construction remediation work for Unit 3, and construction productivity and support resources for Units 3 and 4. Georgia Power also increased its total capital cost forecast as of June 30, 2021 by adding $119 million to replenish construction contingency. As a result of the factors discussed above, during the third quarter 2021, all of the remaining construction contingency previously established in the second quarter 2021 and an additional $127 million was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units 3 and 4, construction productivity and support resources for Units 3 and 4, and construction remediation work for Unit 3. Georgia Power also increased its total capital cost forecast as of September 30, 2021 by adding $137 million to replenish construction contingency.

After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded pre-tax charges to income in the first quarter 2021, the second quarter 2021, and the third quarter 2021 of $48 million ($36 million after tax), $460 million ($343 million after tax), and $264 million ($197 million after tax), respectively, for the increases in the total project capital cost forecast. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.

In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction and testing 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 $160 million and $200 million and is included in the total project capital cost forecast.

As construction, including subcontract work, continues and testing and system turnover activities increase, ongoing or future 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), including the spent fuel pools, any of which may require additional labor and/or materials; or other issues could continue or arise and change the projected schedule and estimated cost.

There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to ensure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. In connection with the additional construction remediation work described above, Southern Nuclear reviewed the project's construction quality programs and, where needed, is implementing improvement plans consistent with these processes. In June 2021, the NRC began a special inspection to review the root cause of this additional construction remediation work and the corresponding corrective action plans. On August 26, 2021, the NRC issued an inspection report with initial findings. Southern Nuclear had already identified and self-reported many of the issues in this report to the NRC and implemented corrective-action plans to resolve these issues. Southern Nuclear responded to the NRC's initial findings on October 5, 2021 and expects a final report from the NRC by November 24, 2021. Findings resulting from this or other inspections could require additional remediation

and/or further NRC oversight. In addition, certain license amendment requests have been filed and approved or are pending before the NRC. On March 15, 2021, the NRC denied the Blue Ridge Environmental Defense League's (BREDL) December 2020 motion to reopen proceedings on BREDL's petition challenging a requested license amendment, which has been issued by the NRC staff.

The site work plan currently targets fuel load for Unit 3 in the first quarter 2022. 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, have arisen or may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues, including inspections and ITAACs, are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the in-service date beyond the third quarter 2022 for Unit 3 or the second quarter 2023 for Unit 4 is currently estimated to result in additional base capital costs for Georgia Power of approximately $25 million per month for Unit 3 and approximately $15 million per month for Unit 4, as well as the related AFUDC and any additional related construction or testing costs. 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.

Georgia Power and the other Vogtle Owners do not agree on either the starting dollar amount for the determination of cost increases subject to the cost-sharing and tender provisions of the Global Amendments or the extent to which COVID-19-related costs impact the calculation. Based on the definition in the Global Amendments, Georgia Power believes the starting dollar amount is $18.38 billion and does not believe estimated project costs have reached a level where cost-sharing would be triggered. However, the other Vogtle Owners have asserted the cost increases through September 30, 2021 have reached the cost-sharing thresholds and could be sufficient to trigger the tender provisions under the Global Amendments, which could require Georgia Power to record additional pre-tax charges to income of up to approximately $350 million. On October 29, 2021, Georgia Power and the other Vogtle Owners entered into an agreement to clarify the process for the tender provisions of the Global Amendments, which will provide additional time to resolve these matters.

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, 2021, Georgia Power had recovered approximately $2.7 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, 2021, Georgia Power filed a request to decrease the NCCR tariff by $78 million annually, effective January 1, 2022, pending approval by the Georgia PSC.

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 $0.3 billion 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 a prudence proceeding on cost recovery will occur following Unit 4 fuel load, 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 alternate rate plan) 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 effective the first month after Unit 3 reaches commercial operation, retail base rates would be adjusted to include the costs related to Unit 3 and common facilities 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 $150 million in 2020 and are estimated to have negative earnings impacts of approximately $270 million, $260 million, and $135 million in 2021, 2022, and 2023, respectively. In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.

The Georgia PSC has approved 24 VCM reports covering periods through December 31, 2020, including total construction capital costs incurred through December 31, 2020 of $7.3 billion (net of $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). In the August 24, 2021 order approving the twenty-fourth VCM report, the Georgia PSC also approved a stipulation addressing the following matters: (i) beginning with its twenty-fifth VCM report, Georgia Power will continue to report to the Georgia PSC all costs incurred during the period for review and will request for approval costs up to the $7.3 billion determined to be reasonable in the Georgia PSC's seventeenth VCM order and (ii) Georgia Power will not seek rate recovery of the $0.7 billion increase to the base capital cost forecast included in the nineteenth VCM report and charged to income by Georgia Power in the second quarter 2018. In addition, the stipulation

confirms Georgia Power may request verification and approval of costs above $7.3 billion for inclusion in rate base at a later time, but no earlier than the prudence review contemplated by the seventeenth VCM order described previously. Georgia Power filed its twenty-fifth VCM report with the Georgia PSC on August 31, 2021, which reflects the revised capital cost forecast as of June 30, 2021 of $9.2 billion (net of $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). See "Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" herein for information on Georgia Power's request to adjust retail base rates to include a portion of costs related to its investment in Plant Vogtle Unit 3 and Common Facilities.

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

Mississippi Power

Performance Evaluation Plan

On June 8, 2021, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2021, resulting in an annual increase in revenues of approximately $16 million, or 1.8%, which became effective with the first billing cycle of April 2021 in accordance with the PEP rate schedule.

Integrated Resource Plan

In December 2020, the Mississippi PSC issued an order in the Reserve Margin Plan docket requiring Mississippi Power to incorporate into its 2021 IRP a schedule reflecting the retirement of 950 MWs of fossil-steam generation by year-end 2027 to reduce Mississippi Power's excess reserve margin. On September 9, 2021, the Mississippi PSC issued an order confirming the conclusion of its review of Mississippi Power's 2021 IRP with no deficiencies identified. The 2021 IRP includes a schedule to retire Plant Watson Unit 4 (268 MWs) and Mississippi Power's 40% ownership interest in Plant Greene County Units 1 and 2 (103 MWs each) in December 2023, 2025, and 2026, respectively, consistent with each unit's remaining useful life in the most recent approved depreciation studies. In addition, the schedule reflects the early retirement of Mississippi Power's 50% undivided ownership interest in Plant Daniel Units 1 and 2 (502 MWs) by the end of 2027. The Plant Greene County unit retirements require the completion by Alabama Power of transmission and system reliability improvements, as well as agreement by Alabama Power.

The remaining net book value of Plant Daniel Units 1 and 2 was approximately $520 million at September 30, 2021 and Mississippi Power is continuing to depreciate these units using the current approved rates through the end of 2027. Mississippi Power expects to reclassify the net book value remaining at retirement, which is expected to total approximately $390 million, to a regulatory asset to be amortized over a period to be determined by the Mississippi PSC in future proceedings, consistent with the December 2020 order. The Plant Watson and Greene County units are expected to be fully depreciated upon retirement. The ultimate outcome of these matters cannot be determined at this time.

Environmental Compliance Overview Plan

On June 8, 2021, the Mississippi PSC approved Mississippi Power's ECO Plan filing for 2021, resulting in an annual decrease in revenues of approximately $9 million, primarily due to a change in the amortization periods of certain regulatory assets and liabilities. The rate decrease became effective with the first billing cycle of July 2021.

Ad Valorem Tax Adjustment

On April 6, 2021, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment filing for 2021, which requested an annual increase in revenues of approximately $28 million, including approximately $19 million of ad valorem taxes previously recovered through PEP in accordance with the Mississippi Power Rate Case Settlement Agreement. The rate increase became effective with the first billing cycle of May 2021.

System Restoration Rider

On October 14, 2021, the Mississippi PSC issued an accounting order giving Mississippi Power the authority to reclassify the retail costs associated with Hurricanes Zeta and Ida to a regulatory asset to be recovered through PEP over a period to be determined in Mississippi Power's 2022 PEP proceeding. At September 30, 2021, these costs totaled approximately $49 million.

On October 25, 2021, Mississippi Power made its annual System Restoration Rider filing with the Mississippi PSC, which requested an annual increase in retail revenues of approximately $9 million primarily for an increase in the property damage reserve accrual. The requested increase is expected to become effective with the first billing cycle following approval by the Mississippi PSC. The filing excludes recovery of the costs associated with Hurricanes Zeta and Ida.

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

Southern Company Gas

Infrastructure Replacement Programs and Capital Projects

Capital expenditures incurred under specific infrastructure replacement programs during the first nine months of 2021 were as follows:

Utility	Program	Nine Months Ended September 30, 2021
		(in millions)
Nicor Gas	Investing in Illinois	$	307
Virginia Natural Gas	Steps to Advance Virginia's Energy	36
Total		$	343

Atlanta Gas Light

On April 28, 2021, Atlanta Gas Light filed its first Integrated Capacity and Delivery Plan (i-CDP) with the Georgia PSC, which includes a series of ongoing and proposed pipeline safety, reliability, and growth programs for the next 10 years (2022 through 2031), as well as the required capital investments and related costs to implement the programs. The i-CDP reflects capital investments totaling approximately $0.5 billion to $0.6 billion annually.

Recovery of the related revenue requirements will be included in either subsequent annual GRAM filings or the new System Reinforcement Rider for authorized large pressure improvement and system reliability projects. On October 14, 2021, Atlanta Gas Light and the staff of the Georgia PSC filed a joint stipulation agreement, under which, for the years 2022 through 2024, Atlanta Gas Light would incrementally reduce its combined GRAM and System Reinforcement Rider request by 10% through Atlanta Gas Light's GRAM mechanism, or $5 million for 2022 based on the initial July 21, 2021 GRAM filing. The stipulation agreement also would provide for $1.7 billion of total capital investment for the years 2022 through 2024. The Georgia PSC is scheduled to vote on this matter later in November 2021. The ultimate outcome of this matter cannot be determined at this time. See "Rate Proceedings – Atlanta Gas Light" herein for additional information.

Virginia Natural Gas

On April 6, 2021, the Virginia Commission approved a motion filed by Virginia Natural Gas to withdraw the application for its 9.5-mile interconnect project due to a change in the capacity needs of one of the project's customers. No further action is necessary and this matter is now concluded.

Rate Proceedings

Virginia Natural Gas

On September 14, 2021, the Virginia Commission approved a stipulation agreement related to Virginia Natural Gas' June 2020 general rate case filing, which allows for a $43 million increase in annual base rate revenues, including $14 million related to the recovery of investments under the SAVE program, based on a ROE of 9.5% and an equity ratio of 51.9%. Interim rate adjustments became effective as of November 1, 2020, subject to refund, based on Virginia Natural Gas' original request for an increase of approximately $50 million. Refunds to customers related to the difference between the approved rates and the interim rates will be completed during the fourth quarter 2021.

Atlanta Gas Light

On July 21, 2021, Atlanta Gas Light filed its annual GRAM filing with the Georgia PSC. The filing requested an annual base rate increase of $49 million based on the projected 12-month period beginning January 1, 2022. Later in November 2021, Atlanta Gas Light expects to file an amended GRAM filing in accordance with the reduction agreed to in the October 14, 2021 joint stipulation agreement, as discussed previously under "Infrastructure Replacement Programs and Capital Projects – Atlanta Gas Light" herein. Resolution of the GRAM filing is expected by December 31, 2021, with the new rates to become effective January 1, 2022. The ultimate outcome of this matter cannot be determined at this time.

Deferral of Incremental COVID-19 Costs

Nicor Gas

On March 18, 2021, the Illinois Commission approved a phased-in schedule for disconnections related to non-payment. Nicor Gas began certain disconnections in late April 2021 and resumed normal disconnections in June 2021.

Virginia Natural Gas

On June 30, 2021, the declared state of emergency in Virginia expired, ending the suspension of disconnections related to non-payment. Virginia Natural Gas began certain disconnections in July 2021 and late payment fees resumed in October 2021.

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Contingencies

9 Months Ended

Sep. 30, 2021

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

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

Southern Company

In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits 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.

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. In August 2019, the court granted a motion filed by the plaintiff in July 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust.

The plaintiffs in each of these cases seek to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiffs also seek certain changes to Southern Company's corporate governance and internal processes. In 2018, the court in each case entered an order staying each lawsuit until 30 days after the settlement of a securities class action filed in January 2017 against Southern Company, certain of its current and former officers, and certain former Mississippi Power officers. In September 2020, the plaintiffs in each case filed a status report noting the settlement of the securities class action and informing the court that the parties had scheduled mediation, which occurred in November 2020. In September 2021, the parties executed a term sheet memorializing a settlement-in-principle of both pending derivative lawsuits. The parties are negotiating a global stipulation of settlement that will apply to both lawsuits and will be subject to approval by the federal court. If approved, the terms of the settlement-in-principle are not expected to have a material impact on Southern Company's financial statements.

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. In March 2020, the Georgia Court of Appeals vacated the Superior Court of Fulton County's February 2019 order granting conditional class certification and 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 and the plaintiffs renewed their motion for class certification. On March 16, 2021, the Superior Court of Fulton County granted class certification and Georgia Power's motion for summary judgment. On March 22, 2021, the plaintiffs filed a notice of appeal, and, on April 2, 2021, Georgia Power filed a notice of cross appeal on the issue of class certification. The amount of any possible losses cannot be estimated at this time because, among other factors, it is unknown whether any losses would be subject to recovery from any municipalities.

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

damages including punitive damages, a medical monitoring fund, and injunctive relief. In September 2020, Georgia Power filed a motion to dismiss. On October 8, 2021, three additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages. The amount of any possible losses from these matters cannot be estimated at this time.

Mississippi Power

In 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi. 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 each filed a motion to dismiss the amended complaint, which occurred in May 2020 and March 2020, respectively. Also in March 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. In July 2020, the plaintiffs filed a motion for leave to file a third amended complaint, which included the same federal claims as the proposed second amended complaint, as well as several additional state law claims based on the allegation that Mississippi Power failed to disclose the annual percentage rate of interest applicable to refunds. In November 2020, the court denied each of the plaintiffs' pending motions and entered final judgment in favor of Mississippi Power. On January 22, 2021, the court denied further motions by the plaintiffs to vacate the judgment and to file a revised second amended complaint. On February 19, 2021, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fifth Circuit. An adverse outcome in this proceeding could have a material impact on Mississippi Power's financial statements.

See Note 3 to the financial statements under "Other Matters – 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 remediation costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.

Georgia Power's environmental remediation liability was $19 million and $15 million at September 30, 2021 and December 31, 2020, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.

Southern Company Gas' environmental remediation liability was $255 million and $245 million at September 30, 2021 and December 31, 2020, respectively, based on the estimated cost of environmental investigation and remediation associated with known former manufactured gas plant operating sites.

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

Other Matters

Southern Company Gas

PennEast Pipeline Project

On June 29, 2021, the U.S. Supreme Court ruled in favor of PennEast Pipeline regarding its federal eminent domain authority over lands in which a state has property rights interests.

Southern Company Gas tests its equity method investments for impairment whenever events or changes in circumstances indicate that the investment may be impaired. Following the U.S. Supreme Court ruling, during the second quarter 2021, Southern Company Gas management reassessed the project construction timing, including the anticipated timing for receipt of the FERC certificate and all remaining state and local permits for both Phase 1 (the construction of 68 miles of pipe entirely within Pennsylvania) and Phase 2 (the construction of the remaining 50 miles in Pennsylvania and New Jersey), as well as potential challenges thereto, and performed an impairment analysis. The outcome of the analysis resulted in a pre-tax impairment charge of $82 million ($58 million after tax).

On September 27, 2021, PennEast Pipeline announced that further development of the project is no longer supported, and, as a result, all further development of the project has ceased. During the third quarter 2021, Southern Company Gas recorded a pre-tax charge of $2 million ($2 million after tax) related to its share of the project level impairment, as well as $7 million of additional tax expense, resulting in total pre-tax charges of $84 million ($67 million after tax) during 2021 related to the project.

See Note (E) under "Southern Company Gas" for additional information.

SNG

As a 50% equity investor in SNG, Southern Company Gas is required to make additional capital contributions as necessary pursuant to the terms of its operating agreement with SNG. Southern Company Gas previously committed to fund up to $150 million as a contingent capital contribution if SNG was unable to refinance or otherwise satisfy $300 million of debt maturing in June 2021. On April 29, 2021, SNG successfully refinanced the debt obligation. See Note (E) under "Southern Company Gas" for additional information.

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Revenue from Contracts with Customers and Lease Income

9 Months Ended

Sep. 30, 2021

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, 2021 and 2020:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2021
Operating revenues
Retail electric revenues
Residential	$	1,974	$	750	$	1,138	$	86	$	—	$	—
Commercial	1,432		471		882		79		—		—
Industrial	902		394		428		80		—		—
Other	24		4		18		2		—		—
Total retail electric revenues	4,332		1,619		2,466		247		—		—
Natural gas distribution revenues
Residential	218		—		—		—		—		218
Commercial	55		—		—		—		—		55
Transportation	239		—		—		—		—		239
Industrial	6		—		—		—		—		6
Other	31		—		—		—		—		31
Total natural gas distribution revenues	549		—		—		—		—		549
Wholesale electric revenues
PPA energy revenues	359		61		41		2		261		—
PPA capacity revenues	125		14		14		1		97		—
Non-PPA revenues	63		54		3		120		134		—
Total wholesale electric revenues	547		129		58		123		492		—
Other natural gas revenues
Gas marketing services	45		—		—		—		—		45
Other natural gas revenues	11		—		—		—		—		11
Total natural gas revenues	56		—		—		—		—		56
Other revenues	248		53		112		8		9		—
Total revenue from contracts with customers	5,732		1,801		2,636		378		501		605
Other revenue sources(a)	506		103		220		—		178		18
Total operating revenues	$	6,238	$	1,904	$	2,856	$	378	$	679	$	623

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Nine Months Ended September 30, 2021
Operating revenues
Retail electric revenues
Residential	$	4,910	$	1,931	$	2,765	$	214	$	—	$	—
Commercial	3,727		1,229		2,293		205		—		—
Industrial	2,299		1,048		1,034		217		—		—
Other	70		13		51		6		—		—
Total retail electric revenues	11,006		4,221		6,143		642		—		—
Natural gas distribution revenues
Residential	1,143		—		—		—		—		1,143
Commercial	298		—		—		—		—		298
Transportation	775		—		—		—		—		775
Industrial	29		—		—		—		—		29
Other	187		—		—		—		—		187
Total natural gas distribution revenues	2,432		—		—		—		—		2,432
Wholesale electric revenues
PPA energy revenues	782		143		71		9		575		—
PPA capacity revenues	375		86		41		4		247		—
Non-PPA revenues	181		108		14		283		273		—
Total wholesale electric revenues	1,338		337		126		296		1,095		—
Other natural gas revenues
Wholesale gas services	2,168		—		—		—		—		2,168
Gas marketing services	303		—		—		—		—		303
Other natural gas revenues	27		—		—		—		—		27
Total natural gas revenues	2,498		—		—		—		—		2,498
Other revenues	792		150		362		22		18		—
Total revenue from contracts with customers	18,066		4,708		6,631		960		1,113		4,930
Other revenue sources(a)	2,979		311		419		28		497		1,763
Other adjustments(b)	(3,699)		—		—		—		—		(3,699)
Total operating revenues	$	17,346	$	5,019	$	7,050	$	988	$	1,610	$	2,994

	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

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

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

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, 2021 and December 31, 2020:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Accounts Receivable
At September 30, 2021	$	2,343	$	712	$	904	$	90	$	170	$	329
At December 31, 2020	2,614		632		806		77		112		788
Contract Assets
At September 30, 2021	$	165	$	5	$	103	$	—	$	1	$	—
At December 31, 2020	158		2		71		—		—		—
Contract Liabilities
At September 30, 2021	$	65	$	6	$	39	$	1	$	2	$	—
At December 31, 2020	61		6		27		1		1		1

At September 30, 2021 and December 31, 2020, 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 unregulated service agreements. Southern Company's unregulated distributed generation business had $55 million and $81 million of contract assets and $19 million and $27 million of contract liabilities at September 30, 2021 and December 31, 2020, respectively, for outstanding performance obligations.

Revenues recognized by Southern Company in the three and nine months ended September 30, 2021, which were included in contract liabilities at December 31, 2020, were $5 million and $25 million, respectively, and immaterial for all other 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. Revenues from contracts with customers related to these performance obligations remaining at September 30, 2021 are expected to be recognized as follows:

	2021 (remaining)		2022		2023		2024		2025		Thereafter
	(in millions)
Southern Company	$	156	$	543	$	347	$	327	$	307	$	2,667
Alabama Power	13		32		24		7		5		—
Georgia Power	22		64		43		23		21		41
Southern Power	70		323		281		297		281		2,644

Revenue expected to be recognized for performance obligations remaining at September 30, 2021 was immaterial for Mississippi Power

Lease Income

Lease income for the three and nine months ended September 30, 2021 and 2020 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, 2021
Lease income - interest income on sales-type leases	$	4	$	—	$	—	$	4	$	—	$	—
Lease income - operating leases	56		21		11		—		21		9
Variable lease income	143		—		—		—		151		—
Total lease income	$	203	$	21	$	11	$	4	$	172	$	9
For the Nine Months Ended September 30, 2021
Lease income - interest income on sales-type leases	$	11	$	—	$	—	$	10	$	—	$	—
Lease income - operating leases	168		62		31		1		64		26
Variable lease income	355		—		—		—		379		—
Total lease income	$	534	$	62	$	31	$	11	$	443	$	26
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

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

Lease Receivables

Mississippi Power

Mississippi Power completed construction of additional leased assets under an existing sales-type lease during the second quarter 2021. Upon completion of construction, the book value was transferred from CWIP to lease receivables. At September 30, 2021, the lease receivable related to the additional leased assets totaled $39 million and is primarily included in other property and investments. The transfer represents a noncash investing transaction for purposes of the statements of cash flows.

Southern Power

During the third quarter 2021, Southern Power completed construction of a portion of the Garland battery energy storage facility assets and recorded a $15 million loss upon commencement of the related PPA, which Southern

Power accounts for as a sales-type lease. The lease has an initial term of 20 years. Upon commencement of the lease, the $113 million book value of the assets was derecognized from CWIP and a lease receivable was recorded. At September 30, 2021, the current portion of the lease receivable of $8 million is included in other current assets and the long-term portion of $91 million is included in net investment in sales-type lease on the balance sheet. The transfer represented a noncash investing transaction for purposes of the statement of cash flows. The undiscounted cash flows expected to be received by Southern Power for assets under the lease are as follows:

	At September 30, 2021
	(in millions)
2021 (remaining)	$	2
2022	8
2023	8
2024	8
2025	8
2026	8
Thereafter	115
Total undiscounted cash flows	$	157
Net investment in sales-type lease(*)	99
Difference between undiscounted cash flows and discounted cash flows	$	58

(*)Included in other current assets and other property and investments on the balance sheet.

See Note (K) under "Southern Power" for additional information on the Garland battery energy storage facility.

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Consolidated Entities and Equity Method Investments

9 Months Ended

Sep. 30, 2021

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, 2021 and December 31, 2020, SP Solar had total assets of $6.2 billion and $6.1 billion, respectively, total liabilities of $364 million and $387 million, respectively, and noncontrolling interests of $1.1 billion. Cash distributions from SP Solar are allocated 67% to Southern Power and 33% to Global Atlantic in accordance with their partnership interest percentage. Under the terms of the limited partnership agreement, distributions without limited partner consent are limited to available cash and SP Solar is obligated to distribute all such available cash to its partners each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves.

At September 30, 2021 and December 31, 2020, SP Wind had total assets of $2.3 billion and $2.4 billion, respectively, total liabilities of $157 million and $138 million, respectively, and noncontrolling interests of $42 million and $43 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, 2021 and December 31, 2020, the other VIEs had total assets of $1.9 billion and $1.1 billion, respectively, total liabilities of $263 million and $110 million, respectively, and noncontrolling interests of $902 million and $454 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, 2021 and December 31, 2020, Southern Power had equity method investments in wind and battery energy storage projects totaling $83 million and $19 million, respectively. Earnings (loss) from these investments were immaterial for all periods presented.

Southern Company Gas

Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments at September 30, 2021 and December 31, 2020 and related earnings (loss) from those investments for the three and nine months ended September 30, 2021 and 2020 were as follows:

Investment Balance	September 30, 2021		December 31, 2020
	(in millions)
SNG	$	1,130	$	1,167
PennEast Pipeline(*)	11		91
Other	33		32
Total	$	1,174	$	1,290

(*)Investment balance at September 30, 2021 reflects pre-tax impairment charges totaling $84 million recorded during 2021. See Note (C) under "Other Matters – Southern Company Gas" for additional information, including the September 2021 cancellation of the project.

	Three Months Ended September 30,				Nine Months Ended September 30,
Earnings (Loss) from Equity Method Investments	2021		2020		2021		2020
	(in millions)
SNG	$	27	$	30	$	93	$	95
PennEast Pipeline(a)(b)	(2)		2		(81)		5
Other(a)(c)	—		1		2		6
Total	$	25	$	33	$	14	$	106

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

(b)Includes pre-tax impairment charges totaling $2 million and $84 million for the three and nine months ended September 30, 2021, respectively. See Note (C) under "Other Matters – Southern Company Gas" for additional information, including the September 2021 cancellation of the project.

(c)On March 24, 2020, Southern Company Gas completed the sale of its interests in Atlantic Coast Pipeline and Pivotal LNG. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.

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Financing

9 Months Ended

Sep. 30, 2021

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, 2021, committed credit arrangements with banks were as follows:

	Expires
Company	2022		2023		2024		2026		Total		Unused		Due within One Year
	(in millions)
Southern Company parent	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—
Alabama Power	—		—		550		700		1,250		1,250		—
Georgia Power	—		—		—		1,750		1,750		1,726		—
Mississippi Power	—		125		150		—		275		250		—
Southern Power(a)	—		—		—		600		600		568		—
Southern Company Gas(b)	250		—		—		1,500		1,750		1,747		250
SEGCO	30		—		—		—		30		30		30
Southern Company	$	280	$	125	$	700	$	6,550	$	7,655	$	7,570	$	280

(a)Does not include Southern Power Company's $75 million and $60 million continuing letter of credit facilities for standby letters of credit expiring in 2023, of which $23 million and $1 million, respectively, was unused at September 30, 2021. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.

(b)Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $800 million of the arrangement expiring in 2026 and all $250 million of the arrangement expiring in 2022. Southern Company Gas' committed credit arrangement expiring in 2026 also includes $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to the multi-year credit arrangement expiring in 2026, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.

As reflected in the table above, in May 2021, Southern Company, Alabama Power, Georgia Power, and Southern Power each amended and restated certain of its multi-year credit arrangements, which, among other things, extended the maturity dates from 2024 to 2026. Alabama Power also decreased the borrowing capacity under its credit arrangement now maturing in 2026 from $800 million to $700 million. Also in May 2021, Southern Company Gas Capital, along with Nicor Gas, amended and restated their multi-year credit arrangement to extend the maturity date from 2024 to 2026 and decrease the aggregate borrowing capacity from $1.75 billion to $1.5 billion. In addition,

Southern Company Gas Capital entered into a new $250 million credit arrangement, which is guaranteed by Southern Company Gas, that matures in 2022. In June 2021, Mississippi Power amended and restated certain of its multi-year credit arrangements aggregating $150 million, which, among other things, extended the maturity dates from 2022 to 2024. In August 2021, Alabama Power amended and restated one of its multi-year credit arrangements, which, among other things, extended the maturity date from 2022 to 2024 and increased the borrowing capacity from $525 million to $550 million.

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, Nicor Gas, 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, 2021, 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, 2021 was approximately $1.6 billion (comprised of approximately $854 million at Alabama Power, $672 million at Georgia Power, and $34 million at Mississippi Power). In addition, at September 30, 2021, Georgia Power and Mississippi Power had approximately $262 million and $50 million, respectively, 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 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 equity units and Note 12 to the financial statements in Item 8 of the Form 10-K for information on stock-based compensation plans. Shares used to compute diluted earnings per share were as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020
	(in millions)
As reported shares	1,061	1,058	1,060	1,058
Effect of stock-based compensation	7	6	7	6
Diluted shares	1,068	1,064	1,067	1,064

For all periods presented, an immaterial number of stock-based compensation awards was not included in the diluted earnings per share calculation because the awards were anti-dilutive.

An immaterial number of shares related to the equity units issued in 2019 was included in the calculations 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, 2021

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 $1.2 billion at September 30, 2021 compared to $1.4 billion at December 31, 2020.

The federal ITC and PTC carryforwards begin expiring in 2036 and 2032, respectively, but are expected to be fully utilized by 2024. The utilization of each Registrant's estimated tax credit and state net operating loss carryforwards and related valuation allowances could be impacted by numerous factors, including the acquisition of additional renewable projects, the purchase of rights to additional PTCs of Plant Vogtle Units 3 and 4 pursuant to certain joint ownership agreements, changes in taxable income projections, and potential income tax rate changes. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.

Valuation Allowances

Details of significant changes in valuation allowances for the applicable Registrants are provided below:

	Southern Company		Georgia Power
	(in millions)
Federal	$	20	$	—
State (net of federal benefit)	92		28
Balance at December 31, 2020	$	112	$	28
Federal	$	20	$	—
State (net of federal benefit)	122		58
Balance at September 30, 2021	$	142	$	58

The increase in valuation allowances, net of federal benefit, for Southern Company and Georgia Power during 2021 was primarily due to Georgia Power's projected inability to utilize certain state tax credit carryforwards.

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 17.5% for the nine months ended September 30, 2021 compared to 13.9% for the corresponding period in 2020. The effective tax rate increase was primarily related to changes in state apportionment rates as a result of the sale of Sequent, an increase in the valuation allowance on certain state tax credit carryforwards, and the tax impact of the second quarter 2020 charge to earnings associated with a leveraged lease investment. See "Valuation Allowances" herein, Note (K) under "Southern Company Gas," and Note 3 to the financial statements in Item 8 of the Form 10-K under "Other Matters – Southern Company" for additional information.

Georgia Power

Georgia Power's effective tax rate was 7.3% for the nine months ended September 30, 2021 compared to 12.3% for the corresponding period in 2020. The effective tax rate decrease was primarily due to higher charges to earnings in 2021 associated with the construction of Plant Vogtle Units 3 and 4, partially offset by an increase in the valuation allowance on certain state tax credit carryforwards. See "Valuation Allowances" herein and Note (B) under "Georgia Power – Nuclear Construction" for additional information.

Southern Power

Southern Power's effective tax benefit rate was (1.6)% for the nine months ended September 30, 2021 compared to an effective tax rate of 11.3% for the corresponding period in 2020. The effective tax rate decrease was primarily due to changes in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in February 2021, as well as the tax impact from the sale of Plant Mankato in January 2020. See Note 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K for additional information.

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Retirement Benefits

9 Months Ended

Sep. 30, 2021

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, 2021. 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.

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, 2021 and 2020 are presented in the following tables.

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2021
Pension Plans
Service cost	$	109	$	26	$	28	$	4	$	2	$	10
Interest cost	87		20		26		4		2		6
Expected return on plan assets	(298)		(72)		(94)		(14)		(4)		(21)
Amortization:
Prior service costs	—		—		—		—		—		(1)
Regulatory asset	—		—		—		—		—		3
Net (gain)/loss	78		21		25		4		1		3
Net periodic pension cost (income)	$	(24)	$	(5)	$	(15)	$	(2)	$	1	$	—
Postretirement Benefits
Service cost	$	6	$	2	$	2	$	1	$	1	$	—
Interest cost	9		2		3		—		—		1
Expected return on plan assets	(19)		(8)		(7)		(1)		—		(2)
Amortization:
Regulatory asset	—		—		—		—		—		2
Net (gain)/loss	1		—		1		—		—		(1)
Net periodic postretirement benefit cost (income)	$	(3)	$	(4)	$	(1)	$	—	$	1	$	—
Nine Months Ended September 30, 2021
Pension Plans
Service cost	$	326	$	77	$	84	$	13	$	7	$	28
Interest cost	260		61		78		12		4		18
Expected return on plan assets	(893)		(215)		(282)		(41)		(11)		(64)
Amortization:
Prior service costs	—		—		1		—		—		(2)
Regulatory asset	—		—		—		—		—		11
Net (gain)/loss	235		62		75		11		3		9
Net periodic pension cost (income)	$	(72)	$	(15)	$	(44)	$	(5)	$	3	$	—
Postretirement Benefits
Service cost	$	18	$	5	$	5	$	1	$	1	$	1
Interest cost	26		6		9		1		—		3
Expected return on plan assets	(57)		(22)		(20)		(2)		—		(6)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		5
Net (gain)/loss	3		—		2		—		—		(2)
Net periodic postretirement benefit cost (income)	$	(11)	$	(11)	$	(4)	$	—	$	1	$	1

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2020
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 (income)	$	2	$	(2)	$	—	$	—	$	1	$	1
Nine Months Ended September 30, 2020
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 (income)	$	4	$	(7)	$	1	$	1	$	1	$	4

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Fair Value Measurements

9 Months Ended

Sep. 30, 2021

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

At September 30, 2021, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

	Fair Value Measurements Using:
At September 30, 2021	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)	$	75	$	425	$	—	$	—	$	500
Interest rate derivatives	—		25		—		—		25
Foreign currency derivatives	—		20		—		—		20
Investments in trusts:(b)(c)
Domestic equity	738		237		—		—		975
Foreign equity	167		183		—		—		350
U.S. Treasury and government agency securities	—		352		—		—		352
Municipal bonds	—		48		—		—		48
Pooled funds – fixed income	—		14		—		—		14
Corporate bonds	2		472		—		—		474
Mortgage and asset backed securities	—		92		—		—		92
Private equity	—		—		—		123		123
Cash and cash equivalents	5		—		—		—		5
Other	29		13		—		—		42
Cash equivalents	1,498		9		—		—		1,507
Other investments	9		26		—		—		35
Total	$	2,523	$	1,916	$	—	$	123	$	4,562
Liabilities:
Energy-related derivatives(a)	$	27	$	17	$	—	$	—	$	44
Interest rate derivatives	—		16		—		—		16
Foreign currency derivatives	—		43		—		—		43
Contingent consideration	—		—		16		—		16
Other	—		13		—		—		13
Total	$	27	$	89	$	16	$	—	$	132

	Fair Value Measurements Using:
At September 30, 2021	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	$	—	$	104	$	—	$	—	$	104
Interest rate derivatives	—		5		—		—		5
Nuclear decommissioning trusts:(b)
Domestic equity	444		227		—		—		671
Foreign equity	167		—		—		—		167
U.S. Treasury and government agency securities	—		22		—		—		22
Municipal bonds	—		1		—		—		1
Corporate bonds	2		243		—		—		245
Mortgage and asset backed securities	—		22		—		—		22
Private equity	—		—		—		123		123
Other	6		—		—		—		6
Cash equivalents	443		9		—		—		452
Other investments	—		26		—		—		26
Total	$	1,062	$	659	$	—	$	123	$	1,844
Liabilities:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4
Georgia Power
Assets:
Energy-related derivatives	$	—	$	166	$	—	$	—	$	166
Nuclear decommissioning trusts:(b)(c)
Domestic equity	294		1		—		—		295
Foreign equity	—		180		—		—		180
U.S. Treasury and government agency securities	—		330		—		—		330
Municipal bonds	—		47		—		—		47
Corporate bonds	—		229		—		—		229
Mortgage and asset backed securities	—		70		—		—		70
Other	23		13		—		—		36
Cash equivalents	240		—		—		—		240
Total	$	557	$	1,036	$	—	$	—	$	1,593
Liabilities:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4

	Fair Value Measurements Using:
At September 30, 2021	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	$	—	$	105	$	—	$	—	$	105
Cash equivalents	121		—		—		—		121
Total	$	121	$	105	$	—	$	—	$	226
Liabilities:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Southern Power
Assets:
Energy-related derivatives	$	—	$	10	$	—	$	—	$	10
Foreign currency derivatives	—		20		—		—		20
Total	$	—	$	30	$	—	$	—	$	30
Liabilities:
Energy-related derivatives	$	—	$	2	$	—	$	—	$	2
Foreign currency derivatives	—		11		—		—		11
Contingent consideration	—		—		16		—		16
Other	—		13		—		—		13
Total	$	—	$	26	$	16	$	—	$	42
Southern Company Gas
Assets:
Energy-related derivatives(a)	$	75	$	40	$	—	$	—	$	115
Interest rate derivatives	—		6		—		—		6
Non-qualified deferred compensation trusts:
Domestic equity	—		9		—		—		9
Foreign equity	—		3		—		—		3
Pooled funds – fixed income	—		14		—		—		14
Cash equivalents	5		—		—		—		5
Total	$	80	$	72	$	—	$	—	$	152
Liabilities:
Energy-related derivatives(a)	$	27	$	4	$	—	$	—	$	31
Interest rate derivatives	—		4		—		—		4
Total	$	27	$	8	$	—	$	—	$	35

(a)Excludes cash collateral of $(20) million.

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

(c)Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. At September 30, 2021, approximately $57 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.

See Note (K) under "Assets Held for Sale" for information regarding assets recorded at fair value on a nonrecurring basis.

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 nine months ended September 30, 2021 and 2020. 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, 2021		Three Months Ended September 30, 2020		Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020
	(in millions)
Southern Company	$	9	$	108	$	173	$	85
Alabama Power	15		66		133		24
Georgia Power	(6)		42		40		61

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 it is primarily obligated to make generation-based payments to the seller, which commenced at the commercial operation of the respective facility and continue through 2026. The obligations are categorized as Level 3 under Fair Value Measurements as

the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.

Southern Power also has payment obligations through 2040 whereby it must reimburse the transmission owners for interconnection facilities and network upgrades constructed to support connection of a Southern Power generating facility to the transmission system. The obligations are categorized as Level 2 under Fair Value Measurements as the fair value is determined using observable inputs for the contracted amounts and reimbursement period, as well as a discount rate. The fair value of the obligations reflects the net present value of expected payments.

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

At September 30, 2021, 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 $123 million and unfunded commitments related to the private equity investments totaled $72 million. Private equity investments include high-quality private equity funds across several market sectors and funds that invest in real estate assets. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.

At September 30, 2021, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas(*)
	(in billions)
Long-term debt, including securities due within one year:
Carrying amount	$	51.9	$	9.1	$	13.6	$	1.6	$	4.0	$	6.8
Fair value	57.6		10.4		15.2		1.7		4.4		7.8

(*)The long-term debt of Southern Company Gas is recorded at amortized cost, including the fair value adjustments at the effective date of the 2016 merger with Southern Company. Southern Company Gas amortizes the fair value adjustments over the remaining lives of the respective bonds, the latest being through 2043.

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

Commodity Contracts with Level 3 Valuation Inputs

Prior to July 1, 2021, Southern Company Gas had Level 3 physical natural gas forward contracts related to Sequent. See Note (K) under "Southern Company Gas" for information regarding the sale of Sequent. 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 provides a reconciliation of Southern Company Gas' Level 3 contracts during the three and nine months ended September 30, 2021.

	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	(in millions)
Beginning balance	$	18	$	28
Instruments realized or otherwise settled during period	—		(6)
Changes in fair value	—		(4)
Sale of Sequent	(18)		(18)
Ending balance	$	—	$	—

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 prior to the sale of Sequent.

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Derivatives

9 Months Ended

Sep. 30, 2021

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. Through the sale of Sequent on July 1, 2021, Southern Company Gas' wholesale gas operations used various contracts in its commercial activities that generally met the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with the classification of the hedged interest or principal, respectively. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information. See Note (K) under "Southern Company Gas" for information regarding Southern Company Gas' sale of Sequent.

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 an approved cost recovery mechanism.

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

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

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

At September 30, 2021, 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(*)	336	2030	2024
Alabama Power	75	2024	—
Georgia Power	99	2024	—
Mississippi Power	79	2025	—
Southern Power	6	2030	2022
Southern Company Gas(*)	77	2024	2024

(*)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 91.4 million mmBtu and short natural gas positions of 14.3 million mmBtu at September 30, 2021, which is also included in Southern Company's total volume. See Note (K) under "Southern Company Gas" for information regarding Southern Company Gas' sale of Sequent.

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 41 million mmBtu for Southern Company, which includes 10 million mmBtu for Alabama Power, 13 million mmBtu for Georgia Power, 5 million mmBtu for Mississippi Power, and 13 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, 2022 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. 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, 2021, 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, 2021
	(in millions)					(in millions)
Cash Flow Hedges of Forecasted Debt
Alabama Power	$	150	—	1.91%	August 2051	$	5
Fair Value Hedges of Existing Debt
Southern Company parent	400		1.75%	1-month LIBOR + 0.68%	March 2028	(2)
Southern Company parent	1,000		3.70%	1-month LIBOR + 2.36%	April 2030	3
Southern Company Gas	500		1.75%	1-month LIBOR + 0.38%	January 2031	2
Southern Company	$	2,050				$	8

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, 2022 total $(22) 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 2051 for the Southern Company parent entity, 2051 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. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Southern Company has elected to exclude the cross-currency basis spread from the assessment of effectiveness in the fair value hedges of its foreign currency risk and record any difference between the change in the fair value of the excluded components and the amounts recognized in earnings as a component of OCI.

At September 30, 2021, 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, 2021
	(in millions)			(in millions)				(in millions)
Fair Value Hedges of Existing Debt
Southern Company parent	$	1,476	3.39%	€	1,250	1.88%	September 2027	$	(32)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	9
Southern Power	564		3.78%	500		1.85%	June 2026	—
Southern Power total	$	1,241		€	1,100			$	9
Southern Company	$	2,717		€	2,350			$	(23)

The estimated pre-tax gain (loss) related to Southern Power's foreign currency derivatives accounted for as cash flow hedges expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2022 is $(4) 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:

	At September 30, 2021				At December 31, 2020
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:
Assets from risk management activities/Other current liabilities	$	308	$	9	$	24	$	11
Other deferred charges and assets/Other deferred credits and liabilities	118		6		18		19
Total derivatives designated as hedging instruments for regulatory purposes	$	426	$	15	$	42	$	30
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Other current liabilities	$	41	$	—	$	3	$	5
Other deferred charges and assets/Other deferred credits and liabilities	4		—		—		—
Interest rate derivatives:
Assets from risk management activities/Other current liabilities	25		—		20		—
Other deferred charges and assets/Other deferred credits and liabilities	—		16		—		—
Foreign currency derivatives:
Assets from risk management activities/Other current liabilities	9		33		—		23
Other deferred charges and assets/Other deferred credits and liabilities	11		10		87		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	90	$	59	$	110	$	28
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Other current liabilities	$	29	$	29	$	388	$	331
Other deferred charges and assets/Other deferred credits and liabilities	1		—		270		232
Total derivatives not designated as hedging instruments	$	30	$	29	$	658	$	563
Gross amounts recognized	$	546	$	103	$	810	$	621
Gross amounts offset(a)	(57)		(37)		(529)		(557)
Net amounts recognized in the Balance Sheets(b)	$	489	$	66	$	281	$	64

	At September 30, 2021				At December 31, 2020
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	$	67	$	2	$	7	$	2
Other deferred charges and assets/Other deferred credits and liabilities	37		2		5		5
Total derivatives designated as hedging instruments for regulatory purposes	$	104	$	4	$	12	$	7
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	5	$	—	$	—	$	—
Gross amounts recognized	$	109	$	4	$	12	$	7
Gross amounts offset	(3)		(3)		(7)		(7)
Net amounts recognized in the Balance Sheets	$	106	$	1	$	5	$	—
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	124	$	2	$	7	$	5
Other deferred charges and assets/Other deferred credits and liabilities	42		2		8		8
Total derivatives designated as hedging instruments for regulatory purposes	$	166	$	4	$	15	$	13
Gross amounts recognized	$	166	$	4	$	15	$	13
Gross amounts offset	(3)		(3)		(12)		(12)
Net amounts recognized in the Balance Sheets	$	163	$	1	$	3	$	1
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	66	$	1	$	4	$	3
Other deferred charges and assets/Other deferred credits and liabilities	39		2		5		6
Total derivatives designated as hedging instruments for regulatory purposes	$	105	$	3	$	9	$	9
Gross amounts recognized	$	105	$	3	$	9	$	9
Gross amounts offset	(2)		(2)		(7)		(7)
Net amounts recognized in the Balance Sheets	$	103	$	1	$	2	$	2

	At September 30, 2021				At December 31, 2020
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Southern Power
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	8	$	—	$	2	$	2
Other deferred charges and assets/Other deferred credits and liabilities	1		—		—		—
Foreign currency derivatives:
Other current assets/Other current liabilities	9		11		—		23
Other deferred charges and assets/Other deferred credits and liabilities	11		—		87		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	29	$	11	$	89	$	25
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	1	$	2	$	—	$	1
Total derivatives not designated as hedging instruments	$	1	$	2	$	—	$	1
Gross amounts recognized	$	30	$	13	$	89	$	26
Gross amounts offset	(1)		(1)		—		—
Net amounts recognized in the Balance Sheets	$	29	$	12	$	89	$	26

	At September 30, 2021				At December 31, 2020
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/Other current liabilities	$	51	$	4	$	6	$	1
Total derivatives designated as hedging instruments for regulatory purposes	$	51	$	4	$	6	$	1
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Other current liabilities	$	33	$	—	$	1	$	3
Other deferred charges and assets/Other deferred credits and liabilities	3		—		—		—
Interest rate derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	6		—		—		—
Other deferred charges and assets/Other deferred credits and liabilities	—		4		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	42	$	4	$	1	$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Other current liabilities	$	28	$	27	$	388	$	330
Other deferred charges and assets/Other deferred credits and liabilities	1		—		270		232
Total derivatives not designated as hedging instruments	$	29	$	27	$	658	$	562
Gross amounts recognized	$	122	$	35	$	665	$	566
Gross amounts offset(a)	(48)		(28)		(503)		(531)
Net amounts recognized in the Balance Sheets(b)	$	74	$	7	$	162	$	35

(a)Gross amounts offset include cash collateral held on deposit in broker margin accounts of $(20) million and $28 million at September 30, 2021 and December 31, 2020, respectively.

(b)Net amounts of derivative instruments outstanding exclude immaterial premium and intrinsic value associated with weather derivatives for both periods presented.

The traditional electric operating companies had no energy-related derivatives not designated as hedging instruments at September 30, 2021 or December 31, 2020.

At September 30, 2021 and December 31, 2020, 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, 2021:
Energy-related derivatives:
Other regulatory assets, current	$	(5)	$	(1)	$	(1)	$	—	$	(3)
Other regulatory liabilities, current	297		66		123		66		42
Other regulatory liabilities, deferred	112		35		40		37		—
Total energy-related derivative gains (losses)	$	404	$	100	$	162	$	103	$	39
At December 31, 2020:
Energy-related derivatives:
Other regulatory assets, deferred	$	(2)	$	—	$	(1)	$	(1)	$	—
Other regulatory liabilities, current	12		5		2		1		4
Other regulatory liabilities, deferred	2		1		1		—		—
Total energy-related derivative gains (losses)	$	12	$	6	$	2	$	—	$	4

For the three and nine months ended September 30, 2021 and 2020, the pre-tax effects of cash flow and fair value hedge accounting on accumulated OCI were as follows:

Gain (Loss) Recognized in OCI on Derivative	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Southern Company
Cash flow hedges:
Energy-related derivatives	$	38	$	9	$	59	$	2
Interest rate derivatives	5		1		7		(27)
Foreign currency derivatives	(36)		54		(79)		(10)
Fair value hedges(*):
Foreign currency derivatives	(4)		—		(4)		—
Total	$	3	$	64	$	(17)	$	(35)
Southern Power
Cash flow hedges:
Energy-related derivatives	$	8	$	5	$	16	$	2
Foreign currency derivatives	(36)		54		(79)		(10)
Total	$	(28)	$	59	$	(63)	$	(8)
Southern Company Gas
Cash flow hedges:
Energy-related derivatives	$	30	$	4	$	43	$	—
Interest rate derivatives	—		1		—		(24)
Total	$	30	$	5	$	43	$	(24)

(*)Represents amounts excluded from the assessment of effectiveness for which the difference between changes in fair value and periodic amortization is recorded in OCI.

For the three and nine months ended September 30, 2021 and 2020, the pre-tax effects of 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, 2021 and 2020, 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,
	2021		2020		2021		2020
	(in millions)				(in millions)
Southern Company
Total cost of natural gas	$	129	$	71	$	943	$	654
Gain (loss) on energy-related cash flow hedges(a)	2		—		—		(8)
Total depreciation and amortization	896		889		2,658		2,619
Gain (loss) on energy-related cash flow hedges(a)	3		(1)		6		(3)
Total interest expense, net of amounts capitalized	(451)		(443)		(1,352)		(1,343)
Gain (loss) on interest rate cash flow hedges(a)	(7)		(6)		(20)		(19)
Gain (loss) on foreign currency cash flow hedges(a)	(6)		(6)		(18)		(18)
Gain (loss) on interest rate fair value hedges(b)	(4)		(3)		(16)		27
Total other income (expense), net	131		113		297		319
Gain (loss) on foreign currency cash flow hedges(a)(c)	(34)		56		(76)		52
Gain (loss) on foreign currency fair value hedges	(32)		—		(32)		—
Amount excluded from effectiveness testing recognized in earnings	4		—		4		—
Southern Power
Total depreciation and amortization	$	132	$	129	$	383	$	367
Gain (loss) on energy-related cash flow hedges(a)	3		(1)		6		(3)
Total interest expense, net of amounts capitalized	(36)		(36)		(111)		(114)
Gain (loss) on foreign currency cash flow hedges(a)	(6)		(6)		(18)		(18)
Total other income (expense), net	2		13		10		19
Gain (loss) on foreign currency cash flow hedges(a)(c)	(34)		56		(76)		52

(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, 2021 and 2020, 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.

At September 30, 2021 and December 31, 2020, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:

	Carrying Amount of the Hedged Item				Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items	At September 30, 2021		At December 31, 2020		At September 30, 2021		At December 31, 2020
	(in millions)				(in millions)
Southern Company
Securities due within one year	$	—	$	(1,509)	$	—	$	(10)
Long-term debt	(3,320)		—		—		—
Southern Company Gas
Long-term debt	$	(497)	$	—	$	(1)	$	—

For the three and nine months ended September 30, 2021 and 2020, 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	2021		2020		2021		2020
		(in millions)				(in millions)
Energy-related derivatives:	Natural gas revenues(*)	$	(2)	$	(30)	$	(122)	$	54
	Cost of natural gas	20		5		36		18
Total derivatives in non-designated hedging relationships		$	18	$	(25)	$	(86)	$	72

(*)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, 2021 and 2020, 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, 2021, the Registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

At September 30, 2021, the Registrants had no interest rate derivative liabilities with contingent features. At September 30, 2021, 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, Inc., 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 and they may be required to post collateral based on the value of the positions in these accounts and the associated margin requirements. At September 30, 2021, 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, 2021, cash collateral held on deposit in broker margin accounts was $(20) million.

The Registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Registrants only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Registrants have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk.

Southern Company Gas uses established credit policies to determine and monitor the creditworthiness of counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or U.S. government securities held by a trustee. Prior to entering a physical transaction, Southern Company Gas assigns its counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.

Southern Company Gas utilizes netting agreements whenever possible to mitigate exposure to counterparty credit risk. Netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty across product lines and against cash collateral, provided the netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, counterparties are settled net, they are recorded on a gross basis on the balance sheet as energy marketing receivables and energy marketing payables.

The Registrants do not anticipate a material adverse effect on their respective financial statements as a result of counterparty nonperformance.

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Acquisitions and Dispositions

9 Months Ended

Sep. 30, 2021

Business Combination and Asset Acquisition [Abstract]

Acquisitions and Dispositions

ACQUISITIONS AND DISPOSITIONSSee Note 15 to the financial statements in Item 8 of the Form 10-K for additional information.

Southern Company

On October 29, 2021, Southern Company completed the sale of assets subject to a leveraged lease to the lessee for $45 million. No gain or loss was recognized on the sale. During the fourth quarter 2021, income tax benefits of approximately $16 million will be recognized as a result of the sale. At September 30, 2021, the leveraged lease investment was classified as held for sale. See Note 3 to the financial statements under "Other Matters – Southern Company" in Item 8 of the Form 10-K and "Assets Held for Sale" herein for additional information.

Alabama Power

On September 23, 2021, Alabama Power entered into an agreement to acquire all of the equity interests in Calhoun Power Company, LLC, which owns and operates the Calhoun Generating Station. See Note (B) under "Alabama Power – Calhoun Generating Station Acquisition" for additional information.

Southern Power

Asset Acquisition

During the nine months ended September 30, 2021, Southern Power acquired a controlling membership 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
Deuel Harvest(*)	Wind	Invenergy Renewables, LLC	300	Deuel County, SD	100% of Class B	February 2021	25 years and 15 years

(*)On March 26, 2021, Southern Power acquired a controlling interest in the project from Invenergy Renewables LLC and, on March 30, 2021, Southern Power completed a tax equity transaction whereby it sold the Class A membership interests in the project. Southern Power consolidates the project's operating results in its financial statements and the tax equity partner and Invenergy Renewables LLC each own a noncontrolling interest.

Construction Projects

During the nine months ended September 30, 2021, Southern Power completed construction of and placed in service 45 MWs of the Garland battery energy storage facility and continued construction of the Tranquillity battery energy storage facility, the Glass Sands wind facility, and the remainder of the Garland battery energy storage facility. Total aggregate construction costs, excluding acquisition costs, are expected to be between $400 million and $460 million for the facilities under construction. At September 30, 2021, total costs of construction incurred for these projects were $341 million, of which $228 million remains 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 Under Construction at September 30, 2021
Garland Solar Storage(a)	Battery energy storage system	88	Kern County, CA	September 2021 and fourth quarter 2021(b)	20 years
Tranquillity Solar Storage(a)	Battery energy storage system	72	Fresno County, CA	Fourth quarter 2021 and first quarter 2022	20 years
Glass Sands(c)	Wind	118	Murray County, OK	Fourth quarter 2021	12 years

(a)During the third quarter 2021, Southern Power further restructured its ownership in the Garland and Tranquillity battery energy storage projects and completed tax equity transactions whereby it sold the Class A membership interests in the projects. Southern Power consolidates each project's operating results in its financial statements and the tax equity partner and two other partners each own a noncontrolling interest.

(b)The facility has a total capacity of 88 MWs, of which 45 MWs were placed in service in September 2021 and 43 MWs are expected to be placed in service later in the fourth quarter 2021.

(c)In December 2020, Southern Power purchased 100% of the membership interests of the Glass Sands facility.

Development Projects

Southern Power continues to evaluate and refine the deployment of the remaining wind turbine equipment purchased in 2016 and 2017 for development and construction projects. During the nine months ended September 30, 2021, gains on wind turbine equipment contributed to various equity method investments totaled approximately $37 million.

Southern Company Gas

Sale of Sequent

On July 1, 2021, Southern Company Gas affiliates completed the sale of Sequent to Williams Field Services Group for a total cash purchase price of $159 million, including final working capital adjustments. The preliminary pre-tax gain associated with the transaction is approximately $121 million ($93 million after tax). As a result of the sale, changes in state apportionment rates resulted in $85 million of additional tax expense.

Prior to the sale, Southern Company Gas had existing agreements in place in which it guaranteed the payment performance of Sequent. Southern Company Gas will continue to guarantee Sequent's payment performance for a period of time as Williams Field Services Group obtains releases from these obligations. At September 30, 2021, the obligations subject to the payment performance guarantee totaled $36 million. Changes in the price of natural gas, market conditions, and the number of open contracts may change the amount that Southern Company Gas is required to guarantee for Sequent each month. The maximum potential exposure over the period of the payment performance guarantee generally is capped at $1 billion. At closing, Williams Field Services Group issued a payment performance guarantee to Southern Company Gas, equal to the outstanding guarantee obligation throughout this period.

Southern Company Gas' sale of Sequent did not represent a strategic shift in operations that has, or is expected to have, a major effect on its operations and financial results; therefore, none of the assets were classified as discontinued operations for any of the periods presented.

Sale of Pivotal LNG

In connection with its March 2020 sale of Pivotal LNG, Southern Company Gas was entitled to two $5 million payments contingent upon Dominion Modular LNG Holdings, Inc. meeting certain milestones related to Pivotal LNG. Southern Company Gas received the first payment on April 22, 2021 and expects to receive the second payment in February 2022.

Assets Held for Sale

The following table provides the major classes of assets classified as held for sale by Southern Company at September 30, 2021 and December 31, 2020:

	Southern Company
	At September 30,		At December 31,
	2021		2020
	(in millions)
Assets Held for Sale:
Total property, plant, and equipment	$	6	$	8
Leveraged leases	45		52
Total Assets Held for Sale	$	51	$	60

Southern Company's assets held for sale at September 30, 2021 and December 31, 2020 were recorded at fair value on a nonrecurring basis, based primarily on unobservable inputs (Level 3). See "Southern Company" herein for additional information.

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Segment and Related Information

9 Months Ended

Sep. 30, 2021

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 and battery energy storage projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through its natural gas distribution utilities and is involved in several other complementary businesses including gas pipeline investments, wholesale gas services (through June 30, 2021), 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 $167 million and $361 million for the three and nine months ended September 30, 2021, respectively, and $101 million and $279 million for the three and nine months ended September 30, 2020, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were immaterial for all periods presented. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $18 million for the nine months ended September 30, 2021, which represented sales from Sequent through June 30, 2021, and $9 million and $22 million for the three and nine months ended September 30, 2020, 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, 2021 and 2020 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, 2021
Operating revenues	$	5,018	$	679	$	(170)	$	5,527	$	623	$	124	$	(36)	$	6,238
Segment net income (loss)(a)(b)(c)	1,085		78		—		1,163		56		(121)		3		1,101
Nine Months Ended September 30, 2021
Operating revenues	$	12,813	$	1,610	$	(372)	$	14,051	$	2,994	$	412	$	(111)	$	17,346
Segment net income (loss)(a)(b)(c)(d)(e)(f)	2,352		211		—		2,563		389		(338)		(6)		2,608
At September 30, 2021
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	263	$	—	$	5,280
Assets held for sale	3		—		—		3		—		48		—		51
Total assets	89,057		13,611		(708)		101,960		22,958		3,704		(761)		127,861
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)(c)(f)(g)	2,571		212		—		2,783		360		(420)		9		2,732
At December 31, 2020
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	263	$	—	$	5,280
Assets held for sale	5		—		—		5		—		55		—		60
Total assets	85,486		13,235		(680)		98,041		22,630		3,168		(904)		122,935

(a)Attributable to Southern Company.

(b)For Southern Company Gas, includes a preliminary pre-tax gain of $121 million ($93 million after tax) related to its sale of Sequent, as well as the resulting $85 million of additional tax expense due to changes in state apportionment rates. See Note (K) under "Southern Company Gas" for additional information.

(c)For the traditional electric operating companies, includes pre-tax charges at Georgia Power for estimated losses associated with the construction of Plant Vogtle Units 3 and 4 of $264 million ($197 million after tax) and $772 million ($576 million after tax) for the three and nine months ended September 30, 2021, respectively, and $149 million ($111 million after tax) for the nine months ended September 30, 2020. 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.

(d)For Southern Power, includes gains on wind turbine equipment contributed to various equity method investments totaling approximately $37 million pre-tax ($28 million after tax). See Notes (E) and (K) under "Southern Power" for additional information.

(e)For Southern Company Gas, includes pre-tax impairment charges totaling $84 million ($67 million after tax) related to its equity method investment in the PennEast Pipeline project. See Notes (C) and (E) under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, for additional information.

(f)For the "All Other" column, includes pre-tax impairment charges related to leveraged lease investments of $7 million ($6 million after tax) and $154 million ($74 million after tax) for the nine months ended September 30, 2021 and 2020, respectively. See Note 3 to the financial statements in Item 8 of the Form 10-K under "Other Matters – Southern Company" for additional information.

(g)For Southern Power, includes a $39 million pre-tax gain ($23 million gain after tax) on the sale of Plant Mankato. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power" for additional information.

Products and Services

	Electric Utilities' Revenues
	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2021	$	4,551	$	731	$	245	$	5,527
Three Months Ended September 30, 2020	4,243		584		222		5,049
Nine Months Ended September 30, 2021	$	11,492	$	1,822	$	737	$	14,051
Nine Months Ended September 30, 2020	10,503		1,473		652		12,628

	Southern Company Gas' Revenues
	Gas Distribution Operations		Wholesale Gas Services(*)		Gas Marketing Services		Other		Total
	(in millions)
Three Months Ended September 30, 2021	$	553	$	—	$	52	$	18	$	623
Three Months Ended September 30, 2020	476		(51)		39		13		477
Nine Months Ended September 30, 2021	$	2,451	$	188	$	311	$	44	$	2,994
Nine Months Ended September 30, 2020	2,072		(19)		272		37		2,362

(*)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. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information on the disposition activities described herein.

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 project, and a 50% joint ownership interest in the Dalton Pipeline. These natural gas pipelines enable the provision of diverse sources of natural gas supplies to the customers of Southern Company Gas. Gas pipeline investments also included a 5% ownership interest in the Atlantic Coast Pipeline construction project prior to its sale on March 24, 2020. See Note (C) under "Other Matters – Southern Company Gas" for information regarding the September 2021 cancellation of the PennEast Pipeline project.

Wholesale gas services (until the sale of Sequent on July 1, 2021) provided natural gas asset management and/or related logistics services for each of Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. The Virginia Natural Gas asset management agreement ended on March 31, 2021 and was not extended. Additionally, wholesale gas services engaged in natural gas storage and gas pipeline arbitrage and related activities. See Note (K) under "Southern Company Gas" for information regarding the sale of Sequent on July 1, 2021.

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

The all other column includes segments and subsidiaries that fall below the quantitative threshold for separate disclosure, including storage and fuels operations. The all other column included Jefferson Island through its sale on December 1, 2020 and Pivotal LNG through its sale on March 24, 2020.

Business segment financial data for the three and nine months ended September 30, 2021 and 2020 was as follows:

	Gas Distribution Operations		Gas Pipeline Investments		Wholesale Gas Services(a)		Gas Marketing Services		Total		All Other		Eliminations		Consolidated
	(in millions)
Three Months Ended September 30, 2021
Operating revenues	$	556	$	8	$	—	$	52	$	616	$	11	$	(4)	$	623
Segment net income (loss)(b)(c)	45		10		94		(2)		147		(91)		—		56
Nine Months Ended September 30, 2021
Operating revenues	$	2,466	$	24	$	188	$	311	$	2,989	$	29	$	(24)	$	2,994
Segment net income (loss)(b)(c)(d)	308		3		108		60		479		(90)		—		389
Total assets at September 30, 2021	20,619		1,478		132		1,534		23,763		11,387		(12,192)		22,958
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 December 31, 2020	19,090		1,597		850		1,503		23,040		11,336		(11,746)		22,630

(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, 2021	$	—	$	—	$	—	$	—	$	—
Three Months Ended September 30, 2020	1,050		33		1,083		1,134		(51)
Nine Months Ended September 30, 2021	$	3,881	$	90	$	3,971	$	3,783	$	188
Nine Months Ended September 30, 2020	3,089		81		3,170		3,189		(19)

(b)For wholesale gas services, includes a preliminary pre-tax gain of $121 million ($93 million after tax) related to the sale of Sequent. See Note (K) under "Southern Company Gas" for additional information.

(c)For the "All Other" column, includes $85 million of additional tax expense due to changes in state apportionment rates as a result of the sale of Sequent. See Note (K) under "Southern Company Gas" for additional information.

(d)For gas pipeline investments, includes pre-tax impairment charges totaling $84 million ($67 million after tax) related to the equity method investment in the PennEast Pipeline project. See Notes (C) and (E) under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, for additional information.

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Introduction (Policies)

9 Months Ended

Sep. 30, 2021

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 at December 31, 2020 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, 2021 and 2020. 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

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.

Natural Gas for Sale

Natural Gas for Sale

With the exception of Nicor Gas, Southern Company Gas records natural gas inventories on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated.

Asset Retirement Obligations

The traditional electric operating companies have periodically updated, and expect to continue periodically updating, their related cost estimates and ARO liabilities for each CCR unit as additional information related to these assumptions becomes available. Some of these updates have been, and future updates may 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) under "Georgia Power – Rate Plan" for additional information. The ultimate outcome of these matters cannot be determined at this time.

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 it is primarily obligated to make generation-based payments to the seller, which commenced at the commercial operation of the respective facility and continue through 2026. The obligations are categorized as Level 3 under Fair Value Measurements as

the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate.

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. Through the sale of Sequent on July 1, 2021, Southern Company Gas' wholesale gas operations used various contracts in its commercial activities that generally met the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with the classification of the hedged interest or principal, respectively. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information. See Note (K) under "Southern Company Gas" for information regarding Southern Company Gas' sale of Sequent.

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 an approved cost recovery mechanism.

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

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

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

Interest Rate Derivatives

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

Foreign Currency Derivatives

Southern Company and certain subsidiaries, including Southern Power, may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Southern Company has elected to exclude the cross-currency basis spread from the assessment of effectiveness in the fair value hedges of its foreign currency risk and record any difference between the change in the fair value of the excluded components and the amounts recognized in earnings as a component of OCI.

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Introduction (Tables)

9 Months Ended

Sep. 30, 2021

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Goodwill

Goodwill at September 30, 2021 and December 31, 2020 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, 2021						At December 31, 2020
	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	$	(148)	$	64	$	212	$	(135)	$	77
Trade names	64		(36)		28		64		(31)		33
Storage and transportation contracts(*)	—		—		—		64		(64)		—
PPA fair value adjustments	390		(104)		286		390		(89)		301
Other	10		(8)		2		10		(9)		1
Total other intangible assets subject to amortization	$	676	$	(296)	$	380	$	740	$	(328)	$	412
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—		75		75		—		75
Total other intangible assets	$	751	$	(296)	$	455	$	815	$	(328)	$	487
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	390	$	(104)	$	286	$	390	$	(89)	$	301
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	156	$	(128)	$	28	$	156	$	(119)	$	37
Trade names	26		(14)		12		26		(12)		14
Wholesale gas services
Storage and transportation contracts(*)	—		—		—		64		(64)		—
Total other intangible assets subject to amortization	$	182	$	(142)	$	40	$	246	$	(195)	$	51

(*)See Note (K) under "Southern Company Gas" for information regarding the sale of Sequent.

Schedule of Other Intangible Assets, Finite-Lived

Other intangible assets were as follows:

	At September 30, 2021						At December 31, 2020
	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	$	(148)	$	64	$	212	$	(135)	$	77
Trade names	64		(36)		28		64		(31)		33
Storage and transportation contracts(*)	—		—		—		64		(64)		—
PPA fair value adjustments	390		(104)		286		390		(89)		301
Other	10		(8)		2		10		(9)		1
Total other intangible assets subject to amortization	$	676	$	(296)	$	380	$	740	$	(328)	$	412
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—		75		75		—		75
Total other intangible assets	$	751	$	(296)	$	455	$	815	$	(328)	$	487
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	390	$	(104)	$	286	$	390	$	(89)	$	301
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	156	$	(128)	$	28	$	156	$	(119)	$	37
Trade names	26		(14)		12		26		(12)		14
Wholesale gas services
Storage and transportation contracts(*)	—		—		—		64		(64)		—
Total other intangible assets subject to amortization	$	182	$	(142)	$	40	$	246	$	(195)	$	51

(*)See Note (K) under "Southern Company Gas" for information regarding the sale of Sequent.

Schedule of Amortization of Other Intangible Assets

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Nine Months Ended
	September 30, 2021
	(in millions)
Southern Company(a)	$	11	$	33
Southern Power(b)	5		15
Southern Company Gas(c)	4		11

(a)Includes $5 million and $15 million for the three and nine months ended September 30, 2021, respectively, recorded as a reduction to operating revenues.

(b)Recorded as a reduction to operating revenues.

(c)Relates to gas marketing services.

Schedule of 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 amount shown in the condensed statements of cash flows for the applicable Registrants:

	Southern Company				Southern Power		Southern Company Gas
	September 30, 2021		December 31, 2020		September 30, 2021		September 30, 2021		December 31, 2020
	(in millions)				(in millions)		(in millions)
Cash and cash equivalents	$	2,078	$	1,065	$	192	$	29	$	17
Restricted cash(a):
Other current assets	3		2		—		3		2
Other deferred charges and assets	21		—		21		—		—
Total cash, cash equivalents, and restricted cash(b)	$	2,101	$	1,068	$	213	$	32	$	19

(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 may 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 amount shown in the condensed statements of cash flows for the applicable Registrants:

	Southern Company				Southern Power		Southern Company Gas
	September 30, 2021		December 31, 2020		September 30, 2021		September 30, 2021		December 31, 2020
	(in millions)				(in millions)		(in millions)
Cash and cash equivalents	$	2,078	$	1,065	$	192	$	29	$	17
Restricted cash(a):
Other current assets	3		2		—		3		2
Other deferred charges and assets	21		—		21		—		—
Total cash, cash equivalents, and restricted cash(b)	$	2,101	$	1,068	$	213	$	32	$	19

(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 may not add due to rounding.

Schedule of Changes in Asset Retirement Obligations

Details of changes in AROs for Southern Company, Alabama Power, Georgia Power, and Mississippi Power during the first nine months of 2021 are shown in the following table. There were no material changes in AROs for the other Registrants during the first nine months of 2021.

	Southern Company		Alabama Power		Georgia Power		Mississippi Power
	(in millions)
Balance at December 31, 2020	$	10,684	$	3,974	$	6,265	$	176
Liabilities incurred	17		—		3		—
Liabilities settled	(341)		(152)		(154)		(18)
Accretion	304		116		176		6
Cash flow revisions	945		385		475		30
Balance at September 30, 2021	$	11,609	$	4,323	$	6,765	$	194

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Regulatory Matters (Tables)

9 Months Ended

Sep. 30, 2021

Regulated Operations [Abstract]

Schedule of Cost Recovery Clauses

The recovery balances for certain retail regulatory clauses of the traditional electric operating companies and Southern Company Gas at September 30, 2021 and December 31, 2020 were as follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2021		December 31, 2020
		(in millions)
Alabama Power
Rate CNP Compliance	Other regulatory liabilities, current	$	—	$	28
	Other regulatory liabilities, deferred	24		—
Rate CNP PPA	Other regulatory assets, deferred	88		58
Retail Energy Cost Recovery	Other regulatory liabilities, current	—		18
	Other regulatory assets, current	79		—
	Other regulatory assets, deferred	6		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	36		77
Georgia Power
Fuel Cost Recovery	Over recovered fuel clause revenues	$	—	$	113
	Other deferred charges and assets	203		—
Mississippi Power
Fuel Cost Recovery	Over recovered regulatory clause liabilities	$	5	$	24
Ad Valorem Tax	Other regulatory assets, current	12		11
	Other regulatory assets, deferred	39		41
Property Damage Reserve	Other regulatory liabilities, deferred	—		4
	Other regulatory assets, deferred	16		—
Southern Company Gas
Natural Gas Cost Recovery(*)	Other regulatory liabilities	$	—	$	88
	Natural gas cost under recovery	432		—
	Other regulatory assets, deferred	79		—

(*)The significant change during the nine months ended September 30, 2021 was primarily driven by an increase in the cost of gas purchased in February 2021 resulting from Winter Storm Uri.

Nuclear Construction Cost and Schedule

Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4, including contingency, through September 2022 and June 2023, respectively, is as follows:

	(in millions)
Base project capital cost forecast(a)(b)	$	9,342
Construction contingency estimate	137
Total project capital cost forecast(a)(b)	9,479
Net investment at September 30, 2021(b)	(8,159)
Remaining estimate to complete	$	1,320

(a)    Includes approximately $570 million of costs that are not shared with the other Vogtle Owners. Excludes financing costs expected to be capitalized through AFUDC of approximately $318 million, of which $169 million had been accrued through September 30, 2021.

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

Schedule of Infrastructure Replacement Programs and Capital Projects

Capital expenditures incurred under specific infrastructure replacement programs during the first nine months of 2021 were as follows:

Utility	Program	Nine Months Ended September 30, 2021
		(in millions)
Nicor Gas	Investing in Illinois	$	307
Virginia Natural Gas	Steps to Advance Virginia's Energy	36
Total		$	343

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Revenue from Contracts with Customers and Lease Income (Tables)

9 Months Ended

Sep. 30, 2021

Revenue from Contract with Customer [Abstract]

Schedule of Disaggregation of Revenue

The following table disaggregates revenue from contracts with customers for the three and nine months ended September 30, 2021 and 2020:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2021
Operating revenues
Retail electric revenues
Residential	$	1,974	$	750	$	1,138	$	86	$	—	$	—
Commercial	1,432		471		882		79		—		—
Industrial	902		394		428		80		—		—
Other	24		4		18		2		—		—
Total retail electric revenues	4,332		1,619		2,466		247		—		—
Natural gas distribution revenues
Residential	218		—		—		—		—		218
Commercial	55		—		—		—		—		55
Transportation	239		—		—		—		—		239
Industrial	6		—		—		—		—		6
Other	31		—		—		—		—		31
Total natural gas distribution revenues	549		—		—		—		—		549
Wholesale electric revenues
PPA energy revenues	359		61		41		2		261		—
PPA capacity revenues	125		14		14		1		97		—
Non-PPA revenues	63		54		3		120		134		—
Total wholesale electric revenues	547		129		58		123		492		—
Other natural gas revenues
Gas marketing services	45		—		—		—		—		45
Other natural gas revenues	11		—		—		—		—		11
Total natural gas revenues	56		—		—		—		—		56
Other revenues	248		53		112		8		9		—
Total revenue from contracts with customers	5,732		1,801		2,636		378		501		605
Other revenue sources(a)	506		103		220		—		178		18
Total operating revenues	$	6,238	$	1,904	$	2,856	$	378	$	679	$	623

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Nine Months Ended September 30, 2021
Operating revenues
Retail electric revenues
Residential	$	4,910	$	1,931	$	2,765	$	214	$	—	$	—
Commercial	3,727		1,229		2,293		205		—		—
Industrial	2,299		1,048		1,034		217		—		—
Other	70		13		51		6		—		—
Total retail electric revenues	11,006		4,221		6,143		642		—		—
Natural gas distribution revenues
Residential	1,143		—		—		—		—		1,143
Commercial	298		—		—		—		—		298
Transportation	775		—		—		—		—		775
Industrial	29		—		—		—		—		29
Other	187		—		—		—		—		187
Total natural gas distribution revenues	2,432		—		—		—		—		2,432
Wholesale electric revenues
PPA energy revenues	782		143		71		9		575		—
PPA capacity revenues	375		86		41		4		247		—
Non-PPA revenues	181		108		14		283		273		—
Total wholesale electric revenues	1,338		337		126		296		1,095		—
Other natural gas revenues
Wholesale gas services	2,168		—		—		—		—		2,168
Gas marketing services	303		—		—		—		—		303
Other natural gas revenues	27		—		—		—		—		27
Total natural gas revenues	2,498		—		—		—		—		2,498
Other revenues	792		150		362		22		18		—
Total revenue from contracts with customers	18,066		4,708		6,631		960		1,113		4,930
Other revenue sources(a)	2,979		311		419		28		497		1,763
Other adjustments(b)	(3,699)		—		—		—		—		(3,699)
Total operating revenues	$	17,346	$	5,019	$	7,050	$	988	$	1,610	$	2,994

	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

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

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

Schedule of 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, 2021 and December 31, 2020:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Accounts Receivable
At September 30, 2021	$	2,343	$	712	$	904	$	90	$	170	$	329
At December 31, 2020	2,614		632		806		77		112		788
Contract Assets
At September 30, 2021	$	165	$	5	$	103	$	—	$	1	$	—
At December 31, 2020	158		2		71		—		—		—
Contract Liabilities
At September 30, 2021	$	65	$	6	$	39	$	1	$	2	$	—
At December 31, 2020	61		6		27		1		1		1

Schedule of Remaining Performance Obligations

Revenues from contracts with customers related to these performance obligations remaining at September 30, 2021 are expected to be recognized as follows:

	2021 (remaining)		2022		2023		2024		2025		Thereafter
	(in millions)
Southern Company	$	156	$	543	$	347	$	327	$	307	$	2,667
Alabama Power	13		32		24		7		5		—
Georgia Power	22		64		43		23		21		41
Southern Power	70		323		281		297		281		2,644

Schedule of Lease Income

Lease income for the three and nine months ended September 30, 2021 and 2020 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, 2021
Lease income - interest income on sales-type leases	$	4	$	—	$	—	$	4	$	—	$	—
Lease income - operating leases	56		21		11		—		21		9
Variable lease income	143		—		—		—		151		—
Total lease income	$	203	$	21	$	11	$	4	$	172	$	9
For the Nine Months Ended September 30, 2021
Lease income - interest income on sales-type leases	$	11	$	—	$	—	$	10	$	—	$	—
Lease income - operating leases	168		62		31		1		64		26
Variable lease income	355		—		—		—		379		—
Total lease income	$	534	$	62	$	31	$	11	$	443	$	26
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

Undiscounted Cash Flows to be Received Under Sales-type Leases

The undiscounted cash flows expected to be received by Southern Power for assets under the lease are as follows:

	At September 30, 2021
	(in millions)
2021 (remaining)	$	2
2022	8
2023	8
2024	8
2025	8
2026	8
Thereafter	115
Total undiscounted cash flows	$	157
Net investment in sales-type lease(*)	99
Difference between undiscounted cash flows and discounted cash flows	$	58

(*)Included in other current assets and other property and investments on the balance sheet.

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Consolidated Entities and Equity Method Investments (Tables)

9 Months Ended

Sep. 30, 2021

Regulated Operations [Abstract]

Schedule of Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments at September 30, 2021 and December 31, 2020 and related earnings (loss) from those investments for the three and nine months ended September 30, 2021 and 2020 were as follows:

Investment Balance	September 30, 2021		December 31, 2020
	(in millions)
SNG	$	1,130	$	1,167
PennEast Pipeline(*)	11		91
Other	33		32
Total	$	1,174	$	1,290

(*)Investment balance at September 30, 2021 reflects pre-tax impairment charges totaling $84 million recorded during 2021. See Note (C) under "Other Matters – Southern Company Gas" for additional information, including the September 2021 cancellation of the project.

Schedule of Earnings (Loss) from Equity Method Investments

	Three Months Ended September 30,				Nine Months Ended September 30,
Earnings (Loss) from Equity Method Investments	2021		2020		2021		2020
	(in millions)
SNG	$	27	$	30	$	93	$	95
PennEast Pipeline(a)(b)	(2)		2		(81)		5
Other(a)(c)	—		1		2		6
Total	$	25	$	33	$	14	$	106

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

(b)Includes pre-tax impairment charges totaling $2 million and $84 million for the three and nine months ended September 30, 2021, respectively. See Note (C) under "Other Matters – Southern Company Gas" for additional information, including the September 2021 cancellation of the project.

(c)On March 24, 2020, Southern Company Gas completed the sale of its interests in Atlantic Coast Pipeline and Pivotal LNG. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.

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Financing (Tables)

9 Months Ended

Sep. 30, 2021

Debt Disclosure [Abstract]

Schedule of Credit Arrangements

At September 30, 2021, committed credit arrangements with banks were as follows:

	Expires
Company	2022		2023		2024		2026		Total		Unused		Due within One Year
	(in millions)
Southern Company parent	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—
Alabama Power	—		—		550		700		1,250		1,250		—
Georgia Power	—		—		—		1,750		1,750		1,726		—
Mississippi Power	—		125		150		—		275		250		—
Southern Power(a)	—		—		—		600		600		568		—
Southern Company Gas(b)	250		—		—		1,500		1,750		1,747		250
SEGCO	30		—		—		—		30		30		30
Southern Company	$	280	$	125	$	700	$	6,550	$	7,655	$	7,570	$	280

(a)Does not include Southern Power Company's $75 million and $60 million continuing letter of credit facilities for standby letters of credit expiring in 2023, of which $23 million and $1 million, respectively, was unused at September 30, 2021. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.

(b)Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $800 million of the arrangement expiring in 2026 and all $250 million of the arrangement expiring in 2022. Southern Company Gas' committed credit arrangement expiring in 2026 also includes $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to the multi-year credit arrangement expiring in 2026, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.

Schedule of Shares Used to Compute Diluted Earnings Per Share

Shares used to compute diluted earnings per share were as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020
	(in millions)
As reported shares	1,061	1,058	1,060	1,058
Effect of stock-based compensation	7	6	7	6
Diluted shares	1,068	1,064	1,067	1,064

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2021

Income Tax Disclosure [Abstract]

Summary of Operating Loss Carryforwards Valuation Allowances

Details of significant changes in valuation allowances for the applicable Registrants are provided below:

	Southern Company		Georgia Power
	(in millions)
Federal	$	20	$	—
State (net of federal benefit)	92		28
Balance at December 31, 2020	$	112	$	28
Federal	$	20	$	—
State (net of federal benefit)	122		58
Balance at September 30, 2021	$	142	$	58

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Retirement Benefits (Tables)

9 Months Ended

Sep. 30, 2021

Retirement Benefits [Abstract]

Schedule of Pension Plans and Postretirement Plans

Components of the net periodic benefit costs for the three and nine months ended September 30, 2021 and 2020 are presented in the following tables.

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2021
Pension Plans
Service cost	$	109	$	26	$	28	$	4	$	2	$	10
Interest cost	87		20		26		4		2		6
Expected return on plan assets	(298)		(72)		(94)		(14)		(4)		(21)
Amortization:
Prior service costs	—		—		—		—		—		(1)
Regulatory asset	—		—		—		—		—		3
Net (gain)/loss	78		21		25		4		1		3
Net periodic pension cost (income)	$	(24)	$	(5)	$	(15)	$	(2)	$	1	$	—
Postretirement Benefits
Service cost	$	6	$	2	$	2	$	1	$	1	$	—
Interest cost	9		2		3		—		—		1
Expected return on plan assets	(19)		(8)		(7)		(1)		—		(2)
Amortization:
Regulatory asset	—		—		—		—		—		2
Net (gain)/loss	1		—		1		—		—		(1)
Net periodic postretirement benefit cost (income)	$	(3)	$	(4)	$	(1)	$	—	$	1	$	—
Nine Months Ended September 30, 2021
Pension Plans
Service cost	$	326	$	77	$	84	$	13	$	7	$	28
Interest cost	260		61		78		12		4		18
Expected return on plan assets	(893)		(215)		(282)		(41)		(11)		(64)
Amortization:
Prior service costs	—		—		1		—		—		(2)
Regulatory asset	—		—		—		—		—		11
Net (gain)/loss	235		62		75		11		3		9
Net periodic pension cost (income)	$	(72)	$	(15)	$	(44)	$	(5)	$	3	$	—
Postretirement Benefits
Service cost	$	18	$	5	$	5	$	1	$	1	$	1
Interest cost	26		6		9		1		—		3
Expected return on plan assets	(57)		(22)		(20)		(2)		—		(6)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		5
Net (gain)/loss	3		—		2		—		—		(2)
Net periodic postretirement benefit cost (income)	$	(11)	$	(11)	$	(4)	$	—	$	1	$	1

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2020
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 (income)	$	2	$	(2)	$	—	$	—	$	1	$	1
Nine Months Ended September 30, 2020
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 (income)	$	4	$	(7)	$	1	$	1	$	1	$	4

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2021

Fair Value Disclosures [Abstract]

Schedule of Assets and Liabilities Measured at Fair Value

At September 30, 2021, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

	Fair Value Measurements Using:
At September 30, 2021	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)	$	75	$	425	$	—	$	—	$	500
Interest rate derivatives	—		25		—		—		25
Foreign currency derivatives	—		20		—		—		20
Investments in trusts:(b)(c)
Domestic equity	738		237		—		—		975
Foreign equity	167		183		—		—		350
U.S. Treasury and government agency securities	—		352		—		—		352
Municipal bonds	—		48		—		—		48
Pooled funds – fixed income	—		14		—		—		14
Corporate bonds	2		472		—		—		474
Mortgage and asset backed securities	—		92		—		—		92
Private equity	—		—		—		123		123
Cash and cash equivalents	5		—		—		—		5
Other	29		13		—		—		42
Cash equivalents	1,498		9		—		—		1,507
Other investments	9		26		—		—		35
Total	$	2,523	$	1,916	$	—	$	123	$	4,562
Liabilities:
Energy-related derivatives(a)	$	27	$	17	$	—	$	—	$	44
Interest rate derivatives	—		16		—		—		16
Foreign currency derivatives	—		43		—		—		43
Contingent consideration	—		—		16		—		16
Other	—		13		—		—		13
Total	$	27	$	89	$	16	$	—	$	132

	Fair Value Measurements Using:
At September 30, 2021	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	$	—	$	104	$	—	$	—	$	104
Interest rate derivatives	—		5		—		—		5
Nuclear decommissioning trusts:(b)
Domestic equity	444		227		—		—		671
Foreign equity	167		—		—		—		167
U.S. Treasury and government agency securities	—		22		—		—		22
Municipal bonds	—		1		—		—		1
Corporate bonds	2		243		—		—		245
Mortgage and asset backed securities	—		22		—		—		22
Private equity	—		—		—		123		123
Other	6		—		—		—		6
Cash equivalents	443		9		—		—		452
Other investments	—		26		—		—		26
Total	$	1,062	$	659	$	—	$	123	$	1,844
Liabilities:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4
Georgia Power
Assets:
Energy-related derivatives	$	—	$	166	$	—	$	—	$	166
Nuclear decommissioning trusts:(b)(c)
Domestic equity	294		1		—		—		295
Foreign equity	—		180		—		—		180
U.S. Treasury and government agency securities	—		330		—		—		330
Municipal bonds	—		47		—		—		47
Corporate bonds	—		229		—		—		229
Mortgage and asset backed securities	—		70		—		—		70
Other	23		13		—		—		36
Cash equivalents	240		—		—		—		240
Total	$	557	$	1,036	$	—	$	—	$	1,593
Liabilities:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4

	Fair Value Measurements Using:
At September 30, 2021	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	$	—	$	105	$	—	$	—	$	105
Cash equivalents	121		—		—		—		121
Total	$	121	$	105	$	—	$	—	$	226
Liabilities:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Southern Power
Assets:
Energy-related derivatives	$	—	$	10	$	—	$	—	$	10
Foreign currency derivatives	—		20		—		—		20
Total	$	—	$	30	$	—	$	—	$	30
Liabilities:
Energy-related derivatives	$	—	$	2	$	—	$	—	$	2
Foreign currency derivatives	—		11		—		—		11
Contingent consideration	—		—		16		—		16
Other	—		13		—		—		13
Total	$	—	$	26	$	16	$	—	$	42
Southern Company Gas
Assets:
Energy-related derivatives(a)	$	75	$	40	$	—	$	—	$	115
Interest rate derivatives	—		6		—		—		6
Non-qualified deferred compensation trusts:
Domestic equity	—		9		—		—		9
Foreign equity	—		3		—		—		3
Pooled funds – fixed income	—		14		—		—		14
Cash equivalents	5		—		—		—		5
Total	$	80	$	72	$	—	$	—	$	152
Liabilities:
Energy-related derivatives(a)	$	27	$	4	$	—	$	—	$	31
Interest rate derivatives	—		4		—		—		4
Total	$	27	$	8	$	—	$	—	$	35

(a)Excludes cash collateral of $(20) million.

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

(c)Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. At September 30, 2021, approximately $57 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 nine months ended September 30, 2021 and 2020. 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, 2021		Three Months Ended September 30, 2020		Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020
	(in millions)
Southern Company	$	9	$	108	$	173	$	85
Alabama Power	15		66		133		24
Georgia Power	(6)		42		40		61

Schedule of Financial Instruments for which Carrying Amount Did Not Equal Fair Value

At September 30, 2021, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas(*)
	(in billions)
Long-term debt, including securities due within one year:
Carrying amount	$	51.9	$	9.1	$	13.6	$	1.6	$	4.0	$	6.8
Fair value	57.6		10.4		15.2		1.7		4.4		7.8

(*)The long-term debt of Southern Company Gas is recorded at amortized cost, including the fair value adjustments at the effective date of the 2016 merger with Southern Company. Southern Company Gas amortizes the fair value adjustments over the remaining lives of the respective bonds, the latest being through 2043.

Schedule of Fair Value of Commodity Derivative Contracts that Include a Significant Unobservable Component

The following table provides a reconciliation of Southern Company Gas' Level 3 contracts during the three and nine months ended September 30, 2021.

	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	(in millions)
Beginning balance	$	18	$	28
Instruments realized or otherwise settled during period	—		(6)
Changes in fair value	—		(4)
Sale of Sequent	(18)		(18)
Ending balance	$	—	$	—

XML

Derivatives (Tables)

9 Months Ended

Sep. 30, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Energy-Related Derivatives

At September 30, 2021, 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(*)	336	2030	2024
Alabama Power	75	2024	—
Georgia Power	99	2024	—
Mississippi Power	79	2025	—
Southern Power	6	2030	2022
Southern Company Gas(*)	77	2024	2024

(*)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 91.4 million mmBtu and short natural gas positions of 14.3 million mmBtu at September 30, 2021, which is also included in Southern Company's total volume. See Note (K) under "Southern Company Gas" for information regarding Southern Company Gas' sale of Sequent.

Schedule of Interest Rate Derivatives

At September 30, 2021, 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, 2021
	(in millions)					(in millions)
Cash Flow Hedges of Forecasted Debt
Alabama Power	$	150	—	1.91%	August 2051	$	5
Fair Value Hedges of Existing Debt
Southern Company parent	400		1.75%	1-month LIBOR + 0.68%	March 2028	(2)
Southern Company parent	1,000		3.70%	1-month LIBOR + 2.36%	April 2030	3
Southern Company Gas	500		1.75%	1-month LIBOR + 0.38%	January 2031	2
Southern Company	$	2,050				$	8

Schedule of Foreign Currency Derivatives

At September 30, 2021, 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, 2021
	(in millions)			(in millions)				(in millions)
Fair Value Hedges of Existing Debt
Southern Company parent	$	1,476	3.39%	€	1,250	1.88%	September 2027	$	(32)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	9
Southern Power	564		3.78%	500		1.85%	June 2026	—
Southern Power total	$	1,241		€	1,100			$	9
Southern Company	$	2,717		€	2,350			$	(23)

Schedule of Derivative Category and Balance Sheet Location

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

	At September 30, 2021				At December 31, 2020
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:
Assets from risk management activities/Other current liabilities	$	308	$	9	$	24	$	11
Other deferred charges and assets/Other deferred credits and liabilities	118		6		18		19
Total derivatives designated as hedging instruments for regulatory purposes	$	426	$	15	$	42	$	30
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Other current liabilities	$	41	$	—	$	3	$	5
Other deferred charges and assets/Other deferred credits and liabilities	4		—		—		—
Interest rate derivatives:
Assets from risk management activities/Other current liabilities	25		—		20		—
Other deferred charges and assets/Other deferred credits and liabilities	—		16		—		—
Foreign currency derivatives:
Assets from risk management activities/Other current liabilities	9		33		—		23
Other deferred charges and assets/Other deferred credits and liabilities	11		10		87		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	90	$	59	$	110	$	28
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Other current liabilities	$	29	$	29	$	388	$	331
Other deferred charges and assets/Other deferred credits and liabilities	1		—		270		232
Total derivatives not designated as hedging instruments	$	30	$	29	$	658	$	563
Gross amounts recognized	$	546	$	103	$	810	$	621
Gross amounts offset(a)	(57)		(37)		(529)		(557)
Net amounts recognized in the Balance Sheets(b)	$	489	$	66	$	281	$	64

	At September 30, 2021				At December 31, 2020
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	$	67	$	2	$	7	$	2
Other deferred charges and assets/Other deferred credits and liabilities	37		2		5		5
Total derivatives designated as hedging instruments for regulatory purposes	$	104	$	4	$	12	$	7
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	5	$	—	$	—	$	—
Gross amounts recognized	$	109	$	4	$	12	$	7
Gross amounts offset	(3)		(3)		(7)		(7)
Net amounts recognized in the Balance Sheets	$	106	$	1	$	5	$	—
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	124	$	2	$	7	$	5
Other deferred charges and assets/Other deferred credits and liabilities	42		2		8		8
Total derivatives designated as hedging instruments for regulatory purposes	$	166	$	4	$	15	$	13
Gross amounts recognized	$	166	$	4	$	15	$	13
Gross amounts offset	(3)		(3)		(12)		(12)
Net amounts recognized in the Balance Sheets	$	163	$	1	$	3	$	1
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	66	$	1	$	4	$	3
Other deferred charges and assets/Other deferred credits and liabilities	39		2		5		6
Total derivatives designated as hedging instruments for regulatory purposes	$	105	$	3	$	9	$	9
Gross amounts recognized	$	105	$	3	$	9	$	9
Gross amounts offset	(2)		(2)		(7)		(7)
Net amounts recognized in the Balance Sheets	$	103	$	1	$	2	$	2

	At September 30, 2021				At December 31, 2020
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Southern Power
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	8	$	—	$	2	$	2
Other deferred charges and assets/Other deferred credits and liabilities	1		—		—		—
Foreign currency derivatives:
Other current assets/Other current liabilities	9		11		—		23
Other deferred charges and assets/Other deferred credits and liabilities	11		—		87		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	29	$	11	$	89	$	25
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	1	$	2	$	—	$	1
Total derivatives not designated as hedging instruments	$	1	$	2	$	—	$	1
Gross amounts recognized	$	30	$	13	$	89	$	26
Gross amounts offset	(1)		(1)		—		—
Net amounts recognized in the Balance Sheets	$	29	$	12	$	89	$	26

	At September 30, 2021				At December 31, 2020
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/Other current liabilities	$	51	$	4	$	6	$	1
Total derivatives designated as hedging instruments for regulatory purposes	$	51	$	4	$	6	$	1
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Other current liabilities	$	33	$	—	$	1	$	3
Other deferred charges and assets/Other deferred credits and liabilities	3		—		—		—
Interest rate derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	6		—		—		—
Other deferred charges and assets/Other deferred credits and liabilities	—		4		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	42	$	4	$	1	$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Other current liabilities	$	28	$	27	$	388	$	330
Other deferred charges and assets/Other deferred credits and liabilities	1		—		270		232
Total derivatives not designated as hedging instruments	$	29	$	27	$	658	$	562
Gross amounts recognized	$	122	$	35	$	665	$	566
Gross amounts offset(a)	(48)		(28)		(503)		(531)
Net amounts recognized in the Balance Sheets(b)	$	74	$	7	$	162	$	35

(a)Gross amounts offset include cash collateral held on deposit in broker margin accounts of $(20) million and $28 million at September 30, 2021 and December 31, 2020, respectively.

(b)Net amounts of derivative instruments outstanding exclude immaterial premium and intrinsic value associated with weather derivatives for both periods presented.

Schedule of Pre-tax Effects of Unrealized Derivative Gains (Losses)

At September 30, 2021 and December 31, 2020, 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, 2021:
Energy-related derivatives:
Other regulatory assets, current	$	(5)	$	(1)	$	(1)	$	—	$	(3)
Other regulatory liabilities, current	297		66		123		66		42
Other regulatory liabilities, deferred	112		35		40		37		—
Total energy-related derivative gains (losses)	$	404	$	100	$	162	$	103	$	39
At December 31, 2020:
Energy-related derivatives:
Other regulatory assets, deferred	$	(2)	$	—	$	(1)	$	(1)	$	—
Other regulatory liabilities, current	12		5		2		1		4
Other regulatory liabilities, deferred	2		1		1		—		—
Total energy-related derivative gains (losses)	$	12	$	6	$	2	$	—	$	4

Schedule of Pre-Tax Effects of Hedging on AOCI

For the three and nine months ended September 30, 2021 and 2020, the pre-tax effects of cash flow and fair value hedge accounting on accumulated OCI were as follows:

Gain (Loss) Recognized in OCI on Derivative	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Southern Company
Cash flow hedges:
Energy-related derivatives	$	38	$	9	$	59	$	2
Interest rate derivatives	5		1		7		(27)
Foreign currency derivatives	(36)		54		(79)		(10)
Fair value hedges(*):
Foreign currency derivatives	(4)		—		(4)		—
Total	$	3	$	64	$	(17)	$	(35)
Southern Power
Cash flow hedges:
Energy-related derivatives	$	8	$	5	$	16	$	2
Foreign currency derivatives	(36)		54		(79)		(10)
Total	$	(28)	$	59	$	(63)	$	(8)
Southern Company Gas
Cash flow hedges:
Energy-related derivatives	$	30	$	4	$	43	$	—
Interest rate derivatives	—		1		—		(24)
Total	$	30	$	5	$	43	$	(24)

(*)Represents amounts excluded from the assessment of effectiveness for which the difference between changes in fair value and periodic amortization is recorded in OCI.

Schedule of Pre-Tax Effects of Cash Flow and Fair Value Hedging on Income

For the three and nine months ended September 30, 2021 and 2020, 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,
	2021		2020		2021		2020
	(in millions)				(in millions)
Southern Company
Total cost of natural gas	$	129	$	71	$	943	$	654
Gain (loss) on energy-related cash flow hedges(a)	2		—		—		(8)
Total depreciation and amortization	896		889		2,658		2,619
Gain (loss) on energy-related cash flow hedges(a)	3		(1)		6		(3)
Total interest expense, net of amounts capitalized	(451)		(443)		(1,352)		(1,343)
Gain (loss) on interest rate cash flow hedges(a)	(7)		(6)		(20)		(19)
Gain (loss) on foreign currency cash flow hedges(a)	(6)		(6)		(18)		(18)
Gain (loss) on interest rate fair value hedges(b)	(4)		(3)		(16)		27
Total other income (expense), net	131		113		297		319
Gain (loss) on foreign currency cash flow hedges(a)(c)	(34)		56		(76)		52
Gain (loss) on foreign currency fair value hedges	(32)		—		(32)		—
Amount excluded from effectiveness testing recognized in earnings	4		—		4		—
Southern Power
Total depreciation and amortization	$	132	$	129	$	383	$	367
Gain (loss) on energy-related cash flow hedges(a)	3		(1)		6		(3)
Total interest expense, net of amounts capitalized	(36)		(36)		(111)		(114)
Gain (loss) on foreign currency cash flow hedges(a)	(6)		(6)		(18)		(18)
Total other income (expense), net	2		13		10		19
Gain (loss) on foreign currency cash flow hedges(a)(c)	(34)		56		(76)		52

(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 Cumulative Basis Adjustments for Fair Value Hedges

At September 30, 2021 and December 31, 2020, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:

	Carrying Amount of the Hedged Item				Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items	At September 30, 2021		At December 31, 2020		At September 30, 2021		At December 31, 2020
	(in millions)				(in millions)
Southern Company
Securities due within one year	$	—	$	(1,509)	$	—	$	(10)
Long-term debt	(3,320)		—		—		—
Southern Company Gas
Long-term debt	$	(497)	$	—	$	(1)	$	—

Schedule of Pre-tax Effect of Interest Rate and Energy Related Derivatives on Income

For the three and nine months ended September 30, 2021 and 2020, 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	2021		2020		2021		2020
		(in millions)				(in millions)
Energy-related derivatives:	Natural gas revenues(*)	$	(2)	$	(30)	$	(122)	$	54
	Cost of natural gas	20		5		36		18
Total derivatives in non-designated hedging relationships		$	18	$	(25)	$	(86)	$	72

(*)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, 2021

Business Combination and Asset Acquisition [Abstract]

Schedule of Asset Acquisitions

During the nine months ended September 30, 2021, Southern Power acquired a controlling membership 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
Deuel Harvest(*)	Wind	Invenergy Renewables, LLC	300	Deuel County, SD	100% of Class B	February 2021	25 years and 15 years

(*)On March 26, 2021, Southern Power acquired a controlling interest in the project from Invenergy Renewables LLC and, on March 30, 2021, Southern Power completed a tax equity transaction whereby it sold the Class A membership interests in the project. Southern Power consolidates the project's operating results in its financial statements and the tax equity partner and Invenergy Renewables LLC each own a noncontrolling interest.

Schedule of Construction Projects

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
Projects Under Construction at September 30, 2021
Garland Solar Storage(a)	Battery energy storage system	88	Kern County, CA	September 2021 and fourth quarter 2021(b)	20 years
Tranquillity Solar Storage(a)	Battery energy storage system	72	Fresno County, CA	Fourth quarter 2021 and first quarter 2022	20 years
Glass Sands(c)	Wind	118	Murray County, OK	Fourth quarter 2021	12 years

(a)During the third quarter 2021, Southern Power further restructured its ownership in the Garland and Tranquillity battery energy storage projects and completed tax equity transactions whereby it sold the Class A membership interests in the projects. Southern Power consolidates each project's operating results in its financial statements and the tax equity partner and two other partners each own a noncontrolling interest.

(b)The facility has a total capacity of 88 MWs, of which 45 MWs were placed in service in September 2021 and 43 MWs are expected to be placed in service later in the fourth quarter 2021.

(c)In December 2020, Southern Power purchased 100% of the membership interests of the Glass Sands facility.

Schedule of Assets Held for Sale

The following table provides the major classes of assets classified as held for sale by Southern Company at September 30, 2021 and December 31, 2020:

	Southern Company
	At September 30,		At December 31,
	2021		2020
	(in millions)
Assets Held for Sale:
Total property, plant, and equipment	$	6	$	8
Leveraged leases	45		52
Total Assets Held for Sale	$	51	$	60

XML

Segment and Related Information (Tables)

9 Months Ended

Sep. 30, 2021

Segment Reporting [Abstract]

Schedule of Financial Data for Business Segments

Financial data for business segments and products and services for the three and nine months ended September 30, 2021 and 2020 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, 2021
Operating revenues	$	5,018	$	679	$	(170)	$	5,527	$	623	$	124	$	(36)	$	6,238
Segment net income (loss)(a)(b)(c)	1,085		78		—		1,163		56		(121)		3		1,101
Nine Months Ended September 30, 2021
Operating revenues	$	12,813	$	1,610	$	(372)	$	14,051	$	2,994	$	412	$	(111)	$	17,346
Segment net income (loss)(a)(b)(c)(d)(e)(f)	2,352		211		—		2,563		389		(338)		(6)		2,608
At September 30, 2021
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	263	$	—	$	5,280
Assets held for sale	3		—		—		3		—		48		—		51
Total assets	89,057		13,611		(708)		101,960		22,958		3,704		(761)		127,861
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)(c)(f)(g)	2,571		212		—		2,783		360		(420)		9		2,732
At December 31, 2020
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	263	$	—	$	5,280
Assets held for sale	5		—		—		5		—		55		—		60
Total assets	85,486		13,235		(680)		98,041		22,630		3,168		(904)		122,935

(a)Attributable to Southern Company.

(b)For Southern Company Gas, includes a preliminary pre-tax gain of $121 million ($93 million after tax) related to its sale of Sequent, as well as the resulting $85 million of additional tax expense due to changes in state apportionment rates. See Note (K) under "Southern Company Gas" for additional information.

(c)For the traditional electric operating companies, includes pre-tax charges at Georgia Power for estimated losses associated with the construction of Plant Vogtle Units 3 and 4 of $264 million ($197 million after tax) and $772 million ($576 million after tax) for the three and nine months ended September 30, 2021, respectively, and $149 million ($111 million after tax) for the nine months ended September 30, 2020. 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.

(d)For Southern Power, includes gains on wind turbine equipment contributed to various equity method investments totaling approximately $37 million pre-tax ($28 million after tax). See Notes (E) and (K) under "Southern Power" for additional information.

(e)For Southern Company Gas, includes pre-tax impairment charges totaling $84 million ($67 million after tax) related to its equity method investment in the PennEast Pipeline project. See Notes (C) and (E) under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, for additional information.

(f)For the "All Other" column, includes pre-tax impairment charges related to leveraged lease investments of $7 million ($6 million after tax) and $154 million ($74 million after tax) for the nine months ended September 30, 2021 and 2020, respectively. See Note 3 to the financial statements in Item 8 of the Form 10-K under "Other Matters – Southern Company" for additional information.

(g)For Southern Power, includes a $39 million pre-tax gain ($23 million gain after tax) on the sale of Plant Mankato. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power" for additional information.

Business segment financial data for the three and nine months ended September 30, 2021 and 2020 was as follows:

	Gas Distribution Operations		Gas Pipeline Investments		Wholesale Gas Services(a)		Gas Marketing Services		Total		All Other		Eliminations		Consolidated
	(in millions)
Three Months Ended September 30, 2021
Operating revenues	$	556	$	8	$	—	$	52	$	616	$	11	$	(4)	$	623
Segment net income (loss)(b)(c)	45		10		94		(2)		147		(91)		—		56
Nine Months Ended September 30, 2021
Operating revenues	$	2,466	$	24	$	188	$	311	$	2,989	$	29	$	(24)	$	2,994
Segment net income (loss)(b)(c)(d)	308		3		108		60		479		(90)		—		389
Total assets at September 30, 2021	20,619		1,478		132		1,534		23,763		11,387		(12,192)		22,958
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 December 31, 2020	19,090		1,597		850		1,503		23,040		11,336		(11,746)		22,630

(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, 2021	$	—	$	—	$	—	$	—	$	—
Three Months Ended September 30, 2020	1,050		33		1,083		1,134		(51)
Nine Months Ended September 30, 2021	$	3,881	$	90	$	3,971	$	3,783	$	188
Nine Months Ended September 30, 2020	3,089		81		3,170		3,189		(19)

(b)For wholesale gas services, includes a preliminary pre-tax gain of $121 million ($93 million after tax) related to the sale of Sequent. See Note (K) under "Southern Company Gas" for additional information.

(c)For the "All Other" column, includes $85 million of additional tax expense due to changes in state apportionment rates as a result of the sale of Sequent. See Note (K) under "Southern Company Gas" for additional information.

(d)For gas pipeline investments, includes pre-tax impairment charges totaling $84 million ($67 million after tax) related to the equity method investment in the PennEast Pipeline project. See Notes (C) and (E) under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, for additional information.

Schedule of Financial Data for Products and Services

	Electric Utilities' Revenues
	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2021	$	4,551	$	731	$	245	$	5,527
Three Months Ended September 30, 2020	4,243		584		222		5,049
Nine Months Ended September 30, 2021	$	11,492	$	1,822	$	737	$	14,051
Nine Months Ended September 30, 2020	10,503		1,473		652		12,628

	Southern Company Gas' Revenues
	Gas Distribution Operations		Wholesale Gas Services(*)		Gas Marketing Services		Other		Total
	(in millions)
Three Months Ended September 30, 2021	$	553	$	—	$	52	$	18	$	623
Three Months Ended September 30, 2020	476		(51)		39		13		477
Nine Months Ended September 30, 2021	$	2,451	$	188	$	311	$	44	$	2,994
Nine Months Ended September 30, 2020	2,072		(19)		272		37		2,362

(*)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. Also see Note (K) under "Southern Company Gas" regarding the July 1, 2021 sale of Sequent.

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Introduction - Schedule of Goodwill (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
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 - Schedule of Other Intangible Assets (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Other intangible assets subject to amortization:
Gross Carrying Amount	$ 676	$ 740
Accumulated Amortization	(296)	(328)
Other Intangible Assets, Net	380	412
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75	75
Total other intangible assets
Gross Carrying Amount	751	815
Accumulated Amortization	(296)	(328)
Other Intangible Assets, Net	455	487
Customer relationships
Other intangible assets subject to amortization:
Gross Carrying Amount	212	212
Accumulated Amortization	(148)	(135)
Other Intangible Assets, Net	64	77
Total other intangible assets
Accumulated Amortization	(148)	(135)
Trade names
Other intangible assets subject to amortization:
Gross Carrying Amount	64	64
Accumulated Amortization	(36)	(31)
Other Intangible Assets, Net	28	33
Total other intangible assets
Accumulated Amortization	(36)	(31)
Storage and transportation contracts
Other intangible assets subject to amortization:
Gross Carrying Amount	0	64
Accumulated Amortization	0	(64)
Other Intangible Assets, Net	0	0
Total other intangible assets
Accumulated Amortization	0	(64)
PPA fair value adjustments
Other intangible assets subject to amortization:
Gross Carrying Amount	390	390
Accumulated Amortization	(104)	(89)
Other Intangible Assets, Net	286	301
Total other intangible assets
Accumulated Amortization	(104)	(89)
Other
Other intangible assets subject to amortization:
Gross Carrying Amount	10	10
Accumulated Amortization	(8)	(9)
Other Intangible Assets, Net	2	1
Total other intangible assets
Accumulated Amortization	(8)	(9)
SOUTHERN POWER CO
Other intangible assets subject to amortization:
Accumulated Amortization	(104)	(89)
Total other intangible assets
Accumulated Amortization	(104)	(89)
SOUTHERN POWER CO | PPA fair value adjustments
Other intangible assets subject to amortization:
Gross Carrying Amount	390	390
Accumulated Amortization	(104)	(89)
Other Intangible Assets, Net	286	301
Total other intangible assets
Accumulated Amortization	(104)	(89)
SOUTHERN Co GAS
Other intangible assets subject to amortization:
Gross Carrying Amount	182	246
Accumulated Amortization	(142)	(195)
Other Intangible Assets, Net	40	51
Total other intangible assets
Accumulated Amortization	(142)	(195)
Other Intangible Assets, Net	40	51
SOUTHERN Co GAS | Customer relationships
Other intangible assets subject to amortization:
Gross Carrying Amount	156	156
Accumulated Amortization	(128)	(119)
Other Intangible Assets, Net	28	37
Total other intangible assets
Accumulated Amortization	(128)	(119)
SOUTHERN Co GAS | Trade names
Other intangible assets subject to amortization:
Gross Carrying Amount	26	26
Accumulated Amortization	(14)	(12)
Other Intangible Assets, Net	12	14
Total other intangible assets
Accumulated Amortization	(14)	(12)
SOUTHERN Co GAS | Storage and transportation contracts
Other intangible assets subject to amortization:
Gross Carrying Amount	0	64
Accumulated Amortization	0	(64)
Other Intangible Assets, Net	0	0
Total other intangible assets
Accumulated Amortization	$ 0	$ (64)

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Introduction - Schedule of Amortization of Other Intangible Assets (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2021
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 11	$ 33
Decrease in operating revenues	5	15
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	$ 4	$ 11

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Introduction - Schedule of Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020	Sep. 30, 2020	Dec. 31, 2019
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	$ 2,078	$ 1,065
Restricted cash:
Total cash, cash equivalents, and restricted cash	2,101	1,068	$ 3,383	$ 1,978
Other current assets
Restricted cash:
Restricted cash	3	2
Other deferred charges and assets
Restricted cash:
Restricted cash	21	0
SOUTHERN POWER CO
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	192	182
Restricted cash:
Total cash, cash equivalents, and restricted cash	213	183	417	279
SOUTHERN POWER CO | Other current assets
Restricted cash:
Restricted cash	0
SOUTHERN POWER CO | Other deferred charges and assets
Restricted cash:
Restricted cash	21
SOUTHERN Co GAS
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	29	17
Restricted cash:
Total cash, cash equivalents, and restricted cash	32	19	$ 161	$ 49
SOUTHERN Co GAS | Other current assets
Restricted cash:
Restricted cash	3	2
SOUTHERN Co GAS | Other deferred charges and assets
Restricted cash:
Restricted cash	$ 0	$ 0

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Introduction - Asset Retirement Obligations (Details) - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	Aug. 31, 2021	Sep. 30, 2021
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		$ 10,684
Liabilities incurred		17
Liabilities settled		(341)
Accretion		304
Cash flow revisions		945
Ending balance		11,609
ALABAMA POWER CO
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		3,974
Liabilities incurred		0
Liabilities settled		(152)
Accretion		116
Cash flow revisions	$ 385	385
Ending balance		4,323
GEORGIA POWER CO
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		6,265
Liabilities incurred		3
Liabilities settled		(154)
Accretion		176
Cash flow revisions	435	475
Ending balance		6,765
MISSISSIPPI POWER CO
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		176
Liabilities incurred		0
Liabilities settled		(18)
Accretion		6
Cash flow revisions	$ 30	30
Ending balance		$ 194

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Regulatory Matters - Schedule of Cost Recovery Clauses (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Loss Contingencies [Line Items]
Natural gas cost under recovery	$ 432	$ 0
ALABAMA POWER CO | Other regulatory liabilities, current
Loss Contingencies [Line Items]
Rate CNP Compliance	0	28
Retail Energy Cost Recovery	0	18
ALABAMA POWER CO | Other regulatory liabilities, deferred
Loss Contingencies [Line Items]
Rate CNP Compliance	24	0
Natural Disaster Reserve	36	77
ALABAMA POWER CO | Other regulatory assets, deferred
Loss Contingencies [Line Items]
Rate CNP PPA	88	58
Retail Energy Cost Recovery	6	0
ALABAMA POWER CO | Other regulatory assets, current
Loss Contingencies [Line Items]
Retail Energy Cost Recovery	79	0
GEORGIA POWER CO | Over recovered fuel clause revenues
Loss Contingencies [Line Items]
Fuel Cost Recovery	0	113
GEORGIA POWER CO | Other deferred charges and assets
Loss Contingencies [Line Items]
Fuel Cost Recovery	203	0
MISSISSIPPI POWER CO | Other regulatory liabilities, deferred
Loss Contingencies [Line Items]
Property Damage Reserve	0	4
MISSISSIPPI POWER CO | Other regulatory assets, deferred
Loss Contingencies [Line Items]
Ad Valorem Tax	39	41
Property Damage Reserve	16	0
MISSISSIPPI POWER CO | Other regulatory assets, current
Loss Contingencies [Line Items]
Ad Valorem Tax	12	11
MISSISSIPPI POWER CO | Over recovered regulatory clause liabilities
Loss Contingencies [Line Items]
Fuel Cost Recovery	5	24
SOUTHERN Co GAS
Loss Contingencies [Line Items]
Natural gas cost under recovery	432	0
SOUTHERN Co GAS | Other regulatory liabilities
Loss Contingencies [Line Items]
Natural gas cost under recovery	0	88
SOUTHERN Co GAS | Other regulatory assets, deferred
Loss Contingencies [Line Items]
Natural gas cost under recovery	79	0
SOUTHERN Co GAS | Other regulatory assets, current
Loss Contingencies [Line Items]
Natural gas cost under recovery	$ 432	$ 0

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Regulatory Matters - APC (Details)	3 Months Ended	9 Months Ended
	Dec. 31, 2021 USD ($)	Sep. 30, 2022 USD ($)	Sep. 30, 2021 USD ($)	Sep. 23, 2021 MW	Apr. 15, 2021	Dec. 31, 2020 USD ($)
Public Utilities, General Disclosures [Line Items]
Construction work in progress			$ 9,611,000,000			$ 8,697,000,000
ALABAMA POWER CO
Public Utilities, General Disclosures [Line Items]
Construction work in progress			1,129,000,000			866,000,000
Minimum natural disaster reserve balance, triggering establishment charge			50,000,000
Natural disaster reserve authorized limit			75,000,000
Natural disaster reserve balance			36,000,000
Natural disaster reserve, expected annual recovery until reserve is restored			16,000,000
ALABAMA POWER CO | Calhoun Power Company, LLC
Public Utilities, General Disclosures [Line Items]
Approximate nameplate capacity (in MWs) | MW				743
ALABAMA POWER CO | Scenario, Forecast | Subsequent Event
Public Utilities, General Disclosures [Line Items]
Natural disaster reserve, expected recovery amount	$ 4,000,000
ALABAMA POWER CO | Scenario, Forecast | Calhoun Power Company, LLC
Public Utilities, General Disclosures [Line Items]
Purchase price		$ 180,000,000
ALABAMA POWER CO | Plant Barry Unit 8
Public Utilities, General Disclosures [Line Items]
Construction work in progress			222,000,000
MISSISSIPPI POWER CO
Public Utilities, General Disclosures [Line Items]
Construction work in progress			$ 117,000,000			$ 146,000,000
MISSISSIPPI POWER CO | Plant Greene County Units 1 and 2 | ALABAMA POWER CO
Public Utilities, General Disclosures [Line Items]
Proportionate ownership share					40.00%

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Regulatory Matters - GPC Rate Plan (Details) - GEORGIA POWER CO - USD ($) $ in Millions	Oct. 12, 2021	Oct. 01, 2021	Jan. 01, 2021
Subsequent Event
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease) amount	$ 252
Traditional Base | Subsequent Event
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease) amount		$ 192
Environmental Compliance Cost Recovery | Subsequent Event
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease) amount		(12)
Demand-Side Management | Subsequent Event
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease) amount		(25)
Municipal Franchise Fee | Subsequent Event
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease) amount		$ 2
Plant Vogtle Units 3 And 4
Public Utilities, General Disclosures [Line Items]
Approved reduction in amortization of CCR ARO costs			$ 90

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Regulatory Matters - GPC Plant Vogtle Units 3 and Common Facilities Rate Proceeding (Details) - GEORGIA POWER CO - USD ($) $ in Millions	Nov. 02, 2021	Oct. 12, 2021	Jun. 15, 2021
Subsequent Event
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease) amount		$ 252
Plant Vogtle Unit 3
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease) amount			$ 2,380
Requested rate increase, annual amount			$ 302
Plant Vogtle Unit 3 | Subsequent Event
Public Utilities, General Disclosures [Line Items]
Approved rate increase (decrease)	$ 2,100
Approved depreciation expense deferred, annual amount	$ 38

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Regulatory Matters - GPC Deferral of Incremental COVID-19 Costs (Details) - GEORGIA POWER CO $ in Millions	4 Months Ended
	Sep. 30, 2021 USD ($)
Public Utilities, General Disclosures [Line Items]
Decrease in incremental COVID-19 costs deferred	$ 23
Incremental COVID-19 costs deferred	20
Incremental COVID-19 costs deferred, bad debt costs	1
Incremental COVID-19 costs deferred, other	$ 19

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Regulatory Matters - GPC Fuel Cost Recovery (Details) - GEORGIA POWER CO - Subsequent Event $ in Millions	Oct. 12, 2021 USD ($)
Public Utilities, General Disclosures [Line Items]
Requested revenues increase (decrease) percentage	15.00%
Requested rate increase (decrease) amount	$ 252

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Regulatory Matters - GPC Nuclear Construction (Details) $ in Millions	3 Months Ended				9 Months Ended		12 Months Ended
	Sep. 30, 2021 USD ($)	Jun. 30, 2021 USD ($)	Mar. 31, 2021 USD ($)	Sep. 30, 2020 USD ($)	Sep. 30, 2021 USD ($)	Sep. 30, 2020 USD ($)	Dec. 31, 2012 utility MW	Aug. 31, 2018
Loss Contingencies [Line Items]
Estimated loss on Plant Vogtle Units 3 and 4	$ 264			$ 0	$ 772	$ 149
GEORGIA POWER CO
Loss Contingencies [Line Items]
Estimated loss on Plant Vogtle Units 3 and 4	264	$ 460	$ 48	$ 0	772	149
Estimated loss on Plant Vogtle Units 3 and 4, net of tax	$ 197	343	36		$ 576	$ 111
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
Estimated cost to complete, construction contingency estimate, financing costs	$ 3,200				$ 3,200
Estimated cost to complete, construction contingency estimate, financing costs, incurred to date	2,800				2,800
Construction contingency estimate	127	341	84		127
Construction contingency estimate, additional amount	137	$ 119	$ 48		137
Base project capital cost forecast, monthly					25
Monthly AFUDC					$ 15
Percentage of ownership interest required for voting for continuing construction								90.00%
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
Minimum | GEORGIA POWER CO | Plant Vogtle Units 3 And 4 | COVID-19
Loss Contingencies [Line Items]
Loss contingency, estimate of possible loss, loss of productivity, term					3 months
Estimate of possible loss	160				$ 160
Maximum | GEORGIA POWER CO | Plant Vogtle Units 3 And 4 | COVID-19
Loss Contingencies [Line Items]
Loss contingency, estimate of possible loss, loss of productivity, term					4 months
Estimate of possible loss	$ 200				$ 200

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Regulatory Matters - GPC Nuclear Construction Cost and Schedule (Details) - GEORGIA POWER CO - Plant Vogtle Units 3 And 4 $ in Millions	9 Months Ended
	Sep. 30, 2021 USD ($)
Loss Contingencies [Line Items]
Base project capital cost forecast	$ 9,342
Construction contingency estimate	137
Total project capital cost forecast	9,479
Net investment as of end of the period	(8,159)
Remaining estimate to complete	1,320
Estimated cost to complete, costs not shared with other owners	570
Expected capitalized costs	318
Capitalized interest accrued	169
Twenty Fourth Vogtle Construction Monitoring Report
Loss Contingencies [Line Items]
Guarantor obligations	1,700
Customer refund	$ 188

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Regulatory Matters - GPC Amendments to the Vogtle Joint Ownership Agreements (Details) - Plant Vogtle Units 3 And 4 - Georgia Power - USD ($) $ in Millions		9 Months Ended
	Jan. 11, 2018	Sep. 30, 2021	Aug. 31, 2018
Public Utilities, General Disclosures [Line Items]
Production tax credits, aggregate purchase price, maximum		$ 300
Preliminary estimated cost to complete		9,479
Additional construction capital costs	$ 3,300	$ 350
Remaining share of construction costs, agreement to pay, percentage		100.00%
Percentage of ownership interest required for voting for continuing construction			90.00%
Percentage of costs, disallowed for recovery		6.00%
Costs disallowed for recovery, period		6 months
Public utilities, extension project schedule, term		1 year
Estimated cost to complete, starting dollar amount		$ 18,380
Category I
Public Utilities, General Disclosures [Line Items]
Preliminary estimated cost to complete		8,400
Additional construction capital costs, threshold		$ 800
Category II
Public Utilities, General Disclosures [Line Items]
Percentage of construction costs, responsibility to pay		55.70%
Additional construction capital costs		$ 80
Category II | Vogtle Owners
Public Utilities, General Disclosures [Line Items]
Percentage of construction costs, responsibility to pay		44.30%
Category II | Minimum
Public Utilities, General Disclosures [Line Items]
Additional construction capital costs, threshold		$ 800
Category II | Maximum
Public Utilities, General Disclosures [Line Items]
Additional construction capital costs, threshold		$ 1,600
Category III
Public Utilities, General Disclosures [Line Items]
Percentage of construction costs, responsibility to pay		65.70%
Additional construction capital costs		$ 100
Category III | Vogtle Owners
Public Utilities, General Disclosures [Line Items]
Percentage of construction costs, responsibility to pay		34.30%
Category III | Minimum
Public Utilities, General Disclosures [Line Items]
Additional construction capital costs, threshold		$ 1,600
Category III | Maximum
Public Utilities, General Disclosures [Line Items]
Additional construction capital costs, threshold		$ 2,100

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Regulatory Matters - GPC Nuclear Construction Regulatory Matters (Details) - Plant Vogtle Units 3 And 4 - Georgia Power $ in Millions						6 Months Ended	9 Months Ended	12 Months Ended
	Oct. 01, 2021 USD ($)	Jan. 01, 2021	Jan. 01, 2020	Jan. 11, 2018 USD ($)	Jan. 01, 2016	Jun. 30, 2020 USD ($)	Sep. 30, 2021 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($) report	Dec. 31, 2009 USD ($)	Jun. 30, 2018 USD ($)	Dec. 31, 2013
Public Utilities, General Disclosures [Line Items]
Estimated in-service capital cost												$ 4,418
Financing costs collected, net of tax							$ 2,700
Additional construction capital costs				$ 3,300			$ 350
Payments for contractor settlement agreement				300
Amendment to estimated in-service capital cost				$ 5,680
Retail rate of return on common equity														10.95%
Public utilities, approved return on equity percentage		5.30%	8.30%		10.00%
Public utilities, approved return on equity, monthly percentage decrease							0.10%
Return on equity reduction, negative impact on earnings											$ 150
Increase to base capital cost forecast not seeking recovery													$ 700
Subsequent Event
Public Utilities, General Disclosures [Line Items]
Requested decrease in tariff	$ 78
Twenty Fourth Vogtle Construction Monitoring Report
Public Utilities, General Disclosures [Line Items]
Number of approved construction management reports | report											24
Requested capital construction costs						$ 9,200					$ 7,300
Guarantor obligations							$ 1,700
Customer refund							188
Twenty Fifth Vogtle Construction Monitoring Report
Public Utilities, General Disclosures [Line Items]
Cost settlement agreement revised forecast, net of payments							$ 7,300
Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Return on equity reduction, negative impact on earnings								$ 135	$ 260	$ 270

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Regulatory Matters - MPC (Details) - MISSISSIPPI POWER CO $ in Millions	Oct. 25, 2021 USD ($)	Jun. 08, 2021 USD ($)	Apr. 06, 2021 USD ($)	Sep. 30, 2021 USD ($)	Apr. 15, 2021 MW	Dec. 31, 2020 MW
Loss Contingencies [Line Items]
Approved rate increase (decrease)		$ 16	$ 28
Approved rate increase, percentage		1.80%
Required fossil-stream generation retirements (in MWs) | MW						950
Public utilities, valorem taxes previously recovered, amount			$ 19
Hurricanes Zeta and Ida Accounting Order
Loss Contingencies [Line Items]
Retail costs to be reclassified to a regulatory asset due to accounting order				$ 49
Subsequent Event
Loss Contingencies [Line Items]
Requested rate increase (decrease) amount	$ 9
Environmental Compliance Overview Plan
Loss Contingencies [Line Items]
Approved rate increase (decrease)		$ 9
Plant Watson Unit 4
Loss Contingencies [Line Items]
Required fossil-stream generation retirements (in MWs) | MW					268
Plant Greene County Units 1 and 2
Loss Contingencies [Line Items]
Required fossil-stream generation retirements (in MWs) | MW					103
Plant Greene County Units 1 and 2 | ALABAMA POWER CO
Loss Contingencies [Line Items]
Proportionate ownership share					40.00%
Plant Daniel Units 1 and 2
Loss Contingencies [Line Items]
Required fossil-stream generation retirements (in MWs) | MW					502
Proportionate ownership share					50.00%
Remaining net book value				520
Estimated amount remaining at retirement				$ 390

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Regulatory Matters - GAS Schedule of Infrastructure Replacement Programs and Capital Projects (Details) - SOUTHERN Co GAS $ in Millions	9 Months Ended
	Sep. 30, 2021 USD ($)
Public Utilities, General Disclosures [Line Items]
Capital expenditures	$ 343
Investing in Illinois
Public Utilities, General Disclosures [Line Items]
Capital expenditures	307
Steps to Advance Virginia's Energy
Public Utilities, General Disclosures [Line Items]
Capital expenditures	$ 36

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Regulatory Matters - GAS Narrative (Details) $ in Millions	Oct. 14, 2021 USD ($)	Sep. 14, 2021 USD ($)	Jul. 21, 2021 USD ($)	Apr. 28, 2021 USD ($)	Nov. 01, 2020 USD ($)	Apr. 06, 2021 mi
Atlanta Gas Light
Loss Contingencies [Line Items]
Integrated capacity delivery plan, capital budgets and related operations and maintenance spending, term				10 years
Approved rate increase (decrease)			$ 49
Atlanta Gas Light | Minimum
Loss Contingencies [Line Items]
Integrated capacity delivery plan, capital forecast plan, amount, years one through ten				$ 500
Atlanta Gas Light | Maximum
Loss Contingencies [Line Items]
Integrated capacity delivery plan, capital forecast plan, amount, years one through ten				$ 600
Atlanta Gas Light | Subsequent Event
Loss Contingencies [Line Items]
Requested revenues increase (decrease) percentage	(10.00%)
Requested rate increase (decrease) amount	$ 5
Integrated capacity delivery plan, capital forecast plan, amount, years one through three	$ 1,700
Virginia Natural Gas
Loss Contingencies [Line Items]
Requested rate increase (decrease) amount					$ 50
Motion filed to withdraw project application, header improvement project, scope of project (in miles) | mi						9.5
Approved rate increase (decrease)		$ 43
Public utilities, approved rate increase amount recovery of investments		$ 14
Public utilities, approved return on equity percentage		9.50%
Public utilities, approved equity capital structure percentage		51.90%

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Contingencies - General Litigation Matters (Details) - Pending Litigation $ in Millions		1 Months Ended	12 Months Ended
	Oct. 08, 2021 claim	Mar. 31, 2019 plaintiff	Dec. 31, 2018 USD ($) plaintiff defendant	Dec. 31, 2017 claim
Shareholder Derivative Lawsuits
Loss Contingencies [Line Items]
Pending number of claims				2
Stay period			30 days
GEORGIA POWER CO | Subsequent Event
Loss Contingencies [Line Items]
Complaints filed	3
MISSISSIPPI POWER CO | 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

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Contingencies - Environmental Remediation (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
GEORGIA POWER CO
Loss Contingencies [Line Items]
Environmental remediation liability, current and former sites	$ 19	$ 15
SOUTHERN Co GAS
Loss Contingencies [Line Items]
Environmental remediation liability, current and former sites	$ 255	$ 245

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Contingencies - Other Matters (Details) $ in Millions	3 Months Ended			6 Months Ended		9 Months Ended
	Sep. 30, 2021 USD ($)	Jun. 30, 2021 USD ($)	Sep. 30, 2020 USD ($)	Sep. 30, 2021 USD ($)	Jun. 30, 2021 USD ($)	Sep. 30, 2021 USD ($)	Sep. 30, 2020 USD ($)	Jan. 30, 2020 mi
Loss Contingencies [Line Items]
Tax expense	$ 372		$ 293			$ 550	$ 443
SOUTHERN Co GAS
Loss Contingencies [Line Items]
Asset impairment charges						84	0
Tax expense	133		$ 3			224	$ 98
SOUTHERN Co GAS | PennEast Pipeline
Loss Contingencies [Line Items]
Construction amendment, number of miles of pipe, phase one | mi								68
Construction amendment, number of miles of pipe, phase two | mi								50
Asset impairment charges	2			$ 84	$ 82	84
Asset impairment charges, net of tax	$ 2	$ 67		$ 67	$ 58
Tax expense						$ 7
Ownership percentage, equity method investment	20.00%			20.00%		20.00%
SOUTHERN Co GAS | SNG
Loss Contingencies [Line Items]
Ownership percentage, equity method investment	50.00%			50.00%		50.00%
Commitment to fund contingent capital contribution	$ 150			$ 150		$ 150
SNG
Loss Contingencies [Line Items]
Debt maturing in June 2021	$ 300			$ 300		$ 300

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Revenue from Contracts with Customers and Lease Income - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	$ 5,732	$ 5,755	$ 18,066	$ 15,771
Total operating revenues	6,238	5,620	17,346	15,258
Retail electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	4,332	4,178	11,006	10,540
Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,974	2,019	4,910	4,802
Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,432	1,354	3,727	3,589
Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	902	783	2,299	2,081
Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	24	22	70	68
Natural gas distribution revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	549	474	2,432	2,058
Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	218	170	1,143	906
Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	55	41	298	229
Transportation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	239	224	775	723
Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	6	4	29	21
Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	31	35	187	179
Wholesale electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	547	409	1,338	1,048
PPA energy revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	359	214	782	550
PPA capacity revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	125	136	375	339
Non-PPA revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	63	59	181	159
Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	56	476	2,498	1,448
Wholesale gas services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		431	2,168	1,168
Gas marketing services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	45	38	303	258
Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	11	7	27	22
Other revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	248	218	792	677
Other revenue sources
Disaggregation of Revenue [Line Items]
Other revenues	506	968	2,979	2,604
Other adjustments
Disaggregation of Revenue [Line Items]
Other revenues		(1,103)	(3,699)	(3,117)
ALABAMA POWER CO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,801	1,671	4,708	4,285
Total operating revenues	1,904	1,729	5,019	4,445
ALABAMA POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,619	1,562	4,221	3,963
ALABAMA POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	750	752	1,931	1,839
ALABAMA POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	471	447	1,229	1,152
ALABAMA POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	394	358	1,048	956
ALABAMA POWER CO | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	4	5	13	16
ALABAMA POWER CO | Natural gas distribution revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
ALABAMA POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
ALABAMA POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
ALABAMA POWER CO | Transportation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
ALABAMA POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
ALABAMA POWER CO | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
ALABAMA POWER CO | Wholesale electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	129	76	337	205
ALABAMA POWER CO | PPA energy revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	61	40	143	94
ALABAMA POWER CO | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	14	26	86	78
ALABAMA POWER CO | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	54	10	108	33
ALABAMA POWER CO | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
ALABAMA POWER CO | Wholesale gas services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		0	0	0
ALABAMA POWER CO | Gas marketing services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
ALABAMA POWER CO | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
ALABAMA POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	53	33	150	117
ALABAMA POWER CO | Other revenue sources
Disaggregation of Revenue [Line Items]
Other revenues	103	58	311	160
ALABAMA POWER CO | Other adjustments
Disaggregation of Revenue [Line Items]
Other revenues		0	0	0
GEORGIA POWER CO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	2,636	2,529	6,631	6,359
Total operating revenues	2,856	2,617	7,050	6,371
GEORGIA POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	2,466	2,383	6,143	5,955
GEORGIA POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,138	1,183	2,765	2,760
GEORGIA POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	882	833	2,293	2,242
GEORGIA POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	428	352	1,034	907
GEORGIA POWER CO | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	18	15	51	46
GEORGIA POWER CO | Natural gas distribution revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
GEORGIA POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
GEORGIA POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
GEORGIA POWER CO | Transportation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
GEORGIA POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
GEORGIA POWER CO | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
GEORGIA POWER CO | Wholesale electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	58	31	126	75
GEORGIA POWER CO | PPA energy revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	41	13	71	38
GEORGIA POWER CO | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	14	15	41	30
GEORGIA POWER CO | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	3	3	14	7
GEORGIA POWER CO | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
GEORGIA POWER CO | Wholesale gas services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		0	0	0
GEORGIA POWER CO | Gas marketing services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
GEORGIA POWER CO | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
GEORGIA POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	112	115	362	329
GEORGIA POWER CO | Other revenue sources
Disaggregation of Revenue [Line Items]
Other revenues	220	88	419	12
GEORGIA POWER CO | Other adjustments
Disaggregation of Revenue [Line Items]
Other revenues		0	0	0
MISSISSIPPI POWER CO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	378	335	960	886
Total operating revenues	378	336	988	895
MISSISSIPPI POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	247	233	642	622
MISSISSIPPI POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	86	84	214	203
MISSISSIPPI POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	79	74	205	195
MISSISSIPPI POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	80	73	217	218
MISSISSIPPI POWER CO | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	2	2	6	6
MISSISSIPPI POWER CO | Natural gas distribution revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
MISSISSIPPI POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
MISSISSIPPI POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
MISSISSIPPI POWER CO | Transportation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
MISSISSIPPI POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
MISSISSIPPI POWER CO | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
MISSISSIPPI POWER CO | Wholesale electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	123	96	296	245
MISSISSIPPI POWER CO | PPA energy revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	2	2	9	7
MISSISSIPPI POWER CO | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1	1	4	3
MISSISSIPPI POWER CO | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	120	93	283	235
MISSISSIPPI POWER CO | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
MISSISSIPPI POWER CO | Wholesale gas services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		0	0	0
MISSISSIPPI POWER CO | Gas marketing services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
MISSISSIPPI POWER CO | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
MISSISSIPPI POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	8	6	22	19
MISSISSIPPI POWER CO | Other revenue sources
Disaggregation of Revenue [Line Items]
Other revenues	0	1	28	9
MISSISSIPPI POWER CO | Other adjustments
Disaggregation of Revenue [Line Items]
Other revenues		0	0	0
SOUTHERN POWER CO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	501	332	1,113	851
Total operating revenues	679	523	1,610	1,337
SOUTHERN POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN POWER CO | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN POWER CO | Natural gas distribution revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN POWER CO | Transportation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN POWER CO | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN POWER CO | Wholesale electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	492	328	1,095	840
SOUTHERN POWER CO | PPA energy revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	261	165	575	425
SOUTHERN POWER CO | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	97	95	247	231
SOUTHERN POWER CO | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	134	68	273	184
SOUTHERN POWER CO | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN POWER CO | Wholesale gas services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		0	0	0
SOUTHERN POWER CO | Gas marketing services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN POWER CO | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	9	4	18	11
SOUTHERN POWER CO | Other revenue sources
Disaggregation of Revenue [Line Items]
Other revenues	178	191	497	486
SOUTHERN POWER CO | Other adjustments
Disaggregation of Revenue [Line Items]
Other revenues		0	0	0
SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	605	950	4,930	3,506
Total operating revenues	623	477	2,994	2,362
SOUTHERN Co GAS | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN Co GAS | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN Co GAS | Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN Co GAS | Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN Co GAS | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN Co GAS | Natural gas distribution revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	549	474	2,432	2,058
SOUTHERN Co GAS | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	218	170	1,143	906
SOUTHERN Co GAS | Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	55	41	298	229
SOUTHERN Co GAS | Transportation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	239	224	775	723
SOUTHERN Co GAS | Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	6	4	29	21
SOUTHERN Co GAS | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	31	35	187	179
SOUTHERN Co GAS | Wholesale electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN Co GAS | PPA energy revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN Co GAS | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN Co GAS | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN Co GAS | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	56	476	2,498	1,448
SOUTHERN Co GAS | Wholesale gas services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers		431	2,168	1,168
SOUTHERN Co GAS | Gas marketing services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	45	38	303	258
SOUTHERN Co GAS | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	11	7	27	22
SOUTHERN Co GAS | Other revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0	0
SOUTHERN Co GAS | Other revenue sources
Disaggregation of Revenue [Line Items]
Other revenues	$ 18	630	1,763	1,973
SOUTHERN Co GAS | Other adjustments
Disaggregation of Revenue [Line Items]
Other revenues		$ (1,103)	$ (3,699)	$ (3,117)

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Revenue from Contracts with Customers and Lease Income - Schedule of Contract Balances (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Disaggregation of Revenue [Line Items]
Accounts Receivable	$ 2,343	$ 2,614
Contract Assets	165	158
Contract Liabilities	65	61
ALABAMA POWER CO
Disaggregation of Revenue [Line Items]
Accounts Receivable	712	632
Contract Assets	5	2
Contract Liabilities	6	6
GEORGIA POWER CO
Disaggregation of Revenue [Line Items]
Accounts Receivable	904	806
Contract Assets	103	71
Contract Liabilities	39	27
MISSISSIPPI POWER CO
Disaggregation of Revenue [Line Items]
Accounts Receivable	90	77
Contract Assets	0	0
Contract Liabilities	1	1
SOUTHERN POWER CO
Disaggregation of Revenue [Line Items]
Accounts Receivable	170	112
Contract Assets	1	0
Contract Liabilities	2	1
SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Accounts Receivable	329	788
Contract Assets	0	0
Contract Liabilities	$ 0	$ 1

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Revenue from Contracts with Customers and Lease Income - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Disaggregation of Revenue [Line Items]
Contract assets	$ 165		$ 165		$ 158
Contract liabilities	65		65		61
Revenue from contracts with customers recognized	5		25
Unregulated Distributed Generation
Disaggregation of Revenue [Line Items]
Contract assets	55		55		81
Contract liabilities	19		19		27
MISSISSIPPI POWER CO
Disaggregation of Revenue [Line Items]
Contract assets	0		0		0
Contract liabilities	1		1		1
Sales-type lease, lease receivable	39		39
Transfer of construction work in progress to lease receivables	39
SOUTHERN POWER CO
Disaggregation of Revenue [Line Items]
Contract assets	1		1		0
Contract liabilities	2		2		1
Sales-type lease, lease receivable	113		113
Transfer of construction work in progress to lease receivables	113
Loss on sales-type lease	$ 15	$ 0	$ 15	$ 0
Lessor, lease term, sales-type lease	20 years		20 years
Net investment in sales-type lease, current portion	$ 8		$ 8
Net investment in sales-type lease, long-term portion	$ 91		$ 91		$ 0

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Revenue from Contracts with Customers and Lease Income - Schedule of Remaining Performance Obligations (Details) $ in Millions	Sep. 30, 2021 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 156
Performance obligation, expected timing of satisfaction	3 months
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	$ 543
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	$ 347
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	$ 327
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	$ 307
Performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 2,667
Performance obligation, expected timing of satisfaction
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 13
Performance obligation, expected timing of satisfaction	3 months
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	$ 32
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	1 year
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 0
Performance obligation, expected timing of satisfaction
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 22
Performance obligation, expected timing of satisfaction	3 months
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	$ 64
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	$ 43
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	$ 23
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	$ 21
Performance obligation, expected timing of satisfaction	1 year
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 41
Performance obligation, expected timing of satisfaction
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 70
Performance obligation, expected timing of satisfaction	3 months
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	$ 323
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	$ 281
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	$ 297
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	$ 281
Performance obligation, expected timing of satisfaction	1 year
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 2,644
Performance obligation, expected timing of satisfaction

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Revenue from Contracts with Customers and Lease Income - Schedule of Lease Income (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	$ 4	$ 3	$ 11	$ 8
Lease income - operating leases	56	50	168	148
Variable lease income	143	145	355	345
Total lease income	203	198	534	501
ALABAMA POWER CO
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	0	0	0	0
Lease income - operating leases	21	11	62	24
Variable lease income	0	0	0	0
Total lease income	21	11	62	24
GEORGIA POWER CO
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	0	0	0	0
Lease income - operating leases	11	14	31	44
Variable lease income	0	0	0	0
Total lease income	11	14	31	44
MISSISSIPPI POWER CO
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	4	3	10	8
Lease income - operating leases	0	0	1	1
Variable lease income	0	0	0	0
Total lease income	4	3	11	9
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	21	64	66
Variable lease income	151	153	379	368
Total lease income	172	174	443	434
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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Revenue from Contracts with Customers and Lease Income - Undiscounted Cash Flows to be Received Under Tolling Arrangements Accounted for as Sales-type Leases (Details) $ in Millions	Sep. 30, 2021 USD ($)
Sales-type and Direct Financing Leases, Lease Receivable, Fiscal Year Maturity [Abstract]
2021 (remaining)	$ 2
SOUTHERN POWER CO
Sales-type and Direct Financing Leases, Lease Receivable, Fiscal Year Maturity [Abstract]
2022	8
2023	8
2024	8
2025	8
2026	8
Thereafter	115
Total undiscounted cash flows	157
Net investment in sales-type lease	99
Difference between undiscounted cash flows and discounted cash flows	$ 58

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Consolidated Entities and Equity Method Investments - Narrative (Details) $ in Millions	9 Months Ended
	Sep. 30, 2021 USD ($) investor	Dec. 31, 2020 USD ($)
Schedule of Equity Method Investments [Line Items]
Assets	$ 127,861	$ 122,935
Liabilities	94,351	90,410
Equity investments in unconsolidated subsidiaries	1,278	1,362
SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Assets	13,611	13,235
Liabilities	6,904	6,604
Equity investments in unconsolidated subsidiaries	$ 83	19
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	$ 6,200	6,100
Liabilities	364	387
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	2,300	2,400
Liabilities	157	138
Noncontrolling interests related to other partners' interests	$ 42	43
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	$ 1,900	1,100
Liabilities	263	110
Noncontrolling interests related to other partners' interests	$ 902	$ 454

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Consolidated Entities and Equity Method Investments - Schedule of Equity Method Investments (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2021	Jun. 30, 2021	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Schedule of Equity Method Investments [Line Items]
Investment Balance	$ 1,278	$ 1,278		$ 1,278		$ 1,362
SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Investment Balance	1,174	1,174		1,174		1,290
Asset impairment charges				84	$ 0
SOUTHERN Co GAS | SNG
Schedule of Equity Method Investments [Line Items]
Investment Balance	1,130	1,130		1,130		1,167
SOUTHERN Co GAS | PennEast Pipeline
Schedule of Equity Method Investments [Line Items]
Investment Balance	11	11		11		91
Asset impairment charges	2	84	$ 82	84
SOUTHERN Co GAS | Other
Schedule of Equity Method Investments [Line Items]
Investment Balance	$ 33	$ 33		$ 33		$ 32

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Consolidated Entities and Equity Method Investments - Schedule of Earnings (Loss) from Equity Method Investments (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended		9 Months Ended
	Sep. 30, 2021	Jun. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Jun. 30, 2021	Sep. 30, 2021	Sep. 30, 2020
Schedule of Equity Method Investments [Line Items]
Earnings (Loss) from Equity Method Investments	$ 30		$ 33			$ 35	$ 105
SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Earnings (Loss) from Equity Method Investments	25		33			14	106
Asset impairment charges						84	0
SOUTHERN Co GAS | SNG
Schedule of Equity Method Investments [Line Items]
Earnings (Loss) from Equity Method Investments	27		30			93	95
SOUTHERN Co GAS | PennEast Pipeline
Schedule of Equity Method Investments [Line Items]
Earnings (Loss) from Equity Method Investments	(2)		2			(81)	5
Asset impairment charges	2			$ 84	$ 82	84
Asset impairment charges, net of tax	2	$ 67		$ 67	$ 58
SOUTHERN Co GAS | Other
Schedule of Equity Method Investments [Line Items]
Earnings (Loss) from Equity Method Investments	$ 0		$ 1			$ 2	$ 6

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Financing - Schedule of Credit Arrangements (Details) - USD ($)	Sep. 30, 2021	Aug. 31, 2021	Jul. 31, 2021	May 31, 2021	Apr. 30, 2021
Line of Credit Facility [Line Items]
Expires, 2022	$ 280,000,000
Expires, 2023	125,000,000
Expires, 2024	700,000,000
Expires, 2026	6,550,000,000
Total	7,655,000,000
Unused	7,570,000,000
Due within One Year	280,000,000
Southern Company parent
Line of Credit Facility [Line Items]
Expires, 2022	0
Expires, 2023	0
Expires, 2024	0
Expires, 2026	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, 2022	0		$ 525,000,000
Expires, 2023	0
Expires, 2024	550,000,000	$ 550,000,000
Expires, 2026	700,000,000
Total	1,250,000,000			$ 700,000,000	$ 800,000,000
Unused	1,250,000,000
Due within One Year	0
GEORGIA POWER CO
Line of Credit Facility [Line Items]
Expires, 2022	0
Expires, 2023	0
Expires, 2024	0
Expires, 2026	1,750,000,000
Total	1,750,000,000
Unused	1,726,000,000
Due within One Year	0
MISSISSIPPI POWER CO
Line of Credit Facility [Line Items]
Expires, 2022	0
Expires, 2023	125,000,000
Expires, 2024	150,000,000
Expires, 2026	0
Total	275,000,000			150,000,000
Unused	250,000,000
Due within One Year	0
SOUTHERN POWER CO
Line of Credit Facility [Line Items]
Expires, 2022	0
Expires, 2023	0
Expires, 2024	0
Expires, 2026	600,000,000
Total	600,000,000
Unused	568,000,000
Due within One Year	0
SOUTHERN POWER CO | Continuing Letter of Credit Facility A
Line of Credit Facility [Line Items]
Expires, 2023	75,000,000
Unused	23,000,000
SOUTHERN POWER CO | Continuing Letter of Credit Facility B
Line of Credit Facility [Line Items]
Expires, 2023	60,000,000
Unused	1,000,000
SOUTHERN Co GAS
Line of Credit Facility [Line Items]
Expires, 2022	250,000,000
Expires, 2023	0
Expires, 2024	0
Expires, 2026	1,500,000,000
Total	1,750,000,000			$ 1,500,000,000	$ 1,750,000,000
Unused	1,747,000,000
Due within One Year	250,000,000
SEGCO
Line of Credit Facility [Line Items]
Expires, 2022	30,000,000
Expires, 2023	0
Expires, 2024	0
Expires, 2026	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	800,000,000
Nicor Gas
Line of Credit Facility [Line Items]
Total	$ 700,000,000

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Financing - Narrative (Details) - USD ($)	Sep. 30, 2021	Aug. 31, 2021	Jul. 31, 2021	May 31, 2021	Apr. 30, 2021
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 7,655,000,000
Line of credit expiring in 2022	280,000,000
Line of credit expiring in 2024	700,000,000
Variable rate pollution control revenue bonds outstanding	1,600,000,000
ALABAMA POWER CO
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	1,250,000,000			$ 700,000,000	$ 800,000,000
Line of credit expiring in 2022	0		$ 525,000,000
Line of credit expiring in 2024	550,000,000	$ 550,000,000
Variable rate pollution control revenue bonds outstanding	854,000,000
SOUTHERN Co GAS
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	1,750,000,000			1,500,000,000	$ 1,750,000,000
Line of credit expiring in 2022	250,000,000
Line of credit expiring in 2024	0
MISSISSIPPI POWER CO
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	275,000,000			$ 150,000,000
Line of credit expiring in 2022	0
Line of credit expiring in 2024	150,000,000
Variable rate pollution control revenue bonds outstanding	34,000,000
Fixed rate pollution control revenue bonds outstanding	50,000,000
GEORGIA POWER CO
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	1,750,000,000
Line of credit expiring in 2022	0
Line of credit expiring in 2024	0
Variable rate pollution control revenue bonds outstanding	672,000,000
Fixed rate pollution control revenue bonds outstanding	$ 262,000,000

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Financing - Schedule of Shares Used to Compute Diluted Earnings Per Share (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Debt Disclosure [Abstract]
As reported shares (in shares)	1,061	1,058	1,060	1,058
Effect of stock-based compensation (in shares)	7	6	7	6
Diluted shares (in shares)	1,068	1,064	1,067	1,064

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Income Taxes - Narrative (Details) - USD ($) $ in Billions	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Income Tax Contingency [Line Items]
Effective tax (benefit) rate	17.50%	13.90%
ITC and PTC carryforwards
Income Tax Contingency [Line Items]
Deferred tax assets	$ 1.2		$ 1.4
GEORGIA POWER CO
Income Tax Contingency [Line Items]
Effective tax (benefit) rate	7.30%	12.30%
SOUTHERN POWER CO
Income Tax Contingency [Line Items]
Effective tax (benefit) rate	(1.60%)	11.30%
SOUTHERN Co GAS
Income Tax Contingency [Line Items]
Effective tax (benefit) rate	36.60%	21.40%

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Income Taxes - Summary of Operating Loss Carryforwards Valuation Allowances (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Operating Loss Carryforwards [Line Items]
Valuation allowance	$ 142	$ 112
GEORGIA POWER CO
Operating Loss Carryforwards [Line Items]
Valuation allowance	58	28
Federal
Operating Loss Carryforwards [Line Items]
Valuation allowance	20	20
Federal | GEORGIA POWER CO
Operating Loss Carryforwards [Line Items]
Valuation allowance	0	0
State (net of federal benefit)
Operating Loss Carryforwards [Line Items]
Valuation allowance	122	92
State (net of federal benefit) | GEORGIA POWER CO
Operating Loss Carryforwards [Line Items]
Valuation allowance	$ 58	$ 28

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Retirement Benefits (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
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	109,000,000	$ 94,000,000	326,000,000	$ 282,000,000
Interest cost	87,000,000	108,000,000	260,000,000	324,000,000
Expected return on plan assets	(298,000,000)	(274,000,000)	(893,000,000)	(824,000,000)
Amortization:
Prior service costs	0	0	0	1,000,000
Regulatory asset	0	0	0	0
Net (gain)/loss	78,000,000	67,000,000	235,000,000	201,000,000
Net periodic pension cost (income)	(24,000,000)	(5,000,000)	(72,000,000)	(16,000,000)
Pension Plans | ALABAMA POWER CO
Pension Plans and Postretirement Plans
Service cost	26,000,000	23,000,000	77,000,000	67,000,000
Interest cost	20,000,000	25,000,000	61,000,000	75,000,000
Expected return on plan assets	(72,000,000)	(66,000,000)	(215,000,000)	(198,000,000)
Amortization:
Prior service costs	0	1,000,000	0	1,000,000
Regulatory asset	0	0	0	0
Net (gain)/loss	21,000,000	17,000,000	62,000,000	53,000,000
Net periodic pension cost (income)	(5,000,000)	0	(15,000,000)	(2,000,000)
Pension Plans | GEORGIA POWER CO
Pension Plans and Postretirement Plans
Service cost	28,000,000	24,000,000	84,000,000	72,000,000
Interest cost	26,000,000	33,000,000	78,000,000	100,000,000
Expected return on plan assets	(94,000,000)	(87,000,000)	(282,000,000)	(261,000,000)
Amortization:
Prior service costs	0	0	1,000,000	1,000,000
Regulatory asset	0	0	0	0
Net (gain)/loss	25,000,000	22,000,000	75,000,000	65,000,000
Net periodic pension cost (income)	(15,000,000)	(8,000,000)	(44,000,000)	(23,000,000)
Pension Plans | MISSISSIPPI POWER CO
Pension Plans and Postretirement Plans
Service cost	4,000,000	3,000,000	13,000,000	11,000,000
Interest cost	4,000,000	5,000,000	12,000,000	15,000,000
Expected return on plan assets	(14,000,000)	(13,000,000)	(41,000,000)	(38,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain)/loss	4,000,000	4,000,000	11,000,000	10,000,000
Net periodic pension cost (income)	(2,000,000)	(1,000,000)	(5,000,000)	(2,000,000)
Pension Plans | SOUTHERN POWER CO
Pension Plans and Postretirement Plans
Service cost	2,000,000	2,000,000	7,000,000	6,000,000
Interest cost	2,000,000	1,000,000	4,000,000	4,000,000
Expected return on plan assets	(4,000,000)	(4,000,000)	(11,000,000)	(10,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain)/loss	1,000,000	1,000,000	3,000,000	2,000,000
Net periodic pension cost (income)	1,000,000	0	3,000,000	2,000,000
Pension Plans | SOUTHERN Co GAS
Pension Plans and Postretirement Plans
Service cost	10,000,000	8,000,000	28,000,000	24,000,000
Interest cost	6,000,000	8,000,000	18,000,000	23,000,000
Expected return on plan assets	(21,000,000)	(20,000,000)	(64,000,000)	(59,000,000)
Amortization:
Prior service costs	(1,000,000)	(1,000,000)	(2,000,000)	(2,000,000)
Regulatory asset	3,000,000	4,000,000	11,000,000	12,000,000
Net (gain)/loss	3,000,000	2,000,000	9,000,000	7,000,000
Net periodic pension cost (income)	0	1,000,000	0	5,000,000
Postretirement Benefits
Pension Plans and Postretirement Plans
Service cost	6,000,000	6,000,000	18,000,000	17,000,000
Interest cost	9,000,000	13,000,000	26,000,000	40,000,000
Expected return on plan assets	(19,000,000)	(18,000,000)	(57,000,000)	(54,000,000)
Amortization:
Prior service costs		0	(1,000,000)	(1,000,000)
Regulatory asset	0	0	0	0
Net (gain)/loss	1,000,000	1,000,000	3,000,000	2,000,000
Net periodic pension cost (income)	(3,000,000)	2,000,000	(11,000,000)	4,000,000
Postretirement Benefits | ALABAMA POWER CO
Pension Plans and Postretirement Plans
Service cost	2,000,000	1,000,000	5,000,000	4,000,000
Interest cost	2,000,000	4,000,000	6,000,000	10,000,000
Expected return on plan assets	(8,000,000)	(7,000,000)	(22,000,000)	(21,000,000)
Amortization:
Prior service costs		0	0	0
Regulatory asset	0	0	0	0
Net (gain)/loss	0	0	0	0
Net periodic pension cost (income)	(4,000,000)	(2,000,000)	(11,000,000)	(7,000,000)
Postretirement Benefits | GEORGIA POWER CO
Pension Plans and Postretirement Plans
Service cost	2,000,000	2,000,000	5,000,000	5,000,000
Interest cost	3,000,000	5,000,000	9,000,000	15,000,000
Expected return on plan assets	(7,000,000)	(7,000,000)	(20,000,000)	(20,000,000)
Amortization:
Prior service costs		(1,000,000)	0	(1,000,000)
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)	(1,000,000)	0	(4,000,000)	1,000,000
Postretirement Benefits | MISSISSIPPI POWER CO
Pension Plans and Postretirement Plans
Service cost	1,000,000	(1,000,000)	1,000,000	0
Interest cost	0	1,000,000	1,000,000	2,000,000
Expected return on plan assets	(1,000,000)	0	(2,000,000)	(1,000,000)
Amortization:
Prior service costs		0	0	0
Regulatory asset	0	0	0	0
Net (gain)/loss	0	0	0	0
Net periodic pension cost (income)	0	0	0	1,000,000
Postretirement Benefits | SOUTHERN POWER CO
Pension Plans and Postretirement Plans
Service cost	1,000,000	1,000,000	1,000,000	1,000,000
Interest cost	0	0	0	0
Expected return on plan assets	0	0	0	0
Amortization:
Prior service costs		0	0	0
Regulatory asset	0	0	0	0
Net (gain)/loss	0	0	0	0
Net periodic pension cost (income)	1,000,000	1,000,000	1,000,000	1,000,000
Postretirement Benefits | SOUTHERN Co GAS
Pension Plans and Postretirement Plans
Service cost	0	0	1,000,000	1,000,000
Interest cost	1,000,000	2,000,000	3,000,000	5,000,000
Expected return on plan assets	(2,000,000)	(2,000,000)	(6,000,000)	(5,000,000)
Amortization:
Prior service costs		0	0	0
Regulatory asset	2,000,000	2,000,000	5,000,000	5,000,000
Net (gain)/loss	(1,000,000)	(1,000,000)	(2,000,000)	(2,000,000)
Net periodic pension cost (income)	$ 0	$ 1,000,000	$ 1,000,000	$ 4,000,000

XML

Fair Value Measurements - Schedule of Assets and Liabilities Measured at Fair Value (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Assets:
Derivatives	$ 489	$ 281
Liabilities:
Derivatives	66	64
Other	13
Collateral already posted, assets, aggregate fair value	(20)
Quoted Prices in Active Markets for Identical Assets (Level 1)
Liabilities:
Other	0
Significant Other Observable Inputs (Level 2)
Liabilities:
Other	13
Significant Unobservable Inputs (Level 3)
Liabilities:
Other	0
ALABAMA POWER CO
Assets:
Derivatives	106	5
Liabilities:
Derivatives	1	0
GEORGIA POWER CO
Assets:
Derivatives	163	3
Investments in trusts	57
Liabilities:
Derivatives	1	1
MISSISSIPPI POWER CO
Assets:
Derivatives	103	2
Liabilities:
Derivatives	1	2
SOUTHERN POWER CO
Assets:
Derivatives	29	89
Liabilities:
Derivatives	12	26
Other	13
SOUTHERN POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Liabilities:
Other	0
SOUTHERN POWER CO | Significant Other Observable Inputs (Level 2)
Liabilities:
Other	13
SOUTHERN POWER CO | Significant Unobservable Inputs (Level 3)
Liabilities:
Other	0
SOUTHERN Co GAS
Assets:
Derivatives	74	162
Liabilities:
Derivatives	7	35
Total
Collateral already posted, assets, aggregate fair value	(20)	$ 28
Fair Value, Measurements, Recurring
Assets:
Cash equivalents	1,507
Other investments	35
Total	4,562
Liabilities:
Contingent consideration	16
Total	132
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents	1,498
Other investments	9
Total	2,523
Liabilities:
Contingent consideration	0
Total	27
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents	9
Other investments	26
Total	1,916
Liabilities:
Contingent consideration	0
Total	89
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Cash equivalents	0
Other investments	0
Total	0
Liabilities:
Contingent consideration	16
Total	16
Fair Value, Measurements, Recurring | Net Asset Value as a Practical Expedient (NAV)
Assets:
Total	123
Fair Value, Measurements, Recurring | Energy-related derivatives
Assets:
Derivatives	500
Liabilities:
Derivatives	44
Fair Value, Measurements, Recurring | Energy-related derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	75
Liabilities:
Derivatives	27
Fair Value, Measurements, Recurring | Energy-related derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	425
Liabilities:
Derivatives	17
Fair Value, Measurements, Recurring | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | Interest rate derivatives
Assets:
Derivatives	25
Liabilities:
Derivatives	16
Fair Value, Measurements, Recurring | Interest rate derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | Interest rate derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	25
Liabilities:
Derivatives	16
Fair Value, Measurements, Recurring | Interest rate derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | Foreign currency derivatives
Assets:
Derivatives	20
Liabilities:
Derivatives	43
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	20
Liabilities:
Derivatives	43
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	975
Fair Value, Measurements, Recurring | Domestic equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	738
Fair Value, Measurements, Recurring | Domestic equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	237
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	350
Fair Value, Measurements, Recurring | Foreign equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	167
Fair Value, Measurements, Recurring | Foreign equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	183
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	352
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	352
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	48
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	48
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	14
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	14
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	474
Fair Value, Measurements, Recurring | Corporate bonds | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	2
Fair Value, Measurements, Recurring | Corporate bonds | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	472
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	92
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	92
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	123
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	123
Fair Value, Measurements, Recurring | Cash and cash equivalents
Assets:
Investments in trusts	5
Fair Value, Measurements, Recurring | Cash and cash equivalents | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	5
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	42
Fair Value, Measurements, Recurring | Other | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	29
Fair Value, Measurements, Recurring | Other | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	13
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	452
Other investments	26
Total	1,844
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents	443
Other investments	0
Total	1,062
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents	9
Other investments	26
Total	659
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	123
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Energy-related derivatives
Assets:
Derivatives	104
Liabilities:
Derivatives	4
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	104
Liabilities:
Derivatives	4
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 | Interest rate derivatives
Assets:
Derivatives	5
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Interest rate derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Interest rate derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	5
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Interest rate derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Domestic equity
Assets:
Investments in trusts	671
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Domestic equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	444
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Domestic equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	227
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	167
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Foreign equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	167
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Foreign equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	0
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	22
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	22
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	245
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Corporate bonds | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	2
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Corporate bonds | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	243
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	22
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	22
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	123
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	123
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	240
Total	1,593
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents	240
Total	557
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents	0
Total	1,036
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	166
Liabilities:
Derivatives	4
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	166
Liabilities:
Derivatives	4
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	295
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Domestic equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	294
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	180
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	180
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	330
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	330
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	47
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	47
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	229
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	229
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	70
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	70
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	36
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Other | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	23
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Other | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	13
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	121
Total	226
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents	121
Total	121
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents	0
Total	105
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	105
Liabilities:
Derivatives	3
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	105
Liabilities:
Derivatives	3
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:
Total	30
Liabilities:
Contingent consideration	16
Total	42
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Total	0
Liabilities:
Contingent consideration	0
Total	0
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Total	30
Liabilities:
Contingent consideration	0
Total	26
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Significant Unobservable Inputs (Level 3)
Assets:
Total	0
Liabilities:
Contingent consideration	16
Total	16
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Energy-related derivatives
Assets:
Derivatives	10
Liabilities:
Derivatives	2
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	10
Liabilities:
Derivatives	2
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	20
Liabilities:
Derivatives	11
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	20
Liabilities:
Derivatives	11
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:
Total	152
Liabilities:
Total	35
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Total	80
Liabilities:
Total	27
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2)
Assets:
Total	72
Liabilities:
Total	8
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3)
Assets:
Total	0
Liabilities:
Total	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Energy-related derivatives
Assets:
Derivatives	115
Liabilities:
Derivatives	31
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Energy-related derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	75
Liabilities:
Derivatives	27
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Energy-related derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	40
Liabilities:
Derivatives	4
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Interest rate derivatives
Assets:
Derivatives	6
Liabilities:
Derivatives	4
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Interest rate derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Interest rate derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	6
Liabilities:
Derivatives	4
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Interest rate derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Domestic equity
Assets:
Non-qualified deferred compensation trusts	9
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	9
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	14
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	14
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	5
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	5
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, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	$ 9	$ 108	$ 173	$ 85
ALABAMA POWER CO
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	15	66	133	24
GEORGIA POWER CO
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	$ (6)	$ 42	$ 40	$ 61

XML

Fair Value Measurements - Narrative (Details) - ALABAMA POWER CO - Private equity $ in Millions	Sep. 30, 2021 USD ($)
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair value	$ 123
Unfunded commitments	$ 72

XML

Fair Value Measurements - Schedule of Financial Instruments for which Carrying Amount did not Equal Fair Value (Details) $ in Millions	Sep. 30, 2021 USD ($)
Long-term debt, including securities due within one year:
Carrying amount	$ 51,900.0
Fair value	57,600.0
ALABAMA POWER CO
Long-term debt, including securities due within one year:
Carrying amount	9,100.0
Fair value	10,400.0
GEORGIA POWER CO
Long-term debt, including securities due within one year:
Carrying amount	13,600.0
Fair value	15,200.0
MISSISSIPPI POWER CO
Long-term debt, including securities due within one year:
Carrying amount	1,600.0
Fair value	1,700.0
SOUTHERN POWER CO
Long-term debt, including securities due within one year:
Carrying amount	4,000.0
Fair value	4,400.0
SOUTHERN Co GAS
Long-term debt, including securities due within one year:
Carrying amount	6,800.0
Fair value	$ 7,800.0

XML

Fair Value Measurements - Schedule of 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, 2021	Sep. 30, 2021
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	$ 18	$ 28
Instruments realized or otherwise settled during period	0	(6)
Changes in fair value	0	(4)
Sale of Sequent	(18)	(18)
Ending balance	$ 0	$ 0

XML

Derivatives - Schedule of Energy-Related Derivatives (Details) - Energy-related, Natural Gas MMBTU in Millions	Sep. 30, 2021 MMBTU
Energy-related derivative contracts
Net Purchased mmBtu	336.0
ALABAMA POWER CO
Energy-related derivative contracts
Net Purchased mmBtu	75.0
GEORGIA POWER CO
Energy-related derivative contracts
Net Purchased mmBtu	99.0
MISSISSIPPI POWER CO
Energy-related derivative contracts
Net Purchased mmBtu	79.0
SOUTHERN POWER CO
Energy-related derivative contracts
Net Purchased mmBtu	6.0
SOUTHERN Co GAS
Energy-related derivative contracts
Net Purchased mmBtu	77.0
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Long
Energy-related derivative contracts
Derivative nonmonetary notional amount net long short position volume	91.4
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Short
Energy-related derivative contracts
Derivative nonmonetary notional amount net long short position volume	14.3

XML

Derivatives - Narrative (Details) MMBTU in Millions	9 Months Ended
	Sep. 30, 2021 USD ($) MMBTU	Dec. 31, 2020 USD ($)
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	41
Cash flow hedge gain (loss) to be reclassified within twelve months | $	$ (22,000,000)
Collateral already posted, assets, aggregate fair value | $	$ (20,000,000)
ALABAMA POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	10
GEORGIA POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	13
MISSISSIPPI POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	5
SOUTHERN POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	13
Foreign currency cash flow hedge gain (loss) to be reclassified during next 12 months | $	$ (4,000,000)
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 | $	$ (20,000,000)	$ 28,000,000

XML

Derivatives - Schedule of Interest Rate Derivatives (Details) - Interest rate derivatives $ in Millions	9 Months Ended
	Sep. 30, 2021 USD ($)
Derivative [Line Items]
Notional Amount	$ 2,050
Fair Value Gain (Loss) at September 30, 2021	$ 8
ALABAMA POWER CO | Fair Value Hedges of Existing Debt
Derivative [Line Items]
Weighted Average Interest Rate Paid	1.91%
ALABAMA POWER CO | Fair Value Hedges of Existing Debt | March 2028
Derivative [Line Items]
Notional Amount	$ 150
Interest Rate Received	0.00%
Fair Value Gain (Loss) at September 30, 2021	$ 5
Southern Company parent | Fair Value Hedges of Existing Debt | March 2028
Derivative [Line Items]
Notional Amount	$ 400
Interest Rate Received	1.75%
Fair Value Gain (Loss) at September 30, 2021	$ (2)
Southern Company parent | Fair Value Hedges of Existing Debt | April 2030
Derivative [Line Items]
Notional Amount	$ 1,000
Interest Rate Received	3.70%
Fair Value Gain (Loss) at September 30, 2021	$ 3
SOUTHERN Co GAS | Fair Value Hedges of Existing Debt
Derivative [Line Items]
Notional Amount	$ 500
Interest Rate Received	1.75%
Fair Value Gain (Loss) at September 30, 2021	$ 2
London Interbank Offered Rate (LIBOR) | Southern Company parent | Fair Value Hedges of Existing Debt | March 2028
Derivative [Line Items]
Weighted Average Interest Rate Paid	0.68%
London Interbank Offered Rate (LIBOR) | Southern Company parent | Fair Value Hedges of Existing Debt | April 2030
Derivative [Line Items]
Weighted Average Interest Rate Paid	2.36%
London Interbank Offered Rate (LIBOR) | SOUTHERN Co GAS | Fair Value Hedges of Existing Debt
Derivative [Line Items]
Weighted Average Interest Rate Paid	0.38%

XML

Derivatives - Schedule of Foreign Currency Derivatives (Details) - 9 months ended Sep. 30, 2021 - Foreign currency derivatives € in Millions, $ in Millions	USD ($)	EUR (€)
Derivative [Line Items]
Pay Notional	$ 2,717
Receive Notional | €		€ 2,350
Fair Value Gain (Loss) at September 30, 2021	(23)
Fair Value Hedges of Existing Debt | Southern Company parent
Derivative [Line Items]
Pay Notional	$ 1,476
Pay Rate	3.39%
Receive Notional | €		1,250
Receive Rate	1.88%
Fair Value Gain (Loss) at September 30, 2021	$ (32)
Cash Flow Hedges of Existing Debt | SOUTHERN POWER CO
Derivative [Line Items]
Pay Notional	1,241
Receive Notional | €		1,100
Fair Value Gain (Loss) at September 30, 2021	9
Cash Flow Hedges of Existing Debt | 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, 2021	$ 9
Cash Flow Hedges of Existing Debt | 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, 2021	$ 0

XML

Derivatives - Schedule of Derivative Category and Balance Sheet Location (Details) - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	$ 546	$ 810
Derivative asset, Gross amounts offset	(57)	(529)
Derivative asset, net amounts recognized in the balance sheets	489	281
Derivative liability, gross amount recognized	103	621
Derivative liability, Gross amounts offset	(37)	(557)
Derivative liability, net amounts recognized in the balance sheets	66	64
Collateral already posted, assets, aggregate fair value	(20)
Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	30	658
Derivative liability, gross amount recognized	29	563
Derivatives not designated as hedging instruments | Energy-related derivatives | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	29	388
Derivatives not designated as hedging instruments | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	29	331
Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	1	270
Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	0	232
Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	426	42
Derivative liability, gross amount recognized	15	30
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]
Derivative asset, gross amount recognized	308	24
Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	9	11
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]
Derivative asset, gross amount recognized	118	18
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]
Derivative liability, gross amount recognized	6	19
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]
Derivative asset, gross amount recognized	90	110
Derivative liability, gross amount recognized	59	28
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]
Derivative asset, gross amount recognized	41	3
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 liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	0	5
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]
Derivative asset, gross amount recognized	4	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]
Derivative liability, gross amount recognized	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 | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	25	20
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 liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	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 charges and assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	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]
Derivative liability, gross amount recognized	16	0
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	9	0
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 liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	33	23
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]
Derivative asset, gross amount recognized	11	87
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]
Derivative liability, gross amount recognized	10	0
ALABAMA POWER CO
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	109	12
Derivative asset, Gross amounts offset	(3)	(7)
Derivative asset, net amounts recognized in the balance sheets	106	5
Derivative liability, gross amount recognized	4	7
Derivative liability, Gross amounts offset	(3)	(7)
Derivative liability, net amounts recognized in the balance sheets	1	0
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	104	12
Derivative liability, gross amount recognized	4	7
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]
Derivative asset, gross amount recognized	67	7
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	2	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 charges and assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	37	5
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]
Derivative liability, gross amount recognized	2	5
ALABAMA 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]
Derivative asset, gross amount recognized	5	0
ALABAMA 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 liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	0	0
GEORGIA POWER CO
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	166	15
Derivative asset, Gross amounts offset	(3)	(12)
Derivative asset, net amounts recognized in the balance sheets	163	3
Derivative liability, gross amount recognized	4	13
Derivative liability, Gross amounts offset	(3)	(12)
Derivative liability, net amounts recognized in the balance sheets	1	1
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	166	15
Derivative liability, gross amount recognized	4	13
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]
Derivative asset, gross amount recognized	124	7
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	2	5
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]
Derivative asset, gross amount recognized	42	8
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]
Derivative liability, gross amount recognized	2	8
MISSISSIPPI POWER CO
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	105	9
Derivative asset, Gross amounts offset	(2)	(7)
Derivative asset, net amounts recognized in the balance sheets	103	2
Derivative liability, gross amount recognized	3	9
Derivative liability, Gross amounts offset	(2)	(7)
Derivative liability, net amounts recognized in the balance sheets	1	2
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	105	9
Derivative liability, gross amount recognized	3	9
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]
Derivative asset, gross amount recognized	66	4
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	1	3
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]
Derivative asset, gross amount recognized	39	5
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]
Derivative liability, gross amount recognized	2	6
SOUTHERN POWER CO
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	30	89
Derivative asset, Gross amounts offset	(1)	0
Derivative asset, net amounts recognized in the balance sheets	29	89
Derivative liability, gross amount recognized	13	26
Derivative liability, Gross amounts offset	(1)	0
Derivative liability, net amounts recognized in the balance sheets	12	26
SOUTHERN POWER CO | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	1	0
Derivative liability, gross amount recognized	2	1
SOUTHERN POWER CO | Derivatives not designated as hedging instruments | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	1	0
SOUTHERN POWER CO | Derivatives not designated as hedging instruments | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	2	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]
Derivative asset, gross amount recognized	29	89
Derivative liability, gross amount recognized	11	25
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]
Derivative asset, gross amount recognized	8	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 current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	0	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]
Derivative asset, gross amount recognized	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]
Derivative liability, gross amount recognized	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]
Derivative asset, gross amount recognized	9	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 liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	11	23
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]
Derivative asset, gross amount recognized	11	87
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]
Derivative liability, gross amount recognized	0	0
SOUTHERN Co GAS
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	122	665
Derivative asset, Gross amounts offset	(48)	(503)
Derivative asset, net amounts recognized in the balance sheets	74	162
Derivative liability, gross amount recognized	35	566
Derivative liability, Gross amounts offset	(28)	(531)
Derivative liability, net amounts recognized in the balance sheets	7	35
Collateral already posted, assets, aggregate fair value	(20)	28
SOUTHERN Co GAS | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	29	658
Derivative liability, gross amount recognized	27	562
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	28	388
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	27	330
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	1	270
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	0	232
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	51	6
Derivative liability, gross amount recognized	4	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]
Derivative asset, gross amount recognized	51	6
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	4	1
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]
Derivative asset, gross amount recognized	42	1
Derivative liability, gross amount recognized	4	3
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]
Derivative asset, gross amount recognized	33	1
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 current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	0	3
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]
Derivative asset, gross amount recognized	3	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]
Derivative liability, gross amount recognized	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 | Interest rate derivatives | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	6	0
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 | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	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 | Interest rate derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	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 | Interest rate derivatives | Liabilities from risk management activities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	$ 0	$ 0

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Derivatives - Schedule of Pre-tax Effects of Unrealized Derivative Gains (Losses) (Details) - Energy-related derivatives - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	$ 404	$ 12
Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(5)
Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)		(2)
Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	297	12
Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	112	2
ALABAMA POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	100	6
ALABAMA POWER CO | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(1)
ALABAMA POWER CO | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)		0
ALABAMA POWER CO | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	66	5
ALABAMA POWER CO | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	35	1
GEORGIA POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	162	2
GEORGIA POWER CO | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(1)
GEORGIA POWER CO | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)		(1)
GEORGIA POWER CO | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	123	2
GEORGIA POWER CO | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	40	1
MISSISSIPPI POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	103	0
MISSISSIPPI POWER CO | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	0
MISSISSIPPI POWER CO | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)		(1)
MISSISSIPPI POWER CO | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	66	1
MISSISSIPPI POWER CO | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	37	0
SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	39	4
SOUTHERN Co GAS | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(3)
SOUTHERN Co GAS | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)		0
SOUTHERN Co GAS | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	42	4
SOUTHERN Co GAS | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	$ 0	$ 0

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Derivatives - Schedule of Pre-Tax Effects of Hedging on AOCI (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	$ 3	$ 64	$ (17)	$ (35)
Cash Flow Hedging | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	38	9	59	2
Cash Flow Hedging | Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	5	1	7	(27)
Cash Flow Hedging | Foreign currency derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	(36)	54	(79)	(10)
Fair Value Hedging | Foreign currency derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	(4)	0	(4)	0
Southern Power
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	(28)	59	(63)	(8)
Southern Power | Cash Flow Hedging | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	8	5	16	2
Southern Power | Cash Flow Hedging | Foreign currency derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	(36)	54	(79)	(10)
SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	30	5	43	(24)
SOUTHERN Co GAS | Cash Flow Hedging | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	30	4	43	0
SOUTHERN Co GAS | Cash Flow Hedging | Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	$ 0	$ 1	$ 0	$ (24)

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Derivatives - Schedule of Pre-Tax Effects of Cash Flow and Fair Value Hedging on Income (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Derivative [Line Items]
Depreciation and amortization	$ 896	$ 889	$ 2,658	$ 2,619
Total interest expense, net of amounts capitalized	(451)	(443)	(1,352)	(1,343)
Total other income (expense), net	131	113	297	319
Natural gas
Derivative [Line Items]
Total cost of sales	129	71	943	654
Other Income (Expense)
Derivative [Line Items]
Amount excluded from effectiveness testing recognized in earnings	4	0	4	0
Cash Flow Hedging | Energy-related derivatives | Cost of Sales
Derivative [Line Items]
Gain (loss) on hedges	2	0	0	(8)
Cash Flow Hedging | Energy-related derivatives | Depreciation and Amortization
Derivative [Line Items]
Gain (loss) on hedges	3	(1)	6	(3)
Cash Flow Hedging | Interest rate derivatives | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	(7)	(6)	(20)	(19)
Cash Flow Hedging | Foreign currency derivatives | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	(6)	(6)	(18)	(18)
Cash Flow Hedging | Foreign currency derivatives | Other Income (Expense)
Derivative [Line Items]
Gain (loss) on hedges	(34)	56	(76)	52
Fair Value Hedging | Interest rate derivatives | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	(4)	(3)	(16)	27
Fair Value Hedging | Foreign currency derivatives | Other Income (Expense)
Derivative [Line Items]
Gain (loss) on hedges	(32)	0	(32)	0
SOUTHERN POWER CO
Derivative [Line Items]
Depreciation and amortization	132	129	383	367
Total interest expense, net of amounts capitalized	(36)	(36)	(111)	(114)
Total other income (expense), net	2	13	10	19
SOUTHERN POWER CO | Cash Flow Hedging | Energy-related derivatives | Depreciation and Amortization
Derivative [Line Items]
Gain (loss) on hedges	3	(1)	6	(3)
SOUTHERN POWER CO | Cash Flow Hedging | Foreign currency derivatives | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	(6)	(6)	(18)	(18)
SOUTHERN POWER CO | Cash Flow Hedging | Foreign currency derivatives | Other Income (Expense)
Derivative [Line Items]
Gain (loss) on hedges	$ (34)	$ 56	$ (76)	$ 52

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Derivatives - Schedule of Cumulative Basis Adjustments for Fair Value Hedges (Details) - Fair Value Hedging - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Securities due within one year
Derivative [Line Items]
Carrying Amount of the Hedged Item	$ 0	$ (1,509)
Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item	0	(10)
Long-term debt
Derivative [Line Items]
Carrying Amount of the Hedged Item	(3,320)	0
Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item	0	0
Long-term debt | SOUTHERN Co GAS
Derivative [Line Items]
Carrying Amount of the Hedged Item	(497)	0
Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item	$ (1)	$ 0

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Derivatives - Schedule of Pre-tax Effect of Interest Rate and Energy Related Derivatives on Income (Details) - Derivatives not designated as hedging instruments - Energy-related derivatives - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	$ 18	$ (25)	$ (86)	$ 72
Natural gas revenues
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	(2)	(30)	(122)	54
Cost of natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	$ 20	$ 5	$ 36	$ 18

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Acquisitions and Dispositions - Southern Company Narrative (Details) - Subsequent Event - USD ($) $ in Millions		3 Months Ended
	Oct. 29, 2021	Dec. 31, 2021
Lessor, Lease, Description [Line Items]
Proceeds from sale of assets subject to leveraged lease	$ 45
Scenario, Forecast
Lessor, Lease, Description [Line Items]
Leveraged leases, income tax benefits		$ 16

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Acquisitions and Dispositions - Schedule of Asset Acquisition (Details) - SOUTHERN POWER CO - Deuel Harvest	9 Months Ended
	Sep. 30, 2021 MW
Business Acquisition [Line Items]
Approximate nameplate capacity (in MWs)	300
Maximum
Business Acquisition [Line Items]
PPA Contract Period	25 years
Minimum
Business Acquisition [Line Items]
PPA Contract Period	15 years
Deuel Harvest
Business Acquisition [Line Items]
Ownership percentage by parent	100.00%

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Acquisitions and Dispositions - Southern Power Narrative (Details) $ in Millions	1 Months Ended	9 Months Ended
	Sep. 30, 2021 USD ($) MW	Sep. 30, 2021 USD ($) MW	Sep. 30, 2020 USD ($)	Dec. 31, 2020 USD ($)
Business Acquisition [Line Items]
Construction work in progress	$ 9,611	$ 9,611		$ 8,697
Gain on sale		171	$ 36
SOUTHERN POWER CO
Business Acquisition [Line Items]
Construction work in progress	$ 274	274		$ 127
Gain on sale		39	$ 39
SOUTHERN POWER CO | Wind Generating Facility
Business Acquisition [Line Items]
Gain on sale		$ 37
SOUTHERN POWER CO | Garland Solar Storage
Business Acquisition [Line Items]
Nameplate capacity placed in service (in MWs) | MW	45	45
SOUTHERN POWER CO | Series of Construction Projects
Business Acquisition [Line Items]
Construction costs incurred to date	$ 341	$ 341
Construction work in progress	228	228
SOUTHERN POWER CO | Series of Construction Projects | Minimum
Business Acquisition [Line Items]
Estimated future construction payments	400	400
SOUTHERN POWER CO | Series of Construction Projects | Maximum
Business Acquisition [Line Items]
Estimated future construction payments	$ 460	$ 460

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Acquisitions and Dispositions - Schedule of Construction Projects (Details) - SOUTHERN POWER CO - MW	1 Months Ended	3 Months Ended	4 Months Ended	6 Months Ended	9 Months Ended
	Sep. 30, 2021	Dec. 31, 2021	Dec. 31, 2021	Mar. 31, 2022	Sep. 30, 2021	Dec. 31, 2020
Garland Solar Storage
Business Acquisition [Line Items]
Nameplate capacity placed in service (in MWs)	45				45
Garland Solar Storage | Scenario, Forecast
Business Acquisition [Line Items]
Nameplate capacity placed in service (in MWs)		43
Garland Solar Storage | Scenario, Forecast | Subsequent Event
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)		88	88
PPA Contract Period			20 years
Tranquillity Solar Storage | Scenario, Forecast | Subsequent Event
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)				72
PPA Contract Period				20 years
Glass Sands | Scenario, Forecast | Subsequent Event
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)		118	118
PPA Contract Period		12 years
Glass Sands | Glass Sands
Business Acquisition [Line Items]
Ownership percentage by parent						100.00%

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Acquisitions and Dispositions - Southern Company Gas Narrative (Details) $ in Millions		3 Months Ended		9 Months Ended
	Jul. 01, 2021 USD ($)	Sep. 30, 2021 USD ($)	Sep. 30, 2021 USD ($)	Sep. 30, 2021 USD ($)	Sep. 30, 2020 USD ($)	Feb. 28, 2022 USD ($)	Apr. 22, 2021 USD ($)	Jun. 30, 2020 payment
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sale				$ 171	$ 36
SOUTHERN Co GAS
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sale				127	$ (2)
Deferred tax expense, increase from change in appointment rate			$ 85	85
SOUTHERN Co GAS | Sequent | Disposal Group, Disposed of by Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale price	$ 159
Gain on sale	121
Gain on sale, net of tax	$ 93
Deferred tax expense, increase from change in appointment rate		$ 85
Guarantor obligations, current carrying value		36	36	36
Guarantor obligations		$ 1,000	$ 1,000	$ 1,000
SOUTHERN Co GAS | Pivotal LNG | Disposal Group, Disposed of by Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of contingent milestone payments | payment								2
Contingent milestone payment, amount							$ 5
SOUTHERN Co GAS | Scenario, Forecast | Pivotal LNG | Disposal Group, Disposed of by Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contingent milestone payment, amount						$ 5

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Acquisitions and Dispositions - Schedule of Assets Held for Sale (Details) - Disposal Group, Held-for-sale, Not Discontinued Operations - USD ($) $ in Millions	Sep. 30, 2021	Dec. 31, 2020
Assets Held for Sale:
Total property, plant, and equipment	$ 6	$ 8
Leveraged leases	45	52
Total Assets Held for Sale	$ 51	$ 60

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Segment and Related Information - Narrative (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2021 USD ($) state	Sep. 30, 2020 USD ($)	Sep. 30, 2021 USD ($) state segment	Sep. 30, 2020 USD ($)
Segment Reporting Information [Line Items]
Number of states in which entity operates | state	3		3
Operating revenues	$ 5,732	$ 5,755	$ 18,066	$ 15,771
SOUTHERN POWER CO
Segment Reporting Information [Line Items]
Operating revenues	501	332	1,113	851
SOUTHERN POWER CO | Traditional Electric Operating Companies | Wholesale revenues, affiliates
Segment Reporting Information [Line Items]
Operating revenues	$ 167	101	$ 361	279
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Number of states in which entity operates | state	4		4
Operating revenues	$ 605	950	$ 4,930	3,506
Number of reportable segments | segment			4
SOUTHERN Co GAS | SOUTHERN POWER CO | Natural gas
Segment Reporting Information [Line Items]
Operating revenues		$ 9	$ 18	$ 22
Southern Natural Gas Company, LLC | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Ownership percentage, equity method investment	50.00%		50.00%
PennEast Pipeline | 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 - Schedule of Financial Data for Business Segments (Details) - USD ($) $ in Millions		3 Months Ended					9 Months Ended
	Jul. 01, 2021	Sep. 30, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Segment Reporting Information [Line Items]
Operating revenues			$ 6,238			$ 5,620	$ 17,346	$ 15,258
Segment net income (loss)			1,101			1,251	2,608	2,732
Goodwill		$ 5,280	5,280				5,280		$ 5,280
Assets held for sale		51	51				51		60
Total assets		127,861	127,861				127,861		122,935
Gain on sale							171	36
Estimated loss on Plant Vogtle Units 3 and 4			264			0	772	149
Impairment of leveraged leases			0			0	7	154
SOUTHERN POWER CO
Segment Reporting Information [Line Items]
Operating revenues			679			523	1,610	1,337
Total assets		13,611	13,611				13,611		13,235
Gain on sale							39	39
SOUTHERN POWER CO | Wind Generating Facility
Segment Reporting Information [Line Items]
Gain on sale							37
Gain on sale, net of tax							28
SOUTHERN POWER CO | Disposal Group, Disposed of by Sale | Plant Mankato
Segment Reporting Information [Line Items]
Gain on sale								39
Gain on sale, net of tax								23
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues			623			477	2,994	2,362
Segment net income (loss)			56			14	389	360
Goodwill		5,015	5,015				5,015		5,015
Total assets		22,958	22,958				22,958		22,630
Gain on sale							127	(2)
Deferred tax expense, increase from change in appointment rate			85				85
Asset impairment charges							84	0
SOUTHERN Co GAS | Disposal Group, Disposed of by Sale | Sequent
Segment Reporting Information [Line Items]
Gain on sale	$ 121
Gain on sale, net of tax	$ 93
Deferred tax expense, increase from change in appointment rate		85
GEORGIA POWER CO
Segment Reporting Information [Line Items]
Operating revenues			2,856			2,617	7,050	6,371
Total assets		48,932	48,932				48,932		47,080
Estimated loss on Plant Vogtle Units 3 and 4			264	$ 460	$ 48	0	772	149
Estimated loss on Plant Vogtle Units 3 and 4, net of tax			197	$ 343	$ 36		576	111
Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues			5,527			5,049	14,051	12,628
Segment net income (loss)			1,163			1,358	2,563	2,783
Goodwill		2	2				2		2
Assets held for sale		3	3				3		5
Total assets		101,960	101,960				101,960		98,041
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues			623			477	2,994	2,362
All Other
Segment Reporting Information [Line Items]
Impairment of leveraged leases							7	154
Impairment of leveraged lease, net of tax							6	74
Gas distribution operations | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Goodwill		4,034	4,034				4,034		4,034
Wholesale Gas Services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues			0			(51)	188	(19)
Gas marketing services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Goodwill		981	981				981		981
Operating Segments | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues			616			475	2,989	2,363
Segment net income (loss)			147			21	479	372
Total assets		23,763	23,763				23,763		23,040
Operating Segments | Traditional Electric Operating Companies | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues			5,018			4,629	12,813	11,576
Segment net income (loss)			1,085			1,284	2,352	2,571
Goodwill		0	0				0		0
Assets held for sale		3	3				3		5
Total assets		89,057	89,057				89,057		85,486
Operating Segments | SOUTHERN POWER CO | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues			679			523	1,610	1,337
Segment net income (loss)			78			74	211	212
Goodwill		2	2				2		2
Assets held for sale		0	0				0		0
Total assets		13,611	13,611				13,611		13,235
Operating Segments | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues			623			477	2,994	2,362
Segment net income (loss)			56			14	389	360
Goodwill		5,015	5,015				5,015		5,015
Assets held for sale		0	0				0		0
Total assets		22,958	22,958				22,958		22,630
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues			124			132	412	380
Segment net income (loss)			(121)			(122)	(338)	(420)
Goodwill		263	263				263		263
Assets held for sale		48	48				48		55
Total assets		3,704	3,704				3,704		3,168
Operating Segments | All Other | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues			11			8	29	24
Segment net income (loss)			(91)			(7)	(90)	(12)
Total assets		11,387	11,387				11,387		11,336
Operating Segments | Gas distribution operations | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues			556			479	2,466	2,086
Segment net income (loss)			45			46	308	284
Total assets		20,619	20,619				20,619		19,090
Operating Segments | Gas Pipeline Investments | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues			8			8	24	24
Segment net income (loss)			10			23	3	74
Total assets		1,478	1,478				1,478		1,597
Operating Segments | Wholesale Gas Services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues			0			(51)	188	(19)
Segment net income (loss)			94			(45)	108	(45)
Total assets		132	132				132		850
Operating Segments | Gas marketing services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues			52			39	311	272
Segment net income (loss)			(2)			(3)	60	59
Total assets		1,534	1,534				1,534		1,503
Eliminations
Segment Reporting Information [Line Items]
Operating revenues			(36)			(38)	(111)	(112)
Segment net income (loss)			3			1	(6)	9
Goodwill		0	0				0		0
Assets held for sale		0	0				0		0
Total assets		(761)	(761)				(761)		(904)
Eliminations | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues			(4)			(6)	(24)	(25)
Segment net income (loss)			0			0	0	0
Total assets		(12,192)	(12,192)				(12,192)		(11,746)
Eliminations | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues			(170)			(103)	(372)	(285)
Segment net income (loss)			0			$ 0	0	$ 0
Goodwill		0	0				0		0
Assets held for sale		0	0				0		0
Total assets		$ (708)	$ (708)				$ (708)		$ (680)

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Segment and Related Information - Schedule of Financial Data for Products and Services (Details) - USD ($) $ in Millions		3 Months Ended			9 Months Ended
	Jul. 01, 2021	Sep. 30, 2021	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Concentration Risk [Line Items]
Operating revenues			$ 6,238	$ 5,620	$ 17,346	$ 15,258
Gain on sale					171	36
Retail
Concentration Risk [Line Items]
Operating revenues			4,551	4,243	11,492	10,503
Wholesale
Concentration Risk [Line Items]
Operating revenues			731	584	1,822	1,473
Other
Concentration Risk [Line Items]
Operating revenues			179	164	525	484
Electric Utilities' Revenues
Concentration Risk [Line Items]
Operating revenues			5,527	5,049	14,051	12,628
Electric Utilities' Revenues | Retail
Concentration Risk [Line Items]
Operating revenues			4,551	4,243	11,492	10,503
Electric Utilities' Revenues | Wholesale
Concentration Risk [Line Items]
Operating revenues			731	584	1,822	1,473
Electric Utilities' Revenues | Other
Concentration Risk [Line Items]
Operating revenues			245	222	737	652
Southern Company Gas' Revenues
Concentration Risk [Line Items]
Operating revenues			623	477	2,994	2,362
Southern Company Gas' Revenues | Gas Distribution Operations
Concentration Risk [Line Items]
Operating revenues			553	476	2,451	2,072
Southern Company Gas' Revenues | Wholesale Gas Services
Concentration Risk [Line Items]
Operating revenues			0	(51)	188	(19)
Southern Company Gas' Revenues | Gas marketing services
Concentration Risk [Line Items]
Operating revenues			52	39	311	272
Southern Company Gas' Revenues | Other
Concentration Risk [Line Items]
Operating revenues			18	13	44	37
Southern Company Gas' Revenues
Concentration Risk [Line Items]
Operating revenues			623	477	2,994	2,362
Gain on sale					127	(2)
Deferred tax expense, increase from change in appointment rate			85		85
Asset impairment charges					84	0
Southern Company Gas' Revenues | Disposal Group, Disposed of by Sale | Sequent
Concentration Risk [Line Items]
Gain on sale	$ 121
Gain on sale, net of tax	$ 93
Deferred tax expense, increase from change in appointment rate		$ 85
Southern Company Gas' Revenues | Wholesale Gas Services
Concentration Risk [Line Items]
Operating revenues			0	(51)	188	(19)
Less Gross Gas Costs			0	1,134	3,783	3,189
Third Party Gross Revenues | Southern Company Gas' Revenues | Wholesale Gas Services
Concentration Risk [Line Items]
Operating revenues			0	1,050	3,881	3,089
Intercompany Revenues | Southern Company Gas' Revenues | Wholesale Gas Services
Concentration Risk [Line Items]
Operating revenues			0	33	90	81
Total Gross Revenues | Southern Company Gas' Revenues | Wholesale Gas Services
Concentration Risk [Line Items]
Operating revenues			$ 0	$ 1,083	$ 3,971	$ 3,170