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 June 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
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 June 30, 2021
The Southern Company	Par Value $5 Per Share	1,058,825,814
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	97
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	156
Item 4.	Controls and Procedures	156
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	157
Item 1A.	Risk Factors	157
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	157
	Signatures	161

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    Table of Contents                                Index to Financial Statements

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
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
GRAM	Atlanta Gas Light's Georgia Rate Adjustment Mechanism

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DEFINITIONS

(continued)

Term	Meaning
Guarantee Settlement Agreement	The June 9, 2017 settlement agreement between the Vogtle Owners and Toshiba related to certain payment obligations of the EPC Contractor guaranteed by Toshiba
Gulf Power	Gulf Power Company, until January 1, 2019 a 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 to construct and operate a natural gas pipeline in which Southern Company Gas has a 20% ownership interest
PEP	Mississippi Power's Performance Evaluation Plan
Pivotal LNG	Pivotal LNG, Inc., through March 24, 2020, a wholly-owned subsidiary of Southern Company Gas
PowerSecure	PowerSecure, Inc., a wholly-owned subsidiary of Southern Company

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DEFINITIONS

(continued)

Term	Meaning
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., until July 1, 2021, wholly-owned subsidiaries of Southern Company Gas
SNG	Southern Natural Gas Company, L.L.C., a pipeline system in which Southern Company Gas has a 50% ownership interest
Southern Company	The Southern Company
Southern Company Gas	Southern Company Gas and its subsidiaries
Southern Company Gas Capital	Southern Company Gas Capital Corporation, a 100%-owned subsidiary of Southern Company Gas
Southern Company power pool	The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations
Southern Company system	Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas, Southern Electric Generating Company, Southern Nuclear, SCS, Southern Communications Services, Inc., PowerSecure, and other subsidiaries
Southern Holdings	Southern Company Holdings, Inc., a wholly-owned subsidiary of Southern Company
Southern Nuclear	Southern Nuclear Operating Company, Inc., a wholly-owned subsidiary of Southern Company
Southern Power	Southern Power Company and its subsidiaries
SouthStar	SouthStar Energy Services, LLC (a 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 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
VCM	Vogtle Construction Monitoring

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DEFINITIONS

(continued)

Term	Meaning
VIE	Variable interest entity
Virginia Commission	Virginia State Corporation Commission
Virginia Natural Gas	Virginia Natural Gas, Inc., a wholly-owned subsidiary of Southern Company Gas
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, 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; 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, Plant Barry Unit 8, and pipeline projects, including PSC approvals and FERC and NRC actions;

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

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

(continued)

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

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

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

•advances in technology, 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 June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Operating Revenues:
Retail electric revenues	$	3,599	$	3,182	$	6,941	$	6,260
Wholesale electric revenues	546		472		1,091		889
Other electric revenues	175		168		346		320
Natural gas revenues (includes alternative revenue programs of    $2, $(2), $4, and $7, respectively)	677		636		2,371		1,885
Other revenues	201		162		359		284
Total operating revenues	5,198		4,620		11,108		9,638
Operating Expenses:
Fuel	848		621		1,696		1,257
Purchased power	217		200		424		381
Cost of natural gas	231		144		814		583
Cost of other sales	103		74		185		129
Other operations and maintenance	1,438		1,203		2,810		2,498
Depreciation and amortization	891		873		1,762		1,730
Taxes other than income taxes	313		298		657		629
Estimated loss on Plant Vogtle Units 3 and 4	460		149		508		149
(Gain) loss on dispositions, net	(11)		—		(54)		(39)
Total operating expenses	4,490		3,562		8,802		7,317
Operating Income	708		1,058		2,306		2,321
Other Income and (Expense):
Allowance for equity funds used during construction	45		35		90		68
Earnings (loss) from equity method investments	(40)		30		5		72
Interest expense, net of amounts capitalized	(450)		(444)		(901)		(900)
Impairment of leveraged leases	(7)		(154)		(7)		(154)
Other income (expense), net	108		101		167		204
Total other income and (expense)	(344)		(432)		(646)		(710)
Earnings Before Income Taxes	364		626		1,660		1,611
Income taxes (benefit)	(12)		5		178		150
Consolidated Net Income	376		621		1,482		1,461
Dividends on preferred stock of subsidiaries	4		4		7		7
Net income (loss) attributable to noncontrolling interests	—		5		(33)		(26)
Consolidated Net Income Attributable to    Southern Company	$	372	$	612	$	1,508	$	1,480
Common Stock Data:
Earnings per share -
Basic	$	0.35	$	0.58	$	1.42	$	1.40
Diluted	$	0.35	$	0.58	$	1.41	$	1.39
Average number of shares of common stock outstanding (in millions)
Basic	1,061		1,058		1,060		1,057
Diluted	1,067		1,063		1,066		1,065

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 June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Consolidated Net Income	$	376	$	621	$	1,482	$	1,461
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of    $5, $4, $(5), and $(26), respectively	14		10		(16)		(75)
Reclassification adjustment for amounts included in net income,    net of tax of $(1), $(3), $17, and $10, respectively	(5)		(9)		50		29
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income,    net of tax of $2, $1, $3, and $2, respectively	3		3		6		3
Total other comprehensive income (loss)	12		4		40		(43)
Comprehensive Income	388		625		1,522		1,418
Dividends on preferred stock of subsidiaries	4		4		7		7
Comprehensive income (loss) attributable to noncontrolling interests	—		5		(33)		(26)
Consolidated Comprehensive Income Attributable to    Southern Company	$	384	$	616	$	1,548	$	1,437

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 Six Months Ended June 30,
	2021		2020
	(in millions)
Operating Activities:
Consolidated net income	$	1,482	$	1,461
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	1,949		1,916
Deferred income taxes	(101)		(218)
Utilization of federal investment tax credits	224		—
Mark-to-market adjustments	136		36
Pension, postretirement, and other employee benefits	(115)		(119)
Settlement of asset retirement obligations	(228)		(193)
Stock based compensation expense	105		84
Estimated loss on Plant Vogtle Units 3 and 4	508		149
Storm damage accruals	112		117
Impairment charges	89		154
Natural gas cost under recovery – long-term	(119)		—
Other, net	(60)		(96)
Changes in certain current assets and liabilities —
-Receivables	29		292
-Prepayments	(79)		(102)
-Natural gas for sale, net of temporary LIFO liquidation	375		182
-Natural gas cost under recovery	(485)		—
-Other current assets	36		(253)
-Accounts payable	(177)		(467)
-Accrued taxes	(157)		258
-Accrued compensation	(238)		(347)
-Retail fuel cost over recovery	(146)		174
-Customer refunds	(59)		(223)
-Other current liabilities	(177)		42
Net cash provided from operating activities	2,904		2,847
Investing Activities:
Business acquisitions, net of cash acquired	(345)		(81)
Property additions	(3,384)		(3,202)
Nuclear decommissioning trust fund purchases	(930)		(524)
Nuclear decommissioning trust fund sales	926		519
Proceeds from dispositions	25		983
Cost of removal, net of salvage	(184)		(130)
Change in construction payables, net	(55)		(103)
Payments pursuant to LTSAs	(114)		(91)
Other investing activities	35		(26)
Net cash used for investing activities	(4,026)		(2,655)
Financing Activities:
Increase (decrease) in notes payable, net	492		(1,170)
Proceeds —
Long-term debt	4,646		4,293
Common stock	24		59
Short-term borrowings	325		615
Redemptions and repurchases —
Long-term debt	(2,477)		(2,444)
Short-term borrowings	(25)		(190)
Capital contributions from noncontrolling interests	343		172
Distributions to noncontrolling interests	(113)		(118)
Payment of common stock dividends	(1,377)		(1,332)
Other financing activities	(167)		(170)
Net cash provided from (used for) financing activities	1,671		(285)
Net Change in Cash, Cash Equivalents, and Restricted Cash	549		(93)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	1,068		1,978
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	1,617	$	1,885
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $43 and $41 capitalized for 2021 and 2020, respectively)	$	884	$	852
Income taxes, net	88		(8)
Noncash transactions —
Accrued property additions at end of period	943		828
Contributions from noncontrolling interests	89		9
Contributions of wind turbine equipment	82		17
Right-of-use assets obtained under leases	90		94

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 June 30, 2021		At December 31, 2020
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,582	$	1,065
Receivables —
Customer accounts	1,683		1,753
Energy marketing	—		516
Unbilled revenues	643		672
Other accounts and notes	488		512
Accumulated provision for uncollectible accounts	(88)		(118)
Materials and supplies	1,469		1,478
Fossil fuel for generation	475		550
Natural gas for sale	178		460
Prepaid expenses	538		276
Assets from risk management activities, net of collateral	175		147
Regulatory assets – asset retirement obligations	224		214
Natural gas cost under recovery	485		—
Assets held for sale	787		60
Other regulatory assets	728		810
Other current assets	184		222
Total current assets	9,551		8,617
Property, Plant, and Equipment:
In service	112,783		110,516
Less: Accumulated depreciation	33,240		32,397
Plant in service, net of depreciation	79,543		78,119
Nuclear fuel, at amortized cost	816		818
Construction work in progress	9,264		8,697
Total property, plant, and equipment	89,623		87,634
Other Property and Investments:
Goodwill	5,280		5,280
Nuclear decommissioning trusts, at fair value	2,457		2,303
Equity investments in unconsolidated subsidiaries	1,287		1,362
Other intangible assets, net of amortization of $286 and $328, respectively	466		487
Leveraged leases	569		556
Miscellaneous property and investments	494		398
Total other property and investments	10,553		10,386
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,775		1,802
Deferred charges related to income taxes	806		796
Unamortized loss on reacquired debt	269		280
Regulatory assets – asset retirement obligations, deferred	4,931		4,934
Other regulatory assets, deferred	7,092		7,198
Other deferred charges and assets	1,307		1,288
Total deferred charges and other assets	16,180		16,298
Total Assets	$	125,907	$	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 June 30, 2021		At December 31, 2020
	(in millions)
Current Liabilities:
Securities due within one year	$	2,829	$	3,507
Notes payable	1,402		609
Energy marketing trade payables	—		494
Accounts payable	2,075		2,312
Customer deposits	467		487
Accrued taxes —
Accrued income taxes	40		130
Other accrued taxes	589		699
Accrued interest	510		513
Accrued compensation	770		1,025
Asset retirement obligations	684		585
Liabilities held for sale	677		—
Operating lease obligations	245		241
Other regulatory liabilities	416		509
Other current liabilities	956		968
Total current liabilities	11,660		12,079
Long-term Debt	47,828		45,073
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	8,710		8,175
Deferred credits related to income taxes	5,593		5,767
Accumulated deferred ITCs	2,247		2,235
Employee benefit obligations	2,004		2,213
Operating lease obligations, deferred	1,604		1,611
Asset retirement obligations, deferred	9,983		10,099
Accrued environmental remediation	208		216
Other cost of removal obligations	2,190		2,211
Other regulatory liabilities, deferred	256		251
Other deferred credits and liabilities	587		480
Total deferred credits and other liabilities	33,382		33,258
Total Liabilities	92,870		90,410
Redeemable Preferred Stock of Subsidiaries	291		291
Total Stockholders' Equity (See accompanying statements)	32,746		32,234
Total Liabilities and Stockholders' Equity	$	125,907	$	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

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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

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 June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Operating Revenues:
Retail revenues	$	1,354	$	1,223	$	2,706	$	2,427
Wholesale revenues, non-affiliates	85		54		178		111
Wholesale revenues, affiliates	24		7		55		26
Other revenues	93		81		176		152
Total operating revenues	1,556		1,365		3,115		2,716
Operating Expenses:
Fuel	263		199		554		415
Purchased power, non-affiliates	48		49		97		89
Purchased power, affiliates	39		30		69		49
Other operations and maintenance	413		342		775		690
Depreciation and amortization	214		202		425		402
Taxes other than income taxes	101		102		203		208
Total operating expenses	1,078		924		2,123		1,853
Operating Income	478		441		992		863
Other Income and (Expense):
Allowance for equity funds used during construction	12		11		24		22
Interest expense, net of amounts capitalized	(84)		(83)		(168)		(171)
Other income (expense), net	33		26		62		48
Total other income and (expense)	(39)		(46)		(82)		(101)
Earnings Before Income Taxes	439		395		910		762
Income taxes	104		93		213		177
Net Income	335		302		697		585
Dividends on Preferred Stock	4		4		7		7
Net Income After Dividends on Preferred Stock	$	331	$	298	$	690	$	578

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Net Income	$	335	$	302	$	697	$	585
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income,    net of tax of $—, $—, $1, and $1, respectively	1		1		2		2
Total other comprehensive income (loss)	1		1		2		2
Comprehensive Income	$	336	$	303	$	699	$	587

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 Six Months Ended June 30,
	2021		2020
	(in millions)
Operating Activities:
Net income	$	697	$	585
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	496		484
Deferred income taxes	87		38
Pension, postretirement, and other employee benefits	(39)		(50)
Settlement of asset retirement obligations	(104)		(100)
Other, net	(35)		24
Changes in certain current assets and liabilities —
-Receivables	(85)		6
-Fossil fuel stock	21		(38)
-Prepayments	(53)		(62)
-Materials and supplies	(7)		(38)
-Other current assets	(37)		(34)
-Accounts payable	(236)		(232)
-Accrued taxes	20		197
-Accrued compensation	(60)		(75)
-Retail fuel cost over recovery	(18)		66
-Other current liabilities	(63)		(97)
Net cash provided from operating activities	584		674
Investing Activities:
Property additions	(844)		(686)
Nuclear decommissioning trust fund purchases	(473)		(160)
Nuclear decommissioning trust fund sales	473		160
Cost of removal, net of salvage	(56)		(29)
Change in construction payables	25		(53)
Other investing activities	(18)		(15)
Net cash used for investing activities	(893)		(783)
Financing Activities:
Proceeds —
Senior notes	600		—
Pollution control revenue bonds	—		87
Redemptions —
Senior notes	(200)		—
Pollution control revenue bonds	—		(87)
Capital contributions from parent company	624		610
Payment of common stock dividends	(492)		(479)
Other financing activities	(26)		(15)
Net cash provided from financing activities	506		116
Net Change in Cash, Cash Equivalents, and Restricted Cash	197		7
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	530		894
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	727	$	901
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $7 capitalized for both 2021 and 2020)	$	154	$	161
Income taxes, net	171		—
Noncash transactions —
Accrued property additions at end of period	191		147
Right-of-use assets obtained under leases	2		3

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 June 30, 2021		At December 31, 2020
	(in millions)
Current Assets:
Cash and cash equivalents	$	727	$	530
Receivables —
Customer accounts	402		429
Unbilled revenues	180		152
Affiliated	40		31
Other accounts and notes	80		66
Accumulated provision for uncollectible accounts	(25)		(43)
Fossil fuel stock	214		235
Materials and supplies	550		546
Prepaid expenses	94		42
Other regulatory assets	221		226
Other current assets	88		33
Total current assets	2,571		2,247
Property, Plant, and Equipment:
In service	32,390		31,816
Less: Accumulated provision for depreciation	10,229		10,009
Plant in service, net of depreciation	22,161		21,807
Nuclear fuel, at amortized cost	254		270
Construction work in progress	978		866
Total property, plant, and equipment	23,393		22,943
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,251		1,157
Equity investments in unconsolidated subsidiaries	64		63
Miscellaneous property and investments	127		131
Total other property and investments	1,442		1,351
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	130		151
Deferred charges related to income taxes	237		235
Regulatory assets – asset retirement obligations	1,437		1,441
Other regulatory assets, deferred	2,168		2,162
Other deferred charges and assets	313		273
Total deferred charges and other assets	4,285		4,262
Total Assets	$	31,691	$	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 BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At June 30, 2021		At December 31, 2020
	(in millions)
Current Liabilities:
Securities due within one year	$	616	$	311
Accounts payable —
Affiliated	290		316
Other	378		545
Customer deposits	106		104
Accrued taxes	173		152
Accrued interest	93		90
Accrued compensation	176		212
Asset retirement obligations	296		254
Other regulatory liabilities	37		108
Other current liabilities	119		107
Total current liabilities	2,284		2,199
Long-term Debt	8,649		8,558
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,390		3,273
Deferred credits related to income taxes	1,988		2,016
Accumulated deferred ITCs	91		94
Employee benefit obligations	173		214
Operating lease obligations	100		119
Asset retirement obligations, deferred	3,651		3,720
Other cost of removal obligations	291		335
Other regulatory liabilities, deferred	93		124
Other deferred credits and liabilities	53		50
Total deferred credits and other liabilities	9,830		9,945
Total Liabilities	20,763		20,702
Redeemable Preferred Stock	291		291
Common Stockholder's Equity (See accompanying statements)	10,637		9,810
Total Liabilities and Stockholder's Equity	$	31,691	$	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
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

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

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GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Operating Revenues:
Retail revenues	$	2,026	$	1,760	$	3,813	$	3,435
Wholesale revenues	36		25		80		51
Other revenues	163		143		302		268
Total operating revenues	2,225		1,928		4,195		3,754
Operating Expenses:
Fuel	343		226		656		458
Purchased power, non-affiliates	144		133		288		262
Purchased power, affiliates	149		122		285		251
Other operations and maintenance	542		463		1,015		928
Depreciation and amortization	342		354		680		707
Taxes other than income taxes	118		108		235		221
Estimated loss on Plant Vogtle Units 3 and 4	460		149		508		149
Total operating expenses	2,098		1,555		3,667		2,976
Operating Income	127		373		528		778
Other Income and (Expense):
Allowance for equity funds used during construction	30		20		61		40
Interest expense, net of amounts capitalized	(106)		(105)		(210)		(216)
Other income (expense), net	42		31		83		63
Total other income and (expense)	(34)		(54)		(66)		(113)
Earnings Before Income Taxes	93		319		462		665
Income taxes (benefit)	(50)		11		(32)		27
Net Income	$	143	$	308	$	494	$	638

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Net Income	$	143	$	308	$	494	$	638
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of    $—, $—, $—, and $(1), respectively	—		—		—		(2)
Reclassification adjustment for amounts included in net income,    net of tax of $1, $1, $1, and $1, respectively	1		2		3		3
Total other comprehensive income (loss)	1		2		3		1
Comprehensive Income	$	144	$	310	$	497	$	639

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

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GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2021		2020
	(in millions)
Operating Activities:
Net income	$	494	$	638
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	772		800
Deferred income taxes	(309)		(202)
Allowance for equity funds used during construction	(61)		(40)
Pension, postretirement, and other employee benefits	(59)		(55)
Settlement of asset retirement obligations	(100)		(78)
Storm damage accruals	107		107
Estimated loss on Plant Vogtle Units 3 and 4	508		149
Other, net	90		19
Changes in certain current assets and liabilities —
-Receivables	(73)		(73)
-Fossil fuel stock	55		(52)
-Materials and supplies	(46)		(61)
-Other current assets	15		(26)
-Accounts payable	83		—
-Accrued taxes	14		87
-Accrued compensation	(39)		(69)
-Retail fuel cost over recovery	(113)		109
-Customer refunds	(6)		(159)
-Other current liabilities	(19)		30
Net cash provided from operating activities	1,313		1,124
Investing Activities:
Property additions	(1,575)		(1,650)
Nuclear decommissioning trust fund purchases	(458)		(365)
Nuclear decommissioning trust fund sales	453		359
Cost of removal, net of salvage	(73)		(62)
Change in construction payables, net of joint owner portion	(72)		(48)
Proceeds from dispositions	3		143
Other investing activities	(8)		(36)
Net cash used for investing activities	(1,730)		(1,659)
Financing Activities:
Increase (decrease) in notes payable, net	250		(25)
Proceeds —
Senior notes	750		1,500
Pollution control revenue bonds	—		53
FFB loan	371		519
Short-term borrowings	—		250
Redemptions and repurchases —
Senior notes	(325)		(950)
Pollution control revenue bonds	(69)		(148)
FFB loan	(45)		(32)
Capital contributions from parent company	368		500
Payment of common stock dividends	(824)		(771)
Other financing activities	(19)		(27)
Net cash provided from financing activities	457		869
Net Change in Cash, Cash Equivalents, and Restricted Cash	40		334
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	9		52
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	49	$	386
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $30 and $22 capitalized for 2021 and 2020, respectively)	$	182	$	180
Income taxes, net	139		—
Noncash transactions —
Accrued property additions at end of period	476		478
Right-of-use assets obtained under operating leases	3		29

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 June 30, 2021		At December 31, 2020
	(in millions)
Current Assets:
Cash and cash equivalents	$	49	$	9
Receivables —
Customer accounts	601		621
Unbilled revenues	334		233
Joint owner accounts	98		123
Affiliated	27		21
Other accounts and notes	40		67
Accumulated provision for uncollectible accounts	(3)		(26)
Fossil fuel stock	223		278
Materials and supplies	631		592
Regulatory assets – storm damage	150		213
Regulatory assets – asset retirement obligations	183		166
Other regulatory assets	240		248
Other current assets	140		143
Total current assets	2,713		2,688
Property, Plant, and Equipment:
In service	40,408		39,682
Less: Accumulated provision for depreciation	12,540		12,251
Plant in service, net of depreciation	27,868		27,431
Nuclear fuel, at amortized cost	562		548
Construction work in progress	7,062		6,857
Total property, plant, and equipment	35,492		34,836
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,207		1,145
Equity investments in unconsolidated subsidiaries	51		51
Miscellaneous property and investments	66		63
Total other property and investments	1,324		1,259
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,236		1,308
Deferred charges related to income taxes	535		527
Regulatory assets – asset retirement obligations, deferred	3,281		3,291
Other regulatory assets, deferred	2,550		2,692
Other deferred charges and assets	494		479
Total deferred charges and other assets	8,096		8,297
Total Assets	$	47,625	$	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 June 30, 2021		At December 31, 2020
	(in millions)
Current Liabilities:
Securities due within one year	$	627	$	542
Notes payable	310		60
Accounts payable —
Affiliated	587		597
Other	755		753
Customer deposits	268		276
Accrued taxes	322		407
Accrued interest	138		130
Accrued compensation	164		233
Operating lease obligations	152		151
Asset retirement obligations	321		287
Over recovered fuel clause revenues	—		113
Other regulatory liabilities	277		228
Other current liabilities	230		254
Total current liabilities	4,151		4,031
Long-term Debt	13,023		12,428
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,138		3,272
Deferred credits related to income taxes	2,463		2,588
Accumulated deferred ITCs	322		273
Employee benefit obligations	518		586
Operating lease obligations, deferred	1,111		1,156
Asset retirement obligations, deferred	5,962		5,978
Other deferred credits and liabilities	391		267
Total deferred credits and other liabilities	13,905		14,120
Total Liabilities	31,079		30,579
Common Stockholder's Equity (See accompanying statements)	16,546		16,501
Total Liabilities and Stockholder's Equity	$	47,625	$	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
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

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 June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Operating Revenues:
Retail revenues	$	219	$	199	$	422	$	398
Wholesale revenues, non-affiliates	54		52		117		103
Wholesale revenues, affiliates	25		25		57		47
Other revenues	5		7		14		11
Total operating revenues	303		283		610		559
Operating Expenses:
Fuel	91		83		192		162
Purchased power	11		7		16		12
Other operations and maintenance	76		67		144		142
Depreciation and amortization	44		46		91		88
Taxes other than income taxes	32		30		63		59
Total operating expenses	254		233		506		463
Operating Income	49		50		104		96
Other Income and (Expense):
Interest expense, net of amounts capitalized	(14)		(15)		(29)		(31)
Other income (expense), net	11		6		20		14
Total other income and (expense)	(3)		(9)		(9)		(17)
Earnings Before Income Taxes	46		41		95		79
Income taxes	8		2		12		8
Net Income	$	38	$	39	$	83	$	71

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Net Income	$	38	$	39	$	83	$	71
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of    $—, $—, $—, and $—, respectively	—		—		—		(1)
Reclassification adjustment for amounts included in net income,    net of tax of $—, $—, $—, and $—, respectively	—		—		1		1
Total other comprehensive income (loss)	—		—		1		—
Comprehensive Income	$	38	$	39	$	84	$	71

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 Six Months Ended June 30,
	2021		2020
	(in millions)
Operating Activities:
Net income	$	83	$	71
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	106		92
Settlement of asset retirement obligations	(12)		(9)
Other, net	(16)		(4)
Changes in certain current assets and liabilities —
-Other current assets	(3)		(13)
-Accounts payable	(33)		(19)
-Accrued taxes	(51)		(21)
-Accrued compensation	(10)		(15)
-Retail fuel cost over recovery	(15)		(1)
-Other current liabilities	(8)		(10)
Net cash provided from operating activities	41		71
Investing Activities:
Property additions	(90)		(111)
Construction payables	(3)		(14)
Payments pursuant to LTSAs	(14)		(10)
Other investing activities	(10)		(10)
Net cash used for investing activities	(117)		(145)
Financing Activities:
Increase (decrease) in notes payable, net	(25)		4
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)
Capital contributions from parent company	101		75
Return of capital to parent company	—		(74)
Payment of common stock dividends	(79)		—
Other financing activities	(7)		(1)
Net cash provided from (used for) financing activities	515		(178)
Net Change in Cash, Cash Equivalents, and Restricted Cash	439		(252)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	39		286
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	478	$	34
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $— capitalized for both 2021 and 2020)	$	31	$	33
Income taxes, net	7		—
Noncash transactions — Accrued property additions at end of period	31		21

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 June 30, 2021		At December 31, 2020
	(in millions)
Current Assets:
Cash and cash equivalents	$	478	$	39
Receivables —
Customer accounts, net	38		34
Unbilled revenues	42		38
Affiliated	26		32
Other accounts and notes	30		32
Fossil fuel stock	25		24
Materials and supplies	68		65
Other regulatory assets	53		60
Other current assets	41		20
Total current assets	801		344
Property, Plant, and Equipment:
In service	5,053		5,011
Less: Accumulated provision for depreciation	1,556		1,545
Plant in service, net of depreciation	3,497		3,466
Construction work in progress	126		146
Total property, plant, and equipment	3,623		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	213		201
Other regulatory assets, deferred	375		388
Accumulated deferred income taxes	123		129
Other deferred charges and assets	66		55
Total deferred charges and other assets	808		805
Total Assets	$	5,412	$	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 June 30, 2021		At December 31, 2020
	(in millions)
Current Liabilities:
Securities due within one year	$	421	$	406
Notes payable	—		25
Accounts payable —
Affiliated	71		63
Other	66		109
Accrued taxes	63		114
Accrued interest	15		15
Accrued compensation	24		34
Asset retirement obligations	36		27
Over recovered regulatory clause liabilities	12		34
Other regulatory liabilities	62		49
Other current liabilities	51		40
Total current liabilities	821		916
Long-term Debt	1,512		1,013
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	460		447
Deferred credits related to income taxes	283		287
Employee benefit obligations	102		113
Asset retirement obligations, deferred	135		150
Other cost of removal obligations	193		194
Other regulatory liabilities, deferred	26		15
Other deferred credits and liabilities	31		35
Total deferred credits and other liabilities	1,230		1,241
Total Liabilities	3,563		3,170
Common Stockholder's Equity (See accompanying statements)	1,849		1,742
Total Liabilities and Stockholder's Equity	$	5,412	$	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
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

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

32

    Table of Contents                                Index to Financial Statements

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	373	$	343	$	728	$	629
Wholesale revenues, affiliates	112		92		193		178
Other revenues	5		4		9		7
Total operating revenues	490		439		930		814
Operating Expenses:
Fuel	140		102		281		209
Purchased power	25		18		46		32
Other operations and maintenance	111		77		211		156
Depreciation and amortization	132		121		251		239
Taxes other than income taxes	12		10		24		19
(Gain) loss on dispositions, net	—		—		(39)		(39)
Total operating expenses	420		328		774		616
Operating Income	70		111		156		198
Other Income and (Expense):
Interest expense, net of amounts capitalized	(37)		(38)		(75)		(77)
Other income (expense), net	1		1		8		4
Total other income and (expense)	(36)		(37)		(67)		(73)
Earnings Before Income Taxes	34		74		89		125
Income taxes (benefit)	(2)		6		(11)		13
Net Income	36		68		100		112
Net income (loss) attributable to noncontrolling interests	—		5		(33)		(26)
Net Income Attributable to Southern Power	$	36	$	63	$	133	$	138

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Net Income	$	36	$	68	$	100	$	112
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of    $2, $4, $(8), and $(17), respectively	6		11		(26)		(50)
Reclassification adjustment for amounts included in net income,    net of tax of $(3), $(5), $13, and $5, respectively	(9)		(15)		38		13
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income,    net of tax of $1, $—, $1, and $—, respectively	—		1		1		1
Total other comprehensive income (loss)	(3)		(3)		13		(36)
Comprehensive Income	33		65		113		76
Comprehensive income (loss) attributable to noncontrolling interests	—		5		(33)		(26)
Comprehensive Income Attributable to Southern Power	$	33	$	60	$	146	$	102

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

33

    Table of Contents                                Index to Financial Statements

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2021		2020
	(in millions)
Operating Activities:
Net income	$	100	$	112
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	264		251
Deferred income taxes	(20)		(34)
Utilization of federal investment tax credits	205		—
Amortization of investment tax credits	(29)		(30)
(Gain) loss on dispositions, net	(39)		(39)
Other, net	(18)		(31)
Changes in certain current assets and liabilities —
-Receivables	(91)		(67)
-Prepaid income taxes	28		73
-Other current assets	2		(8)
-Accounts payable	14		(29)
-Accrued taxes	8		16
-Other current liabilities	(13)		(19)
Net cash provided from operating activities	411		195
Investing Activities:
Business acquisitions, net of cash acquired	(345)		(81)
Property additions	(224)		(101)
Proceeds from dispositions	17		660
Change in construction payables	(14)		(4)
Payments pursuant to LTSAs	(47)		(31)
Other investing activities	12		47
Net cash provided from (used for) investing activities	(601)		490
Financing Activities:
Decrease in notes payable, net	(56)		(357)
Proceeds — Senior notes	400		—
Redemptions —
Short-term borrowings	—		(100)
Senior notes	—		(300)
Return of capital to parent company	(271)		—
Capital contributions from noncontrolling interests	343		172
Distributions to noncontrolling interests	(113)		(118)
Payment of common stock dividends	(102)		(100)
Other financing activities	(5)		(5)
Net cash provided from (used for) financing activities	196		(808)
Net Change in Cash, Cash Equivalents, and Restricted Cash	6		(123)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	183		279
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	189	$	156
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $2 and $7 capitalized for 2021 and 2020, respectively)	$	91	$	96
Income taxes, net	(189)		(5)
Noncash transactions —
Contributions from noncontrolling interests	89		9
Contributions of wind turbine equipment	82		17
Accrued property additions at end of period	59		38
Right-of-use assets obtained under operating leases	65		30

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

34

    Table of Contents                                Index to Financial Statements

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2021		At December 31, 2020
	(in millions)
Current Assets:
Cash and cash equivalents	$	165	$	182
Receivables —
Customer accounts, net	168		125
Affiliated	52		37
Other	48		27
Materials and supplies	101		157
Prepaid income taxes	153		11
Other current assets	56		36
Total current assets	743		575
Property, Plant, and Equipment:
In service	14,372		13,904
Less: Accumulated provision for depreciation	2,991		2,842
Plant in service, net of depreciation	11,381		11,062
Construction work in progress	250		127
Total property, plant, and equipment	11,631		11,189
Other Property and Investments:
Intangible assets, net of amortization of $99 and $89, respectively	292		302
Equity investments in unconsolidated subsidiaries	84		19
Total other property and investments	376		321
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	476		415
Prepaid LTSAs	179		155
Accumulated deferred income taxes	—		262
Income taxes receivable, non-current	31		25
Other deferred charges and assets	272		293
Total deferred charges and other assets	958		1,150
Total Assets	$	13,708	$	13,235

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

35

    Table of Contents                                Index to Financial Statements

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At June 30, 2021		At December 31, 2020
	(in millions)
Current Liabilities:
Securities due within one year	$	1,012	$	299
Notes payable	119		175
Accounts payable —
Affiliated	75		65
Other	90		92
Accrued taxes —
Accrued income taxes	7		8
Other accrued taxes	20		22
Accrued interest	24		32
Other current liabilities	116		132
Total current liabilities	1,463		825
Long-term Debt	3,036		3,393
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	221		123
Accumulated deferred ITCs	1,643		1,672
Operating lease obligations	488		426
Other deferred credits and liabilities	167		165
Total deferred credits and other liabilities	2,519		2,386
Total Liabilities	7,018		6,604
Total Stockholders' Equity (See accompanying statements)	6,690		6,631
Total Liabilities and Stockholders' Equity	$	13,708	$	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

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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

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 June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Operating Revenues:
Natural gas revenues (includes revenue taxes of    $23, $22, $77, and $69, respectively)	$	675	$	638	$	2,367	$	1,878
Alternative revenue programs	2		(2)		4		7
Total operating revenues	677		636		2,371		1,885
Operating Expenses:
Cost of natural gas	231		144		814		583
Other operations and maintenance	233		220		532		479
Depreciation and amortization	133		123		263		243
Taxes other than income taxes	49		47		130		118
Total operating expenses	646		534		1,739		1,423
Operating Income	31		102		632		462
Other Income and (Expense):
Earnings (loss) from equity method investments	(52)		30		(11)		72
Interest expense, net of amounts capitalized	(59)		(57)		(118)		(114)
Other income (expense), net	(14)		12		(78)		21
Total other income and (expense)	(125)		(15)		(207)		(21)
Earnings (Loss) Before Income Taxes	(94)		87		425		441
Income taxes (benefit)	(29)		16		92		95
Net Income (Loss)	$	(65)	$	71	$	333	$	346

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Net Income (Loss)	$	(65)	$	71	$	333	$	346
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of    $3, $(1), $3, and $(8), respectively	8		(1)		9		(21)
Reclassification adjustment for amounts included in net income,    net of tax of $—, $—, $1, and $2, respectively	—		1		3		6
Total other comprehensive income (loss)	8		—		12		(15)
Comprehensive Income (Loss)	$	(57)	$	71	$	345	$	331

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 Six Months Ended June 30,
	2021		2020
	(in millions)
Operating Activities:
Net income	$	333	$	346
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	263		243
Deferred income taxes	110		40
Mark-to-market adjustments	137		34
Impairment of PennEast Pipeline investment	82		—
Natural gas cost under recovery – long-term	(119)		—
Other, net	15		11
Changes in certain current assets and liabilities —
-Receivables	262		344
-Natural gas for sale, net of temporary LIFO liquidation	375		182
-Prepaid income taxes	(129)		14
-Natural gas cost under recovery	(485)		—
-Other current assets	7		(8)
-Accounts payable	(42)		(176)
-Accrued compensation	17		(31)
-Other current liabilities	(104)		47
Net cash provided from operating activities	722		1,046
Investing Activities:
Property additions	(635)		(647)
Cost of removal, net of salvage	(44)		(31)
Investment in unconsolidated subsidiaries	(3)		(78)
Proceeds from dispositions	—		178
Other investing activities	14		8
Net cash used for investing activities	(668)		(570)
Financing Activities:
Increase (decrease) in notes payable, net	210		(321)
Proceeds — Short-term borrowings	300		—
Redemptions —
Senior notes	(300)		—
Medium-term notes	(30)		—
Capital contributions from parent company	60		186
Payment of common stock dividends	(265)		(266)
Net cash used for financing activities	(25)		(401)
Net Change in Cash, Cash Equivalents, and Restricted Cash	29		75
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	19		49
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	48	$	124
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $3 and $4 capitalized for 2021 and 2020, respectively)	$	127	$	119
Income taxes, net	100		(4)
Noncash transactions — Accrued property additions at end of period	137		123

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 June 30, 2021		At December 31, 2020
	(in millions)
Current Assets:
Cash and cash equivalents	$	37	$	17
Receivables —
Energy marketing	—		516
Customer accounts	283		353
Unbilled revenues	74		219
Affiliated	3		4
Other accounts and notes	31		51
Accumulated provision for uncollectible accounts	(45)		(40)
Natural gas for sale	178		460
Prepaid expenses	162		48
Assets from risk management activities, net of collateral	22		118
Natural gas cost under recovery	485		—
Assets held for sale	736		—
Other regulatory assets	97		102
Other current assets	40		38
Total current assets	2,103		1,886
Property, Plant, and Equipment:
In service	18,051		17,611
Less: Accumulated depreciation	4,942		4,821
Plant in service, net of depreciation	13,109		12,790
Construction work in progress	790		648
Total property, plant, and equipment	13,899		13,438
Other Property and Investments:
Goodwill	5,015		5,015
Equity investments in unconsolidated subsidiaries	1,189		1,290
Other intangible assets, net of amortization of $138 and $195, respectively	44		51
Miscellaneous property and investments	19		19
Total other property and investments	6,267		6,375
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	72		81
Other regulatory assets, deferred	697		615
Other deferred charges and assets	197		235
Total deferred charges and other assets	966		931
Total Assets	$	23,235	$	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 June 30, 2021		At December 31, 2020
	(in millions)
Current Liabilities:
Securities due within one year	$	48	$	333
Notes payable	834		324
Energy marketing trade payables	—		494
Accounts payable —
Affiliated	50		56
Other	311		373
Customer deposits	75		90
Accrued taxes	79		83
Accrued interest	55		58
Accrued compensation	105		106
Temporary LIFO liquidation	182		—
Liabilities held for sale	677		—
Other regulatory liabilities	39		122
Other current liabilities	125		150
Total current liabilities	2,580		2,189
Long-term Debt	6,234		6,293
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,413		1,265
Deferred credits related to income taxes	831		847
Employee benefit obligations	267		283
Operating lease obligations	59		67
Other cost of removal obligations	1,673		1,649
Accrued environmental remediation	208		216
Other deferred credits and liabilities	41		54
Total deferred credits and other liabilities	4,492		4,381
Total Liabilities	13,306		12,863
Common Stockholder's Equity (See accompanying statements)	9,929		9,767
Total Liabilities and Stockholder's Equity	$	23,235	$	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
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

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	48
C	Contingencies	57
D	Revenue from Contracts with Customers and Lease Income	60
E	Consolidated Entities and Equity Method Investments	67
F	Financing	69
G	Income Taxes	70
H	Retirement Benefits	71
I	Fair Value Measurements	74
J	Derivatives	79
K	Acquisitions and Dispositions	91
L	Segment and Related Information	93

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
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 June 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 June 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 June 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	$	(142)	$	70	$	212	$	(135)	$	77
Trade names	64		(35)		29		64		(31)		33
Storage and transportation contracts(*)	—		—		—		64		(64)		—
PPA fair value adjustments	390		(99)		291		390		(89)		301
Other	11		(10)		1		10		(9)		1
Total other intangible assets subject to amortization	$	677	$	(286)	$	391	$	740	$	(328)	$	412
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—		75		75		—		75
Total other intangible assets	$	752	$	(286)	$	466	$	815	$	(328)	$	487
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	390	$	(99)	$	291	$	390	$	(89)	$	301
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	156	$	(124)	$	32	$	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	$	(138)	$	44	$	246	$	(195)	$	51

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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Six Months Ended
	June 30, 2021
	(in millions)
Southern Company(a)	$	10	$	21
Southern Power(b)	5		10
Southern Company Gas(c)	3		7

(a)Includes $5 million and $10 million for the three and six months ended June 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
	June 30, 2021		December 31, 2020		June 30, 2021		June 30, 2021		December 31, 2020
	(in millions)				(in millions)		(in millions)
Cash and cash equivalents	$	1,582	$	1,065	$	165	$	37	$	17
Cash and cash equivalents classified as held for sale	8		—		—		8		—
Restricted cash(a):
Other current assets	2		2		—		2		2
Other deferred charges and assets	24		—		24		—		—
Total cash, cash equivalents, and restricted cash(b)	$	1,617	$	1,068	$	189	$	48	$	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' natural gas distribution utilities record natural gas inventories on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated.

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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

(B) REGULATORY MATTERS

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

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

Regulatory Clause	Balance Sheet Line Item	June 30, 2021		December 31, 2020
		(in millions)
Alabama Power
Rate CNP Compliance	Other regulatory liabilities, current	$	1	$	28
Rate CNP PPA	Other regulatory assets, deferred	64		58
Retail Energy Cost Recovery	Other regulatory liabilities, current	—		18
	Other regulatory assets, deferred	54		—
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	21		—
Mississippi Power
Fuel Cost Recovery	Over recovered regulatory clause liabilities	$	9	$	24
Ad Valorem Tax	Other regulatory assets, current	12		11
	Other regulatory assets, deferred	45		41
Property Damage Reserve	Other regulatory liabilities, deferred	—		4
	Other regulatory assets, deferred	5		—
Southern Company Gas
Natural Gas Cost Recovery(*)	Other regulatory liabilities	$	5	$	88
	Natural gas cost under recovery	485		—
	Other regulatory assets, deferred	119		—

(*)The significant change during the six months ended June 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. At June 30, 2021, expenditures associated with the construction of Plant Barry Unit 8 included in CWIP totaled approximately $188 million. The ultimate outcome of this matter cannot be determined at this time.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

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 April 15, 2021, Mississippi Power filed its 2021 IRP with the Mississippi PSC, which includes a schedule to retire its 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. Mississippi Power's IRP is subject to a review period during which the Mississippi PSC may note any deficiencies which could require re-evaluation or resubmission of the IRP. If no deficiencies are noted, the Mississippi PSC's review will conclude on August 13, 2021.

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 Mississippi Power's IRP and associated regulatory processes, as well as 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 June 30, 2021, Alabama Power's NDR balance was $36 million. As a result, effective with October 2021 billings, the reserve maintenance charge component of Rate NDR will be suspended and the reserve establishment charge will be 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.

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 January 5, 2021, the Sierra Club filed a notice of appeal with the Georgia Court of Appeals. 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 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.

The request includes an annual rate increase totaling approximately $370 million to be effective the month after Unit 3 is placed in service. Unit 3 is projected to be placed in service in the second quarter 2022. This increase will be partially offset by a decrease in the NCCR tariff of approximately $116 million expected to be effective January 1, 2022. In addition, an estimated $45 million of fuel cost savings related to Unit 3 is already incorporated in Georgia Power's current fuel cost recovery rates.

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Georgia Power also is requesting to defer some of its 2022 financing costs (approximately $42 million) relating to the remaining portion of the total Unit 3 and Common Facilities construction costs not being recovered through the NCCR tariff until Unit 4 costs are placed in retail base rates.

The Georgia PSC is scheduled to issue a final order in this proceeding on November 2, 2021. The ultimate outcome of this matter cannot be determined at this time. See "Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

Deferral of Incremental COVID-19 Costs

In June 2021, Georgia Power performed 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 of the review, Georgia Power reduced the balance of deferred incremental costs by approximately $20 million. At June 30, 2021, the incremental costs deferred totaled approximately $20 million, including approximately $2 million of incremental bad debt costs and $18 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.

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.

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Cost and Schedule

Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4, including contingency, through June 2022 and March 2023, respectively, is as follows:

	(in millions)
Base project capital cost forecast(a)(b)	$	9,096
Construction contingency estimate	119
Total project capital cost forecast(a)(b)	9,215
Net investment at June 30, 2021(b)	(7,856)
Remaining estimate to complete	$	1,359

(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 $290 million, of which $143 million had been accrued through June 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 $2.7 billion had been incurred through June 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. The site has experienced an overall decline in the number of active cases since a peak in January 2021. 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 and fuel load for Unit 3. Hot functional testing for Unit 3 was completed in July 2021. 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. The site work plan currently targets fuel load for Unit 3 in the fourth quarter 2021 and an in-service date of March 2022. As the site work plan includes minimal margin to these milestone dates, an in-service date in the second quarter 2022 for Unit 3 is projected, although any further delays could result in a later in-service date.

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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. The site work plan targets an in-service date of November 2022 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 first 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. Considering the factors above, during the second quarter 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 described above, 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.

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 and the second quarter 2021 of $48 million ($36 million after tax) and $460 million ($343 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. 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.

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In September 2020, Southern Nuclear notified the NRC of its intent to load fuel for Unit 3 in 2021. 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 second quarter 2022 for Unit 3 or the first 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. 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

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(resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests. If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option at the time the project budget forecast is so revised to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion.

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

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

Regulatory Matters

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At June 30, 2021, Georgia Power had recovered approximately $2.6 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. In November 2020, the Georgia PSC approved Georgia Power's request to decrease the NCCR tariff by $142 million annually, effective January 1, 2021.

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

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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 upon Unit 3 reaching 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, $270 million, and $90 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 23 VCM reports covering periods through June 30, 2020 and is scheduled to vote on the twenty-fourth VCM report in August 2021, including total construction capital costs incurred through December 31, 2020 of $8.7 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). On July 28, 2021, Georgia Power and the staff of the Georgia PSC reached a stipulated agreement providing for approval of the twenty-fourth VCM report as well as a change to future VCM proceedings. Beginning with its twenty-fifth VCM report, which Georgia Power expects to file with the Georgia PSC by August 31, 2021, Georgia Power will continue to report to the Georgia PSC all costs incurred during the period for review and will include a request for approval of costs up to the $7.3 billion determined to be reasonable in the Georgia PSC's seventeenth VCM order. Under the stipulation, Georgia Power will not seek verification or approval of costs above $7.3 billion prior to the Georgia PSC's prudence review contemplated by the seventeenth VCM order. The twenty-fifth VCM report will reflect the revised capital cost forecast discussed above. 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

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by year-end 2027 to reduce Mississippi Power's excess reserve margin. On April 15, 2021, Mississippi Power filed its 2021 IRP with the Mississippi PSC. The filing 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 $522 million at June 30, 2021. Mississippi Power expects to reclassify the net book value remaining at retirement 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 2021 IRP is subject to a review period during which the Mississippi PSC may note any deficiencies which could require re-evaluation or resubmission of the IRP. If no deficiencies are noted, the Mississippi PSC's review will conclude on August 13, 2021.

The ultimate outcome of this matter 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.

Southern Company Gas

Infrastructure Replacement Programs and Capital Projects

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

Utility	Program	Six Months Ended June 30, 2021
		(in millions)
Nicor Gas	Investing in Illinois	$	179
Virginia Natural Gas	Steps to Advance Virginia's Energy	22
Total		$	201

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.

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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. The Georgia PSC is scheduled to vote on this matter in November 2021. The ultimate outcome of this matter cannot be determined at this time.

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 May 10, 2021, Virginia Natural Gas, the Virginia Commission staff, and other intervenors entered into 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%. On July 8, 2021, the hearing examiner issued a report recommending adoption of the stipulation agreement. The Virginia Commission is expected to rule on this matter by September 2021. 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. The ultimate outcome of this matter cannot be determined at this time.

Atlanta Gas Light

On July 21, 2021, Atlanta Gas Light filed its annual GRAM filing with the Georgia PSC. The filing requests an annual base rate increase of $49 million based on the projected 12-month period beginning January 1, 2022. The proposed rate increase may be updated pending the resolution of Atlanta Gas Light's i-CDP filing. 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 "Infrastructure Replacement Programs and Capital Projects – Atlanta Gas Light" herein for additional information.

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. Nicor Gas will continue certain flexible credit and collection procedures through the third quarter 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.

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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. The parties in each case did not reach settlement but continue to explore possible resolution. Each case is stayed while the parties discuss potential resolution.

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.

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(UNAUDITED)

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. The amount of any possible losses 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 $15 million at both June 30, 2021 and December 31, 2020. 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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(UNAUDITED)

Southern Company Gas' environmental remediation liability was $247 million and $245 million at June 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

Work continues with state and federal agencies to obtain the required permits to begin construction of the PennEast Pipeline. 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). The ultimate outcome of the PennEast Pipeline construction project cannot be determined at this time. 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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(UNAUDITED)

The following table disaggregates revenue from contracts with customers for the three and six months ended June 30, 2021 and 2020:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended June 30, 2021
Operating revenues
Retail electric revenues
Residential	$	1,469	$	553	$	852	$	64	$	—	$	—
Commercial	1,176		386		724		66		—		—
Industrial	728		334		321		73		—		—
Other	23		4		17		2		—		—
Total retail electric revenues	3,396		1,277		1,914		205		—		—
Natural gas distribution revenues
Residential	311		—		—		—		—		311
Commercial	73		—		—		—		—		73
Transportation	247		—		—		—		—		247
Industrial	8		—		—		—		—		8
Other	59		—		—		—		—		59
Total natural gas distribution revenues	698		—		—		—		—		698
Wholesale electric revenues
PPA energy revenues	209		38		16		2		158		—
PPA capacity revenues	118		29		14		1		75		—
Non-PPA revenues	55		25		3		75		78		—
Total wholesale electric revenues	382		92		33		78		311		—
Other natural gas revenues
Wholesale gas services	578		—		—		—		—		578
Gas marketing services	63		—		—		—		—		63
Other natural gas revenues	10		—		—		—		—		10
Total natural gas revenues	651		—		—		—		—		651
Other revenues	295		52		137		7		5		—
Total revenue from contracts with customers	5,422		1,421		2,084		290		316		1,349
Other revenue sources(a)	1,179		135		141		13		174		731
Other adjustments(b)	(1,403)		—		—		—		—		(1,403)
Total operating revenues	$	5,198	$	1,556	$	2,225	$	303	$	490	$	677

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(UNAUDITED)

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Six Months Ended June 30, 2021
Operating revenues
Retail electric revenues
Residential	$	2,936	$	1,181	$	1,627	$	128	$	—	$	—
Commercial	2,294		758		1,410		126		—		—
Industrial	1,397		654		606		137		—		—
Other	47		9		34		4		—		—
Total retail electric revenues	6,674		2,602		3,677		395		—		—
Natural gas distribution revenues
Residential	925		—		—		—		—		925
Commercial	243		—		—		—		—		243
Transportation	536		—		—		—		—		536
Industrial	24		—		—		—		—		24
Other	155		—		—		—		—		155
Total natural gas distribution revenues	1,883		—		—		—		—		1,883
Wholesale electric revenues
PPA energy revenues	422		81		30		7		313		—
PPA capacity revenues	237		58		27		4		150		—
Non-PPA revenues	119		57		12		162		139		—
Total wholesale electric revenues	778		196		69		173		602		—
Other natural gas revenues
Wholesale gas services	2,168		—		—		—		—		2,168
Gas marketing services	257		—		—		—		—		257
Other natural gas revenues	17		—		—		—		—		17
Total natural gas revenues	2,442		—		—		—		—		2,442
Other revenues	542		97		249		14		9		—
Total revenue from contracts with customers	12,319		2,895		3,995		582		611		4,325
Other revenue sources(a)	2,488		220		200		28		319		1,745
Other adjustments(b)	(3,699)		—		—		—		—		(3,699)
Total operating revenues	$	11,108	$	3,115	$	4,195	$	610	$	930	$	2,371

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(UNAUDITED)

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended June 30, 2020
Operating revenues
Retail electric revenues
Residential	$	1,430	$	549	$	817	$	64	$	—	$	—
Commercial	1,103		353		689		61		—		—
Industrial	642		302		273		67		—		—
Other	23		6		15		2		—		—
Total retail electric revenues	3,198		1,210		1,794		194		—		—
Natural gas distribution revenues
Residential	239		—		—		—		—		239
Commercial	58		—		—		—		—		58
Transportation	234		—		—		—		—		234
Industrial	5		—		—		—		—		5
Other	49		—		—		—		—		49
Total natural gas distribution revenues	585		—		—		—		—		585
Wholesale electric revenues
PPA energy revenues	167		28		7		2		134		—
PPA capacity revenues	108		25		13		1		71		—
Non-PPA revenues	50		5		2		73		59		—
Total wholesale electric revenues	325		58		22		76		264		—
Other natural gas revenues
Wholesale gas services	341		—		—		—		—		341
Gas marketing services	57		—		—		—		—		57
Other natural gas revenues	8		—		—		—		—		8
Total natural gas revenues	406		—		—		—		—		406
Other revenues	251		44		119		6		4		—
Total revenue from contracts with customers	4,765		1,312		1,935		276		268		991
Other revenue sources(a)	728		53		(7)		7		171		518
Other adjustments(b)	(873)		—		—		—		—		(873)
Total operating revenues	$	4,620	$	1,365	$	1,928	$	283	$	439	$	636

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(UNAUDITED)

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Six Months Ended June 30, 2020
Operating revenues
Retail electric revenues
Residential	$	2,801	$	1,103	$	1,577	$	121	$	—	$	—
Commercial	2,247		717		1,409		121		—		—
Industrial	1,323		623		555		145		—		—
Other	46		11		31		4		—		—
Total retail electric revenues	6,417		2,454		3,572		391		—		—
Natural gas distribution revenues
Residential	736		—		—		—		—		736
Commercial	188		—		—		—		—		188
Transportation	499		—		—		—		—		499
Industrial	17		—		—		—		—		17
Other	144		—		—		—		—		144
Total natural gas distribution revenues	1,584		—		—		—		—		1,584
Wholesale electric revenues
PPA energy revenues	326		55		15		4		259		—
PPA capacity revenues	213		52		25		2		136		—
Non-PPA revenues	100		24		4		142		117		—
Total wholesale electric revenues	639		131		44		148		512		—
Other natural gas revenues
Wholesale gas services	737		—		—		—		—		737
Gas marketing services	220		—		—		—		—		220
Other natural gas revenues	15		—		—		—		—		15
Total natural gas revenues	972		—		—		—		—		972
Other revenues	441		78		214		13		7		—
Total revenue from contracts with customers	10,053		2,663		3,830		552		519		2,556
Other revenue sources(a)	1,599		53		(76)		7		295		1,343
Other adjustments(b)	(2,014)		—		—		—		—		(2,014)
Total operating revenues	$	9,638	$	2,716	$	3,754	$	559	$	814	$	1,885

(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 June 30, 2021 and December 31, 2020:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Accounts Receivable
At June 30, 2021	$	2,271	$	633	$	887	$	85	$	129	$	368
At December 31, 2020	2,614		632		806		77		112		788
Contract Assets
At June 30, 2021	$	98	$	—	$	36	$	—	$	1	$	—
At December 31, 2020	158		2		71		—		—		—
Contract Liabilities
At June 30, 2021	$	67	$	5	$	37	$	1	$	1	$	—
At December 31, 2020	61		6		27		1		1		1

At June 30, 2021 and December 31, 2020, Georgia Power had contract assets primarily related to unregulated service agreements, where payment is contingent on project completion, as well as, at December 31, 2020, contract assets 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. 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 $60 million and $81 million of contract assets and $24 million and $27 million of contract liabilities at June 30, 2021 and December 31, 2020, respectively, for outstanding performance obligations.

Revenues recognized by Southern Company in the three and six months ended June 30, 2021, which were included in contract liabilities at December 31, 2020, were $12 million and $21 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 June 30, 2021 are expected to be recognized as follows:

	2021 (remaining)		2022		2023		2024		2025		Thereafter
	(in millions)
Southern Company	$	354	$	464	$	343	$	327	$	307	$	2,667
Alabama Power	23		31		24		7		5		—
Georgia Power	41		58		39		23		21		41
Southern Power	165		323		281		297		281		2,644

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(UNAUDITED)

Revenue expected to be recognized for performance obligations remaining at June 30, 2021 was immaterial for Mississippi Power and Southern Company Gas.

Lease Income

Lease income for the three and six months ended June 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 June 30, 2021
Lease income - interest income on sales-type leases	$	4	$	—	$	—	$	4	$	—	$	—
Lease income - operating leases	56		21		10		—		21		9
Variable lease income	128		(1)		—		—		138		—
Total lease income	$	188	$	20	$	10	$	4	$	159	$	9
For the Six Months Ended June 30, 2021
Lease income - interest income on sales-type leases	$	7	$	—	$	—	$	7	$	—	$	—
Lease income - operating leases	112		41		21		1		42		17
Variable lease income	212		—		—		—		228		—
Total lease income	$	331	$	41	$	21	$	8	$	270	$	17
For the Three Months Ended June 30, 2020
Lease income - interest income on sales-type leases	$	3	$	—	$	—	$	3	$	—	$	—
Lease income - operating leases	47		6		15		—		21		9
Variable lease income	126		—		—		—		136		—
Total lease income	$	176	$	6	$	15	$	3	$	157	$	9
For the Six Months Ended June 30, 2020
Lease income - interest income on sales-type leases	$	6	$	—	$	—	$	5	$	—	$	—
Lease income - operating leases	97		13		30		—		45		17
Variable lease income	200		—		—		—		215		—
Total lease income	$	303	$	13	$	30	$	5	$	260	$	17

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 completed construction of additional leased assets under an existing sales-type lease during the second quarter 2021. Upon completion of construction, the book value of $35 million was transferred from CWIP to lease receivables and is primarily included in other property and investments at June 30, 2021. The transfer represents a noncash investing transaction for purposes of the statements of cash flows.

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(UNAUDITED)

(E) CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS

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

Southern Power

Variable Interest Entities

Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests.

SP Solar and SP Wind

At June 30, 2021 and December 31, 2020, SP Solar had total assets of $6.2 billion and $6.1 billion, respectively, total liabilities of $382 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 June 30, 2021 and December 31, 2020, SP Wind had total assets of $2.3 billion and $2.4 billion, respectively, total liabilities of $140 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 June 30, 2021 and December 31, 2020, the other VIEs had total assets of $1.9 billion and $1.1 billion, respectively, total liabilities of $249 million and $110 million, respectively, and noncontrolling interests of $913 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 June 30, 2021 and December 31, 2020, Southern Power had equity method investments in wind and battery storage projects totaling $84 million and $19 million, respectively.

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(UNAUDITED)

Southern Company Gas

Equity Method Investments

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

Investment Balance	June 30, 2021		December 31, 2020
	(in millions)
SNG	$	1,143	$	1,167
PennEast Pipeline(*)	13		91
Other	33		32
Total	$	1,189	$	1,290

(*)Investment balance at June 30, 2021 reflects a pre-tax impairment charge of $82 million ($58 million after tax) recorded in the second quarter 2021. See Note (C) under "Other Matters – Southern Company Gas" for additional information.

	Three Months Ended June 30,				Six Months Ended June 30,
Earnings (Loss) from Equity Method Investments	2021		2020		2021		2020
	(in millions)
SNG	$	28	$	28	$	66	$	65
PennEast Pipeline(a)(b)	(81)		1		(79)		3
Other(a)(c)	1		1		2		4
Total	$	(52)	$	30	$	(11)	$	72

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

(b)Includes a pre-tax impairment charge of $82 million ($58 million after tax) for the three and six months ended June 30, 2021. See Note (C) under "Other Matters – Southern Company Gas" for additional information.

(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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(UNAUDITED)

(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 June 30, 2021, committed credit arrangements with banks were as follows:

	Expires
Company	2021		2022		2023		2024		2026		Total		Unused		Due within One Year
	(in millions)
Southern Company parent	$	—	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—
Alabama Power	3		525		—		—		700		1,228		1,228		3
Georgia Power	—		—		—		—		1,750		1,750		1,728		—
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	$	3	$	805	$	125	$	150	$	6,550	$	7,633	$	7,550	$	283

(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 June 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.

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 June 30, 2021, the Registrants, Nicor Gas, and

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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 June 30, 2021 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, and $34 million at Mississippi Power). In addition, at June 30, 2021, Georgia Power and Mississippi Power had approximately $105 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 June 30,		Six Months Ended June 30,
	2021	2020	2021	2020
	(in millions)
As reported shares	1,061	1,058	1,060	1,057
Effect of stock-based compensation	6	5	6	7
Effect of equity units	—	—	—	1
Diluted shares	1,067	1,063	1,066	1,065

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

(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 $1.3 billion at June 30, 2021 compared to $1.4 billion at December 31, 2020.

The federal ITC and PTC carryforwards begin expiring in 2034 and 2032, respectively, but are expected to be fully utilized by 2024. The utilization of each 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.

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Effective Tax Rate

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

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

Georgia Power

Georgia Power's effective tax benefit rate was (6.9)% for the six months ended June 30, 2021 compared to an effective tax rate of 4.0% 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. See Note (B) under "Georgia Power – Nuclear Construction" for additional information.

Southern Power

Southern Power's effective tax benefit rate was (12.8)% for the six months ended June 30, 2021 compared to an effective tax rate of 10.5% 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.

(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 six months ended June 30, 2021 and 2020 are presented in the following tables.

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(UNAUDITED)

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended June 30, 2021
Pension Plans
Service cost	$	108	$	25	$	28	$	5	$	3	$	9
Interest cost	86		21		26		4		1		6
Expected return on plan assets	(297)		(71)		(94)		(13)		(4)		(22)
Amortization:
Prior service costs	—		—		1		—		—		—
Regulatory asset	—		—		—		—		—		4
Net (gain)/loss	79		20		25		3		1		3
Net periodic pension cost (income)	$	(24)	$	(5)	$	(14)	$	(1)	$	1	$	—
Postretirement Benefits
Service cost	$	6	$	2	$	1	$	—	$	—	$	1
Interest cost	9		2		3		1		—		1
Expected return on plan assets	(19)		(7)		(6)		(1)		—		(2)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		1
Net (gain)/loss	1		—		—		—		—		—
Net periodic postretirement benefit cost (income)	$	(4)	$	(3)	$	(2)	$	—	$	—	$	1
Six Months Ended June 30, 2021
Pension Plans
Service cost	$	217	$	51	$	56	$	9	$	5	$	18
Interest cost	173		41		52		8		2		12
Expected return on plan assets	(595)		(143)		(188)		(27)		(7)		(43)
Amortization:
Prior service costs	—		—		1		—		—		(1)
Regulatory asset	—		—		—		—		—		8
Net (gain)/loss	157		41		50		7		2		6
Net periodic pension cost (income)	$	(48)	$	(10)	$	(29)	$	(3)	$	2	$	—
Postretirement Benefits
Service cost	$	12	$	3	$	3	$	—	$	—	$	1
Interest cost	17		4		6		1		—		2
Expected return on plan assets	(38)		(14)		(13)		(1)		—		(4)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		3
Net (gain)/loss	2		—		1		—		—		(1)
Net periodic postretirement benefit cost (income)	$	(8)	$	(7)	$	(3)	$	—	$	—	$	1

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	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended June 30, 2020
Pension Plans
Service cost	$	94	$	22	$	24	$	4	$	2	$	8
Interest cost	108		25		34		5		2		7
Expected return on plan assets	(275)		(66)		(87)		(12)		(3)		(20)
Amortization:
Prior service costs	—		—		1		—		—		—
Regulatory asset	—		—		—		—		—		4
Net (gain)/loss	67		18		21		3		—		3
Net periodic pension cost (income)	$	(6)	$	(1)	$	(7)	$	—	$	1	$	2
Postretirement Benefits
Service cost	$	6	$	1	$	2	$	1	$	—	$	1
Interest cost	14		3		5		1		—		4
Expected return on plan assets	(18)		(7)		(6)		(1)		—		(2)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		1
Net (gain)/loss	—		—		—		—		—		(1)
Net periodic postretirement benefit cost (income)	$	1	$	(3)	$	1	$	1	$	—	$	3
Six Months Ended June 30, 2020
Pension Plans
Service cost	$	188	$	44	$	48	$	8	$	4	$	16
Interest cost	216		50		67		10		3		15
Expected return on plan assets	(550)		(132)		(174)		(25)		(6)		(39)
Amortization:
Prior service costs	1		—		1		—		—		(1)
Regulatory asset	—		—		—		—		—		8
Net (gain)/loss	134		36		43		6		1		5
Net periodic pension cost (income)	$	(11)	$	(2)	$	(15)	$	(1)	$	2	$	4
Postretirement Benefits
Service cost	$	11	$	3	$	3	$	1	$	—	$	1
Interest cost	27		6		10		1		—		6
Expected return on plan assets	(36)		(14)		(13)		(1)		—		(4)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		3
Net (gain)/loss	1		—		1		—		—		(2)
Net periodic postretirement benefit cost (income)	$	2	$	(5)	$	1	$	1	$	—	$	4

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(UNAUDITED)

(I) FAIR VALUE MEASUREMENTS

At June 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 June 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)	$	656	$	436	$	28	$	—	$	1,120
Interest rate derivatives	—		17		—		—		17
Foreign currency derivatives	—		55		—		—		55
Investments in trusts:(b)(c)
Domestic equity	812		236		—		—		1,048
Foreign equity	171		191		—		—		362
U.S. Treasury and government agency securities	—		311		—		—		311
Municipal bonds	—		45		—		—		45
Pooled funds – fixed income	—		18		—		—		18
Corporate bonds	4		453		—		—		457
Mortgage and asset backed securities	—		92		—		—		92
Private equity	—		—		—		102		102
Other	29		23		—		—		52
Cash equivalents	1,039		13		—		—		1,052
Other investments	9		30		—		—		39
Total	$	2,720	$	1,920	$	28	$	102	$	4,770
Liabilities:
Energy-related derivatives(a)	$	664	$	333	$	10	$	—	$	1,007
Interest rate derivatives	—		9		—		—		9
Foreign currency derivatives	—		10		—		—		10
Contingent consideration	—		—		16		—		16
Total	$	664	$	352	$	26	$	—	$	1,042

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(UNAUDITED)

	Fair Value Measurements Using:
At June 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	$	—	$	46	$	—	$	—	$	46
Nuclear decommissioning trusts:(b)
Domestic equity	453		226		—		—		679
Foreign equity	171		—		—		—		171
U.S. Treasury and government agency securities	—		22		—		—		22
Municipal bonds	—		1		—		—		1
Corporate bonds	4		241		—		—		245
Mortgage and asset backed securities	—		24		—		—		24
Private equity	—		—		—		102		102
Other	6		—		—		—		6
Cash equivalents	507		13		—		—		520
Other investments	—		30		—		—		30
Total	$	1,141	$	603	$	—	$	102	$	1,846
Liabilities:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Georgia Power
Assets:
Energy-related derivatives	$	—	$	73	$	—	$	—	$	73
Nuclear decommissioning trusts:(b)(c)
Domestic equity	359		1		—		—		360
Foreign equity	—		188		—		—		188
U.S. Treasury and government agency securities	—		289		—		—		289
Municipal bonds	—		44		—		—		44
Corporate bonds	—		212		—		—		212
Mortgage and asset backed securities	—		68		—		—		68
Other	23		23		—		—		46
Total	$	382	$	898	$	—	$	—	$	1,280
Liabilities:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4

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(UNAUDITED)

	Fair Value Measurements Using:
At June 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	$	—	$	44	$	—	$	—	$	44
Cash equivalents	455		—		—		—		455
Total	$	455	$	44	$	—	$	—	$	499
Liabilities:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Southern Power
Assets:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4
Foreign currency derivatives	—		55		—		—		55
Total	$	—	$	59	$	—	$	—	$	59
Liabilities:
Foreign currency derivatives	$	—	$	10	$	—	$	—	$	10
Contingent consideration	—		—		16		—		16
Total	$	—	$	10	$	16	$	—	$	26
Southern Company Gas
Assets:
Energy-related derivatives(a)	$	656	$	269	$	28	$	—	$	953
Interest rate derivatives	—		4		—		—		4
Non-qualified deferred compensation trusts:
Domestic equity	—		9		—		—		9
Foreign equity	—		3		—		—		3
Pooled funds – fixed income	—		18		—		—		18
Total	$	656	$	303	$	28	$	—	$	987
Liabilities:
Energy-related derivatives(a)	$	664	$	323	$	10	$	—	$	997

(a)Includes assets ($626 million, $260 million, and $28 million categorized as Level 1, 2, and 3, respectively) and liabilities ($657 million, $323 million, and $10 million categorized as Level 1, 2, and 3, respectively) related to Sequent, which were classified as held for sale at June 30, 2021. See Note (K) under "Southern Company Gas" and "Assets and Liabilities Held for Sale" for additional information. Excludes cash collateral of $41 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 June 30, 2021, approximately $48 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

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(UNAUDITED)

See Note (K) under "Assets and Liabilities 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 six months ended June 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 June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
	(in millions)
Southern Company	$	125	$	223	$	164	$	(23)
Alabama Power	77		124		118		(42)
Georgia Power	48		99		46		19

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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(UNAUDITED)

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

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

At June 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 $102 million and unfunded commitments related to the private equity investments totaled $67 million. Private equity investments include high-quality private equity funds across several market sectors and funds that invest in real estate assets. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.

At June 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	$	50.4	$	9.3	$	13.5	$	1.9	$	4.0	$	6.3
Fair value	56.2		10.6		15.2		2.1		4.5		7.3

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

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

Commodity Contracts with Level 3 Valuation Inputs

At June 30, 2021, Southern Company Gas had Level 3 physical natural gas forward contracts totaling $18 million related to Sequent, which were classified as held for sale. See Note (K) under "Southern Company Gas" and "Assets and Liabilities Held for Sale" for additional information. Since commodity contracts classified as Level 3 typically include a combination of observable and unobservable components, the changes in fair value may include amounts due in part to observable market factors, or changes to assumptions on the unobservable components. The following table includes transfers to Level 3, which represent the fair value of Southern Company Gas' commodity derivative contracts that include a significant unobservable component for the first time during the period.

	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021
	(in millions)
Beginning balance	$	28	$	28
Instruments realized or otherwise settled during period	(4)		(6)
Changes in fair value	(6)		(4)
Ending balance	$	18	$	18

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

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The valuation of certain commodity contracts requires the use of certain unobservable inputs. All forward pricing used in the valuation of such contracts is directly based on third-party market data, such as broker quotes and exchange settlements, when that data is available. If third-party market data is not available, then industry standard methodologies are used to develop inputs that maximize the use of relevant observable inputs and minimize the use of unobservable inputs. Observable inputs, including some forward prices used for determining fair value, reflect the best available market information. Unobservable inputs are updated using industry standard techniques such as extrapolation, combining observable forward inputs supplemented by historical market and other relevant data. Level 3 physical natural gas forward contracts include unobservable forward price inputs (ranging from $(0.06) to $0.38 per mmBtu). Forward price increases (decreases) at June 30, 2021 would have resulted in higher (lower) values on a net basis.

(J) DERIVATIVES

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Through the sale of Sequent on July 1, 2021, Southern Company Gas' wholesale gas operations used various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with 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.

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

•Regulatory Hedges – Energy-related derivative contracts designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through 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 June 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(*)	978	2030	2031
Alabama Power	73	2024	—
Georgia Power	125	2024	—
Mississippi Power	85	2025	—
Southern Power	9	2030	2022
Southern Company Gas(*)	686	2024	2031

(*)Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 4.6 billion mmBtu and short natural gas positions of 3.9 billion mmBtu at June 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 44 million mmBtu for Southern Company, which includes 11 million mmBtu for Alabama Power, 13 million mmBtu for Georgia Power, 6 million mmBtu for Mississippi Power, and 14 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 June 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. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

At June 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 June 30, 2021
	(in millions)					(in millions)
Cash Flow Hedges of Existing Debt
Mississippi Power	$	60	1-month LIBOR	0.58%	December 2021	$	—
Fair Value Hedges of Existing Debt
Southern Company parent	400		1.75%	1-month LIBOR + 0.68%	March 2028	—
Southern Company parent	1,000		3.70%	1-month LIBOR + 2.36%	April 2030	4
Southern Company Gas	500		1.75%	1-month LIBOR + 0.38%	January 2031	3
Southern Company	$	1,960				$	7

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 June 30, 2022 total $(23) 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. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

At June 30, 2021, Southern Power had the following outstanding foreign currency derivatives designated as cash flow hedges of existing debt:

Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at June 30, 2021
(in millions)			(in millions)				(in millions)
$	677	2.95%	€	600	1.00%	June 2022	$	27
564		3.78%	500		1.85%	June 2026	18
$	1,241		€	1,100			$	45

The estimated pre-tax gains (losses) related to Southern Power's foreign currency derivatives expected to be reclassified from accumulated OCI to earnings for the 12-month period ending June 30, 2022 are $17 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 June 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	$	130	$	2	$	24	$	11
Other deferred charges and assets/Other deferred credits and liabilities	54		8		18		19
Total derivatives designated as hedging instruments for regulatory purposes	$	184	$	10	$	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	$	13	$	—	$	3	$	5
Other deferred charges and assets/Other deferred credits and liabilities	1		—		—		—
Interest rate derivatives:
Assets from risk management activities/Other current liabilities	17		—		20		—
Other deferred charges and assets/Other deferred credits and liabilities	—		9		—		—
Foreign currency derivatives:
Assets from risk management activities/Other current liabilities	27		10		—		23
Other deferred charges and assets/Other deferred credits and liabilities	28		—		87		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	86	$	19	$	110	$	28
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Other current liabilities	$	8	$	7	$	388	$	331
Other deferred charges and assets/Other deferred credits and liabilities	—		—		270		232
Assets held for sale, current/Liabilities held for sale, current	914		990		—		—
Total derivatives not designated as hedging instruments	$	922	$	997	$	658	$	563
Gross amounts recognized	$	1,192	$	1,026	$	810	$	621
Gross amounts offset(a)	(851)		(892)		(529)		(557)
Net amounts recognized in the Balance Sheets(b)	$	341	$	134	$	281	$	64

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	At June 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	$	31	$	1	$	7	$	2
Other deferred charges and assets/Other deferred credits and liabilities	15		2		5		5
Total derivatives designated as hedging instruments for regulatory purposes	$	46	$	3	$	12	$	7
Gross amounts recognized	$	46	$	3	$	12	$	7
Gross amounts offset	(3)		(3)		(7)		(7)
Net amounts recognized in the Balance Sheets	$	43	$	—	$	5	$	—
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	52	$	1	$	7	$	5
Other deferred charges and assets/Other deferred credits and liabilities	21		3		8		8
Total derivatives designated as hedging instruments for regulatory purposes	$	73	$	4	$	15	$	13
Gross amounts recognized	$	73	$	4	$	15	$	13
Gross amounts offset	(4)		(4)		(12)		(12)
Net amounts recognized in the Balance Sheets	$	69	$	—	$	3	$	1
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	28	$	—	$	4	$	3
Other deferred charges and assets/Other deferred credits and liabilities	16		3		5		6
Total derivatives designated as hedging instruments for regulatory purposes	$	44	$	3	$	9	$	9
Gross amounts recognized	$	44	$	3	$	9	$	9
Gross amounts offset	(3)		(3)		(7)		(7)
Net amounts recognized in the Balance Sheets	$	41	$	—	$	2	$	2

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	At June 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	$	4	$	—	$	2	$	2
Foreign currency derivatives:
Other current assets/Other current liabilities	27		10		—		23
Other deferred charges and assets/Other deferred credits and liabilities	28		—		87		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	59	$	10	$	89	$	25
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	—	$	—	$	—	$	1
Total derivatives not designated as hedging instruments	$	—	$	—	$	—	$	1
Net amounts recognized in the Balance Sheets	$	59	$	10	$	89	$	26

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	At June 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	$	19	$	—	$	6	$	1
Other deferred charges and assets/Other deferred credits and liabilities	2		—		—		—
Total derivatives designated as hedging instruments for regulatory purposes	$	21	$	—	$	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	$	9	$	—	$	1	$	3
Other deferred charges and assets/Other deferred credits and liabilities	1		—		—		—
Interest rate derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	4		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	14	$	—	$	1	$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Other current liabilities	$	8	$	7	$	388	$	330
Other deferred charges and assets/Other deferred credits and liabilities	—		—		270		232
Assets held for sale, current/Liabilities held for sale, current	914		990		—		—
Total derivatives not designated as hedging instruments	$	922	$	997	$	658	$	562
Gross amounts of recognized	$	957	$	997	$	665	$	566
Gross amounts offset(a)	(841)		(882)		(503)		(531)
Net amounts recognized in the Balance Sheets(b)	$	116	$	115	$	162	$	35

(a)Gross amounts offset include cash collateral held on deposit in broker margin accounts of $41 million and $28 million at June 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 immaterial energy-related derivatives not designated as hedging instruments at June 30, 2021 and no such instruments at December 31, 2020.

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At June 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 June 30, 2021:
Energy-related derivatives:
Other regulatory liabilities, current	$	120	$	31	$	51	$	28	$	10
Other regulatory liabilities, deferred	46		13		18		14		1
Total energy-related derivative gains (losses)	$	166	$	44	$	69	$	42	$	11
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 six months ended June 30, 2021 and 2020, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows:

Gain (Loss) Recognized in OCI on Derivative	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Southern Company
Energy-related derivatives	$	16	$	(2)	$	20	$	(6)
Interest rate derivatives	(1)		(1)		2		(28)
Foreign currency derivatives	4		17		(43)		(65)
Total	$	19	$	14	$	(21)	$	(99)
Southern Power
Energy-related derivatives	$	5	$	(2)	$	8	$	(2)
Foreign currency derivatives	4		17		(43)		(65)
Total	$	9	$	15	$	(35)	$	(67)
Southern Company Gas
Energy-related derivatives	$	11	$	—	$	12	$	(4)
Interest rate derivatives	—		(1)		—		(25)
Total	$	11	$	(1)	$	12	$	(29)

For the three and six months ended June 30, 2021 and 2020, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for the other Registrants.

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For the three and six months ended June 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 June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Southern Company
Total cost of natural gas	$	231	$	144	$	814	$	583
Gain (loss) on energy-related cash flow hedges(a)	1		(1)		(2)		(8)
Total depreciation and amortization	891		873		1,762		1,730
Gain (loss) on energy-related cash flow hedges(a)	1		(1)		4		(2)
Total interest expense, net of amounts capitalized	(450)		(444)		(901)		(900)
Gain (loss) on interest rate cash flow hedges(a)	(7)		(6)		(14)		(13)
Gain (loss) on foreign currency cash flow hedges(a)	(6)		(6)		(12)		(12)
Gain (loss) on interest rate fair value hedges(b)	(3)		1		(12)		30
Total other income (expense), net	108		101		167		204
Gain (loss) on foreign currency cash flow hedges(a)(c)	17		27		(43)		(4)
Southern Power
Total depreciation and amortization	$	132	$	121	$	251	$	239
Gain (loss) on energy-related cash flow hedges(a)	1		(1)		4		(2)
Total interest expense, net of amounts capitalized	(37)		(38)		(75)		(77)
Gain (loss) on foreign currency cash flow hedges(a)	(6)		(6)		(12)		(12)
Total other income (expense), net	1		1		8		4
Gain (loss) on foreign currency cash flow hedges(a)(c)	17		27		(43)		(4)

(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 six months ended June 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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At June 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 June 30, 2021		At December 31, 2020		At June 30, 2021		At December 31, 2020
	(in millions)				(in millions)
Southern Company
Securities due within one year	$	—	$	(1,509)	$	—	$	(10)
Long-term debt	(1,883)		—		—		—
Southern Company Gas
Long-term debt	$	(492)	$	—	$	3	$	—

For the three and six months ended June 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 June 30,				Six Months Ended June 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(*)	$	(103)	$	14	$	(120)	$	84
	Cost of natural gas	9		5		16		13
Total derivatives in non-designated hedging relationships		$	(94)	$	19	$	(104)	$	97

(*)Excludes immaterial gains (losses) recorded in natural gas revenues associated with weather derivatives for all periods presented.

For the three and six months ended June 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 June 30, 2021, the Registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

At June 30, 2021, the Registrants had no interest rate derivative liabilities with contingent features. At June 30, 2021, the fair value of Southern Company Gas' energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial. At June 30, 2021, the other Registrants had no energy-related derivative liabilities with contingent features. 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.,

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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 June 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 June 30, 2021, cash collateral held on deposit in broker margin accounts was $41 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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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

(K) ACQUISITIONS AND DISPOSITIONS

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

Southern Power

Asset Acquisition

During the six months ended June 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 facility and consolidates the project's operating results in its financial statements. On March 30, 2021, Southern Power completed a tax equity transaction whereby it received $220 million. The tax equity partner, which is the Class A member, and Invenergy Renewables, LLC each own a noncontrolling interest.

Construction Projects

During the six months ended June 30, 2021, Southern Power continued construction of the Garland and Tranquillity battery energy storage facilities and the Glass Sands wind facility. Total aggregate construction costs, excluding acquisition costs, are expected to be between $390 million and $460 million for the facilities under construction. At June 30, 2021, total costs of construction incurred for these projects were $208 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time.

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
Projects Under Construction at June 30, 2021
Garland Solar Storage(a)	Battery energy storage system	88	Kern County, CA	August 2021	20 years
Tranquillity Solar Storage(a)	Battery energy storage system	72	Fresno County, CA	Fourth quarter 2021	20 years
Glass Sands(b)	Wind	118	Murray County, OK	Fourth quarter 2021	12 years

(a)Subsequent to June 30, 2021, Southern Power further restructured its ownership in the Garland battery energy storage project and completed a tax equity transaction whereby it received initial proceeds of $11 million, while retaining the controlling interest. Prior to commercial operation, Southern Power expects to further restructure its ownership in the Tranquillity battery energy storage project and complete a tax equity transaction, but expects to retain the controlling interest. The ultimate outcome of this matter cannot be determined at this time.

(b)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 to development and construction projects. During the six months ended June 30, 2021, gains on wind turbine equipment contributed to various equity method investments totaled approximately $37 million.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

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 $150 million, including estimated working capital adjustments. The preliminary gain associated with the transaction is approximately $90 million, which will be recorded in the third quarter 2021.

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 June 30, 2021, the obligations subject to the payment performance guarantee totaled $268 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.

The assets and liabilities of Sequent were classified as held for sale on the balance sheets of Southern Company and Southern Company Gas at June 30, 2021. See "Assets and Liabilities Held for Sale" herein for additional information.

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 and Liabilities Held for Sale

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

	Southern Company				Southern Company Gas
	At June 30,		At December 31,		At June 30,
	2021		2020		2021
	(in millions)
Assets Held for Sale:
Receivables – energy marketing	$	486	$	—	$	486
Natural gas for sale	90		—		90
Other current assets	76		—		76
Total property, plant, and equipment	11		8		5
Leveraged leases	45		52		—
Accumulated deferred income taxes	30		—		30
Other non-current assets	49		—		49
Total Assets Held for Sale	$	787	$	60	$	736
Liabilities Held for Sale:
Energy marketing trade payables	$	491	$	—	$	491
Other current liabilities	148		—		148
Other non-current liabilities	38		—		38
Total Liabilities Held for Sale	$	677	$	—	$	677

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

Southern Company Gas' assets and liabilities held for sale at June 30, 2021 were recorded based on their carrying value as the net carrying value of Sequent was lower than the agreed upon price in the sale agreement. See Note (I) for information regarding Sequent's energy-related derivatives held for sale that are recorded at fair value on a recurring basis. Southern Company's other assets held for sale at June 30, 2021 and December 31, 2020 were recorded at fair value on a nonrecurring basis, based primarily on unobservable inputs (Level 3).

See Note 3 to the financial statements under "Other Matters – Southern Company" in Item 8 of the Form 10-K for additional information regarding the leveraged lease investment held for sale.

Southern Company's and Southern Company Gas' asset sales, both individually and combined, do not represent a strategic shift in operations that has, or is expected to have, a major effect on operations and financial results; therefore, none of the assets have been classified as discontinued operations for any of the periods presented.

(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 $112 million and $193 million for the three and six months ended June 30, 2021, respectively, and $92 million and $178 million for the three and six months ended June 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 $6 million and $18 million for the three and six months ended June 30, 2021, respectively, and $3 million and $13 million for the three and six months ended June 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 six months ended June 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 June 30, 2021
Operating revenues	$	4,031	$	490	$	(114)	$	4,407	$	677	$	154	$	(40)	$	5,198
Segment net income (loss)(a)(b)(c)(d)	511		36		—		547		(65)		(108)		(2)		372
Six Months Ended June 30, 2021
Operating revenues	$	7,795	$	930	$	(201)	$	8,524	$	2,371	$	288	$	(75)	$	11,108
Segment net income (loss)(a)(b)(c)(d)(e)	1,267		133		—		1,400		333		(216)		(9)		1,508
At June 30, 2021
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	263	$	—	$	5,280
Assets held for sale	2		—		—		2		736		49		—		787
Total assets	87,330		13,708		(693)		100,345		23,235		3,063		(736)		125,907
Three Months Ended June 30, 2020
Operating revenues	$	3,539	$	439	$	(94)	$	3,884	$	636	$	135	$	(35)	$	4,620
Segment net income (loss)(a)(b)(d)	645		63		—		708		71		(177)		10		612
Six Months Ended June 30, 2020
Operating revenues	$	6,946	$	814	$	(181)	$	7,579	$	1,885	$	248	$	(74)	$	9,638
Segment net income (loss)(a)(b)(d)(f)	1,287		138		—		1,425		346		(299)		8		1,480
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 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 $460 million ($343 million after tax) and $508 million ($379 million after tax) for the three and six months ended June 30, 2021, respectively, and $149 million ($111 million after tax) for the three and six months ended June 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.

(c)For Southern Company Gas, includes a pre-tax impairment charge of $82 million ($58 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.

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

(e)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.

(f)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 June 30, 2021	$	3,599	$	546	$	262	$	4,407
Three Months Ended June 30, 2020	3,182		472		230		3,884
Six Months Ended June 30, 2021	$	6,941	$	1,091	$	492	$	8,524
Six Months Ended June 30, 2020	6,260		889		430		7,579

	Southern Company Gas' Revenues
	Gas Distribution Operations		Wholesale Gas Services(*)		Gas Marketing Services		Other		Total
	(in millions)
Three Months Ended June 30, 2021	$	706	$	(110)	$	64	$	17	$	677
Three Months Ended June 30, 2020	583		(19)		56		16		636
Six Months Ended June 30, 2021	$	1,898	$	188	$	259	$	26	$	2,371
Six Months Ended June 30, 2020	1,596		32		233		24		1,885

(*)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.

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 six months ended June 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 June 30, 2021
Operating revenues	$	710	$	8	$	(110)	$	64	$	672	$	11	$	(6)	$	677
Segment net income (loss)(b)	80		(36)		(112)		6		(62)		(3)		—		(65)
Six Months Ended June 30, 2021
Operating revenues	$	1,910	$	16	$	188	$	259	$	2,373	$	18	$	(20)	$	2,371
Segment net income (loss)(b)	263		(7)		14		62		332		1		—		333
Total assets at June 30, 2021	20,245		1,492		807		1,486		24,030		11,300		(12,095)		23,235
Three Months Ended June 30, 2020
Operating revenues	$	587	$	8	$	(19)	$	56	$	632	$	8	$	(4)	$	636
Segment net income (loss)	74		21		(23)		5		77		(6)		—		71
Six Months Ended June 30, 2020
Operating revenues	$	1,607	$	16	$	32	$	233	$	1,888	$	16	$	(19)	$	1,885
Segment net income (loss)	238		51		—		62		351		(5)		—		346
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 June 30, 2021	$	1,292	$	27	$	1,319	$	1,429	$	(110)
Three Months Ended June 30, 2020	854		18		872		891		(19)
Six Months Ended June 30, 2021	$	3,881	$	90	$	3,971	$	3,783	$	188
Six Months Ended June 30, 2020	2,039		47		2,086		2,054		32

(b)For gas pipeline investments, includes a pre-tax impairment charge of $82 million ($58 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	98
Results of Operations	101
Southern Company	101
Alabama Power	110
Georgia Power	115
Mississippi Power	121
Southern Power	125
Southern Company Gas	129
Future Earnings Potential	138
Accounting Policies	142
Financial Condition and Liquidity	143

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 (through June 30, 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

Georgia Power

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 common facilities shared between Plant Vogtle Units 3 and 4, as well as the related costs of operation. The request includes an annual rate increase totaling approximately $370 million to be effective the month after Unit 3 is placed in service, which will be partially offset by a decrease in the NCCR tariff of approximately $116 million expected to be effective January 1, 2022. In addition, an estimated $45 million of fuel cost savings related to Unit 3 is already incorporated in Georgia Power's current fuel cost recovery rates. The Georgia PSC is scheduled to issue a final order in this proceeding on November 2, 2021. The ultimate outcome of this matter cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Georgia Power – Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" herein for additional information.

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 June 2022 and March 2023, respectively, is $9.22 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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

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 and fuel load for Unit 3. Hot functional testing for Unit 3 was completed in July 2021. 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. The site work plan currently targets fuel load for Unit 3 in the fourth quarter 2021 and an in-service date of March 2022. As the site work plan includes minimal margin to these milestone dates, an in-service date in the second 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. The site work plan targets an in-service date of November 2022 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 first 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. Considering the factors above, during the second quarter 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 described above, 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.

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 and the second quarter 2021 of $48 million ($36 million after tax) and $460 million ($343 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.

Mississippi Power

On April 15, 2021, Mississippi Power filed its 2021 IRP with the Mississippi PSC. The filing 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. If no deficiencies are noted that would require re-evaluation or resubmission of the IRP, the

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

Mississippi PSC's review period will conclude on August 13, 2021. The ultimate outcome of this matter cannot be determined at this time.

During the first half of 2021, the Mississippi PSC approved the following 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.

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

Southern Power

During the six months ended June 30, 2021, Southern Power continued construction of the 88-MW Garland and 72-MW Tranquillity battery energy storage facilities and the 118-MW Glass Sands wind 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.

At June 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. The Georgia PSC is scheduled to vote on this matter in November 2021.

On May 10, 2021, Virginia Natural Gas, the Virginia Commission staff, and other intervenors entered into 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%. On July 8, 2021, the hearing examiner issued a report recommending adoption of the stipulation agreement. The Virginia Commission is expected to rule on this matter by September 2021. 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. Resolution of the GRAM filing is expected by December 31, 2021, with the new rates to become effective January 1, 2022.

See Note (B) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information. The ultimate outcome of these matters cannot be determined at this time.

During the second quarter 2021, Southern Company Gas recorded a pre-tax impairment charge of $82 million ($58 million after tax) related to its equity method investment in the PennEast Pipeline project. See Notes (C) and (E) to

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the Condensed Financial Statements herein under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, 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 $150 million, including estimated working capital adjustments. The preliminary gain associated with the transaction is approximately $90 million, which will be recorded in the third quarter 2021. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

RESULTS OF OPERATIONS

Southern Company

Net Income

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(240)	(39.2)	$28	1.9

Consolidated net income attributable to Southern Company was $372 million ($0.35 per share) for the second quarter 2021 compared to $612 million ($0.58 per share) for the corresponding period in 2020. The decrease was primarily due to a $232 million increase in after-tax charges related to the construction of Plant Vogtle Units 3 and 4 at Georgia Power and an after-tax impairment charge related to the PennEast Pipeline project at Southern Company Gas, partially offset by a decrease in after-tax leveraged lease impairment charges. The decrease was also due to higher non-fuel operations and maintenance costs, partially offset by higher retail electric revenues associated with rates and pricing and sales growth.

Consolidated net income attributable to Southern Company was $1.51 billion ($1.42 per share) for year-to-date 2021 compared to $1.48 billion ($1.40 per share) for the corresponding period in 2020. The increase was primarily due to increases in both natural gas revenues and retail electric revenues associated with colder weather in the first quarter 2021 as compared to the corresponding period in 2020, higher retail electric revenues associated with rates and pricing and sales growth, and higher wholesale electric capacity revenues, largely offset by higher non-fuel operations and maintenance costs and the net impact of the charges in the second quarter 2021 and 2020, as described previously.

Retail Electric Revenues

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$417	13.1	$681	10.9

In the second quarter 2021, retail electric revenues were $3.6 billion compared to $3.2 billion for the corresponding period in 2020. For year-to-date 2021, retail electric revenues were $6.9 billion compared to $6.3 billion for the corresponding period in 2020.

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

	Second Quarter 2021				Year-To-Date 2021
	(in millions)		(% change)		(in millions)		(% change)
Retail electric – prior year	$	3,182			$	6,260
Estimated change resulting from –
Rates and pricing	112		3.5	%	137		2.2	%
Sales growth	86		2.7		72		1.2
Weather	18		0.6		106		1.7
Fuel and other cost recovery	201		6.3		366		5.8
Retail electric – current year	$	3,599	13.1	%	$	6,941	10.9	%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2021 when compared to the corresponding periods in 2020 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, higher pricing effects associated with decreased residential customer usage, and increased ECCR tariff revenues associated with higher KWH sales, partially offset by decreases in the NCCR tariff effective January 1, 2021. 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 second quarter and year-to-date 2021 when compared to the corresponding periods in 2020. Weather-adjusted residential KWH sales decreased 2.0% and 0.4% in the second quarter and year-to-date 2021, respectively, when compared to the corresponding periods in 2020 as customer usage decreased, primarily due to shelter-in-place orders in effect during 2020, partially offset by customer growth. Weather-adjusted commercial KWH sales increased 8.7% and 2.7% in the second quarter and year-to-date 2021, respectively, and industrial KWH sales increased 11.7% and 4.0% in the second quarter and year-to-date 2021, respectively, when compared to the corresponding periods in 2020, primarily due to the negative impact of the COVID-19 pandemic on energy demand in 2020.

Fuel and other cost recovery revenues increased $201 million and $366 million in the second 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

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$74	15.7	$202	22.7

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

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decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, the ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales under cost-based tariffs as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.

In the second quarter 2021, wholesale electric revenues were $546 million compared to $472 million for the corresponding period in 2020. For year-to-date 2021, wholesale electric revenues were $1.1 billion compared to $0.9 billion for the corresponding period in 2020. Increases in energy revenues of $51 million and $153 million for the second 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 $23 million and $49 million for the second quarter and year-to-date 2021, respectively, primarily resulted from a power sales agreement at Alabama Power that began in September 2020 and new natural gas PPAs at Southern Power that began subsequent to the second quarter 2020.

Other Electric Revenues

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$7	4.2	$26	8.1

For year-to-date 2021, other electric revenues were $346 million compared to $320 million for the corresponding period in 2020. The increase was primarily due to increases of $16 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, $5 million related to outdoor lighting sales at Georgia Power, and $3 million in transmission services.

Natural Gas Revenues

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$41	6.4	$486	25.8

In the second quarter 2021, natural gas revenues were $677 million compared to $636 million for the corresponding period in 2020. For year-to-date 2021, natural gas revenues were $2.4 billion compared to $1.9 billion for the corresponding period in 2020.

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

	Second Quarter 2021				Year-To-Date 2021
	(in millions)		(% change)		(in millions)		(% change)
Natural gas revenues – prior year	$	636			$	1,885
Estimated change resulting from –
Infrastructure replacement programs and base rate changes	41		6.4	%	81		4.3	%
Gas costs and other cost recovery	88		13.8		240		12.7
Wholesale gas services	(91)		(14.3)		156		8.3
Other	3		0.5		9		0.5
Natural gas revenues – current year	$	677	6.4	%	$	2,371	25.8	%

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

Revenues from Southern Company Gas' wholesale gas services business decreased in the second quarter 2021 compared to the corresponding period in 2020 due to derivative losses, partially offset by higher commercial activities. Revenues from wholesale gas services increased for year-to-date 2021 compared to the corresponding period in 2020 due to higher volumes sold and higher commercial activities as a result of Winter Storm Uri, partially offset by derivative losses. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for information regarding the sale of Sequent on July 1, 2021.

Other Revenues

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$39	24.1	$75	26.4

In the second quarter 2021, other revenues were $201 million compared to $162 million for the corresponding period in 2020. For year-to-date 2021, other revenues were $359 million compared to $284 million for the corresponding period in 2020. The increases for the second quarter and year-to-date 2021 were primarily due to increases of $28 million and $38 million, respectively, in unregulated sales of products and services at Alabama Power and Georgia Power and increases of $15 million and $32 million, respectively, in distributed infrastructure projects at PowerSecure.

Fuel and Purchased Power Expenses

	Second Quarter 2021 vs. Second Quarter 2020			Year-To-Date 2021 vs. Year-To-Date 2020
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	227	36.6	$	439	34.9
Purchased power	17		8.5	43		11.3
Total fuel and purchased power expenses	$	244		$	482

In the second quarter 2021, total fuel and purchased power expenses were $1.1 billion compared to $0.8 billion for the corresponding period in 2020. The increase was primarily the result of a $163 million increase in the average cost of fuel and purchased power and an $81 million net increase in the volume of KWHs generated and purchased.

For year-to-date 2021, total fuel and purchased power expenses were $2.1 billion compared to $1.6 billion for the corresponding period in 2020. The increase was primarily the result of a $322 million increase in the average cost of fuel and purchased power and a $160 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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Details of the Southern Company system's generation and purchased power were as follows:

	Second Quarter 2021	Second Quarter 2020	Year-To-Date 2021	Year-To-Date 2020
Total generation (in billions of KWHs)(a)	43	41	86	82
Total purchased power (in billions of KWHs)	4	4	8	9
Sources of generation (percent)(a) —
Gas	47	55	46	54
Coal	22	19	23	19
Nuclear	18	12	18	13
Hydro	4	5	4	6
Wind, Solar, and Other	9	9	9	8
Cost of fuel, generated (in cents per net KWH)—
Gas(a)	2.58	1.89	2.56	1.92
Coal	2.87	2.96	2.85	2.92
Nuclear	0.75	0.78	0.75	0.78
Average cost of fuel, generated (in cents per net KWH)(a)	2.28	1.79	2.27	1.82
Average cost of purchased power (in cents per net KWH)(b)	5.65	4.74	5.37	4.30

(a)Second 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 second quarter 2021, fuel expense was $848 million compared to $621 million for the corresponding period in 2020. The increase was primarily due to an 84.8% increase in the volume of KWHs generated by coal and a 36.5% increase in the average cost of natural gas per KWH generated, partially offset by an 8.6% decrease in the volume of KWHs generated by natural gas.

For year-to-date 2021, fuel expense was $1.7 billion compared to $1.3 billion for the corresponding period in 2020. The increase was primarily due to an 81.8% increase in the volume of KWHs generated by coal, a 27.6% decrease in the volume of KWHs generated by hydro, and a 33.3% increase in the average cost of natural gas per KWH generated, partially offset by an 8.9% decrease in the volume of KWHs generated by natural gas.

Purchased Power

In the second quarter 2021, purchased power expense was $217 million compared to $200 million for the corresponding period in 2020. The increase was primarily due to a 19.2% increase in the average cost per KWH purchased primarily due to higher natural gas prices, partially offset by a 4.5% decrease in the volume of KWHs purchased.

For year-to-date 2021, purchased power expense was $424 million compared to $381 million for the corresponding period in 2020. The increase was primarily due to a 24.9% increase in the average cost per KWH purchased primarily due to higher natural gas prices, partially offset by a 6.6% 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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Cost of Natural Gas

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$87	60.4	$231	39.6

Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. Cost of natural gas at the natural gas distribution utilities represented 87% of total cost of natural gas for both the second quarter and year-to-date 2021.

In the second quarter 2021, cost of natural gas was $231 million compared to $144 million for the corresponding period in 2020. The increase reflects higher gas cost recovery and a 65.0% increase in natural gas prices in the second quarter 2021 compared to the corresponding period in 2020.

For year-to-date 2021, cost of natural gas was $814 million compared to $583 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 50.6% increase in natural gas prices for year-to-date 2021 compared to the corresponding period in 2020.

Cost of Other Sales

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$29	39.2	$56	43.4

In the second quarter 2021, cost of other sales was $103 million compared to $74 million for the corresponding period in 2020. For year-to-date 2021, cost of other sales was $185 million compared to $129 million for the corresponding period in 2020. The increases for second quarter and year-to-date 2021 primarily relate to increases of $16 million and $23 million, respectively, in unregulated power delivery construction and maintenance projects at Georgia Power and $12 million and $22 million, respectively, in distributed infrastructure projects at PowerSecure.

Other Operations and Maintenance Expenses

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$235	19.5	$312	12.5

In the second quarter 2021, other operations and maintenance expenses were $1.4 billion compared to $1.2 billion for the corresponding period in 2020. The increase reflects increases of $68 million in scheduled generation outage and maintenance expenses, $44 million in transmission and distribution expenses, including $11 million of reliability NDR credits at Alabama Power, and $16 million in compliance and environmental expenses at the traditional electric operating companies. These increases reflect the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. Also contributing to the increase was an increase of $46 million in compensation and benefit expenses.

For year-to-date 2021, other operations and maintenance expenses were $2.8 billion compared to $2.5 billion for the corresponding period in 2020. The increase reflects increases of $58 million in scheduled generation outage and maintenance expenses, $52 million in transmission and distribution expenses, including $22 million of reliability NDR credits at Alabama Power, and $15 million in compliance and environmental expenses at the traditional electric operating companies. These increases reflect the impacts of cost containment activities implemented for

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2020 during the COVID-19 pandemic. Also contributing to the increase was an increase of $101 million in compensation and benefit expenses and an $18 million decrease in nuclear property insurance refunds.

Depreciation and Amortization

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$18	2.1	$32	1.8

In the second quarter 2021, depreciation and amortization was $891 million compared to $873 million for the corresponding period in 2020. For year-to-date 2021, depreciation and amortization was $1.8 billion compared to $1.7 billion for the corresponding period in 2020. The increases for the second quarter and year-to-date 2021 primarily reflect increases of $42 million and $79 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 $44 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

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$15	5.0	$28	4.5

In the second quarter 2021, taxes other than income taxes were $313 million compared to $298 million for the corresponding period in 2020. The increase primarily reflects increases at Georgia Power of $9 million in property taxes primarily from higher assessed values, including the impact of Plant Vogtle Units 3 and 4 construction, and $7 million in municipal franchise fees largely related to higher retail revenues.

For year-to-date 2021, taxes other than income taxes were $657 million compared to $629 million for the corresponding period in 2020. The increase primarily reflects increases of $18 million in property taxes primarily from higher assessed values, including the impact of Plant Vogtle Units 3 and 4 construction, and $10 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

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$311	208.7	$359	240.9

In the second quarter 2021 and 2020, estimated probable losses on Plant Vogtle Units 3 and 4 of $460 million and $149 million, respectively, were recorded at Georgia Power. For year-to-date 2021 and 2020, estimated probable losses on Plant Vogtle Units 3 and 4 of $508 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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(Gain) Loss on Dispositions, Net

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$11	N/M	$15	38.5

N/M - Not meaningful

In the second quarter 2021, gain on dispositions, net was $11 million compared to an immaterial loss for the corresponding period in 2020. The increase primarily reflects $6 million in gains at Alabama Power primarily from property sales and a $5 million gain on the sale of Pivotal LNG at Southern Company Gas.

For year-to-date 2021, gain on dispositions, net was $54 million compared to $39 million for the corresponding period in 2020. The increase primarily reflects $39 million in gains at Southern Power, primarily from contributions of wind turbine equipment to various equity method investments, $10 million in gains at Alabama Power primarily from property sales, and a $6 million gain on the sale of Pivotal LNG at Southern Company Gas, 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" and "Southern Company Gas – Sale of Pivotal LNG and Atlantic Coast Pipeline" in Item 8 of the Form 10-K for additional information.

Allowance for Equity Funds Used During Construction

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$10	28.6	$22	32.4

In the second quarter 2021, allowance for equity funds used during construction was $45 million compared to $35 million for the corresponding period in 2020. For year-to-date 2021, allowance for equity funds used during construction was $90 million compared to $68 million for the corresponding period in 2020. The increases were primarily due to increases at Georgia Power, primarily 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.

Earnings (Loss) from Equity Method Investments

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(70)	N/M	$(67)	N/M

N/M - Not meaningful

In the second quarter 2021, loss from equity method investments was $40 million compared to earnings of $30 million for the corresponding period in 2020. For year-to-date 2021, earnings from equity method investments were $5 million compared to $72 million for the corresponding period in 2020. The decreases were primarily due to a pre-tax impairment charge of $82 million in the second quarter 2021 related to the PennEast Pipeline project at Southern Company Gas. The decreases were partially offset by increases in investment income at Southern Holdings of $12 million and $17 million for the second quarter and year-to-date 2021, respectively. 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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Impairment of Leveraged Leases

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

N/M - Not meaningful

In the second quarter 2021 and 2020, impairment charges of $7 million and $154 million, respectively, were recorded related to leveraged lease investments at Southern Holdings. See Note (K) to the Condensed Financial Statements under "Assets and Liabilities 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

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$7	6.9	$(37)	(18.1)

In the second quarter 2021, other income (expense), net was $108 million compared to $101 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 $26 million in charitable contributions in the second quarter 2021 at Southern Company Gas.

For year-to-date 2021, other income (expense), net was $167 million compared to $204 million for the corresponding period in 2020. The decrease was primarily due to $101 million in charitable contributions at Southern Company Gas, partially offset by a $71 million increase in non-service cost-related retirement benefits income.

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

Income Taxes (Benefit)

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(17)	N/M	$28	18.7

N/M - Not meaningful

In the second quarter 2021, income tax benefit was $12 million compared to income tax expense of $5 million for the corresponding period in 2020. The change was primarily due to lower pre-tax earnings, partially offset by the tax impact of the second quarter 2020 charge to earnings associated with a leveraged lease investment.

For year-to-date 2021, income taxes were $178 million compared to $150 million for the corresponding period in 2020. The increase was primarily due to the tax impact of the second quarter 2020 charge to earnings associated with a leveraged lease investment.

See Note (G) 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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Alabama Power

Net Income

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$33	11.1	$112	19.4

Alabama Power's net income after dividends on preferred stock for the second quarter 2021 was $331 million compared to $298 million for the corresponding period in 2020. Alabama Power's net income after dividends on preferred stock for year-to-date 2021 was $690 million compared to $578 million 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, as well as additional wholesale capacity revenues related to a power sales agreement that began in September 2020. Also contributing to the year-to-date 2021 increase was colder weather in Alabama Power's service territory in the first quarter 2021 compared to the corresponding period in 2020. The second quarter and year-to-date 2021 increases were partially offset by an increase in operations and maintenance expenses and depreciation.

Retail Revenues

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$131	10.7	$279	11.5

In the second quarter 2021, retail revenues were $1.35 billion compared to $1.22 billion for the corresponding period in 2020. For year-to-date 2021, retail revenues were $2.71 billion compared to $2.43 billion for the corresponding period in 2020.

Details of the changes in retail revenues were as follows:

	Second Quarter 2021				Year-To-Date 2021
	(in millions)		(% change)		(in millions)		(% change)
Retail – prior year	$	1,223			$	2,427
Estimated change resulting from –
Rates and pricing	66		5.4	%	116		4.8	%
Sales growth	16		1.3		13		0.5
Weather	3		0.2		42		1.7
Fuel and other cost recovery	46		3.8		108		4.5
Retail – current year	$	1,354	10.7	%	$	2,706	11.5	%

Revenues associated with changes in rates and pricing increased in the second 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 second quarter and year-to-date 2021 when compared to the corresponding periods in 2020. Weather-adjusted residential KWH sales decreased 3.9% and 2.0% in the second 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 7.8% and 2.8% in the second quarter and year-to-date 2021, respectively, and industrial KWH sales increased 10.0% and 1.8% in the second quarter and year-to-date 2021, respectively, when compared to the corresponding periods in 2020, primarily due to the negative impact of the COVID-19 pandemic on energy demand in 2020.

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Fuel and other cost recovery revenues increased in the second 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

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$31	57.4	$67	60.4

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 second quarter 2021, wholesale revenues from sales to non-affiliates were $85 million compared to $54 million for the corresponding period in 2020. For year-to-date 2021, wholesale revenues from sales to non-affiliates were $178 million compared to $111 million for the corresponding period in 2020. The second quarter and year-to-date 2021 increases consisted of increases in capacity revenues of $18 million and $35 million, respectively, primarily related to a power sales agreement that began in September 2020 and increases in energy revenues of $13 million and $32 million, respectively, primarily due to higher natural gas prices.

Wholesale Revenues – Affiliates

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$17	242.9	$29	111.5

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

In the second quarter 2021, wholesale revenues from sales to affiliates were $24 million compared to $7 million for the corresponding period in 2020. For year-to-date 2021, wholesale revenues from sales to affiliates were $55 million compared to $26 million for the corresponding period in 2020. The second quarter and year-to-date 2021 increases were primarily due to increases of 133.8% and 50.1%, respectively, in the price of energy as a result of higher natural gas prices and increases of 51.9% and 43.5%, respectively, in KWH sales due to increased demand for Alabama Power's available lower cost generation compared to the corresponding periods in 2020.

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Other Revenues

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$12	14.8	$24	15.8

In the second quarter 2021, other revenues were $93 million compared to $81 million for the corresponding period in 2020. For year-to-date 2021, other revenues were $176 million compared to $152 million for the corresponding period in 2020. The second quarter and year-to-date 2021 increases were primarily due to increases of $12 million and $15 million, respectively, in unregulated sales of products and services. In addition, the year-to-date 2021 increase included a $6 million increase in customer fees largely resulting from the COVID-19 pandemic-related temporary suspensions of disconnections and late fees in 2020.

Fuel and Purchased Power Expenses

	Second Quarter 2021 vs. Second Quarter 2020			Year-To-Date 2021 vs. Year-To-Date 2020
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	64	32.2	$	139	33.5
Purchased power – non-affiliates	(1)		(2.0)	8		9.0
Purchased power – affiliates	9		30.0	20		40.8
Total fuel and purchased power expenses	$	72		$	167

In the second quarter 2021, total fuel and purchased power expenses were $350 million compared to $278 million for the corresponding period in 2020. The increase was primarily due a $42 million net increase related to the volume of KWHs generated and purchased and a $30 million increase in the average cost of fuel and purchased power.

For year-to-date 2021, total fuel and purchased power expenses were $720 million compared to $553 million for the corresponding period in 2020. The increase was primarily due to a $98 million increase related to the volume of KWHs generated and purchased and a $69 million increase in the average cost of fuel and purchased power.

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

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

	Second Quarter 2021	Second Quarter 2020	Year-To-Date 2021	Year-To-Date 2020
Total generation (in billions of KWHs)(a)	13	12	28	26
Total purchased power (in billions of KWHs)	2	2	3	3
Sources of generation (percent)(a) —
Coal	43	33	45	33
Nuclear	25	32	25	30
Gas	22	24	20	22
Hydro	10	11	10	15
Cost of fuel, generated (in cents per net KWH) —
Coal	2.73	2.82	2.74	2.72
Nuclear	0.69	0.75	0.71	0.75
Gas(a)	2.47	1.95	2.49	2.07
Average cost of fuel, generated (in cents per net KWH)(a)	2.10	1.85	2.12	1.86
Average cost of purchased power (in cents per net KWH)(b)	5.57	4.29	5.99	4.51

(a)Second 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 second quarter 2021, fuel expense was $263 million compared to $199 million for the corresponding period in 2020. The increase was primarily due to a 44.6% increase in the volume of KWHs generated by coal and a 26.7% increase in the average cost of KWHs generated by natural gas, which excludes tolling agreements.

For year-to-date 2021, fuel expense was $554 million compared to $415 million for the corresponding period in 2020. The increase was primarily due to a 44.6% increase in the volume of KWHs generated by coal, a 26.9% decrease in the volume of KWHs generated by hydro, and a 20.3% increase in the average cost of KWHs generated by natural gas, which excludes tolling agreements.

Purchased Power – Affiliates

In the second quarter 2021, purchased power expense from affiliates was $39 million compared to $30 million for the corresponding period in 2020. For year-to-date 2021, purchased power expense from affiliates was $69 million compared to $49 million for the corresponding period in 2020. The second quarter and year-to-date 2021 increases were primarily due to increases of 74.2% and 70.7%, respectively, in the average cost per KWH purchased as a result of higher natural gas prices, partially offset by decreases of 27.0% and 17.2%, respectively, in the volume of KWH purchased as a result of increased generation compared to the corresponding periods 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.

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Other Operations and Maintenance Expenses

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$71	20.8	$85	12.3

In the second quarter 2021, other operations and maintenance expenses were $413 million compared to $342 million for the corresponding period in 2020. The increase was primarily due to an increase of $36 million in generation expenses associated with scheduled outages and Rate CNP Compliance-related expenses primarily related to the addition of new environmental systems in 2021. These increases reflect the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. Also contributing to the increase were increases of $17 million in compensation and benefit expenses and $5 million related to unregulated services, as well as $11 million of reliability NDR credits applied in 2020.

For year-to-date 2021, other operations and maintenance expenses were $775 million compared to $690 million for the corresponding period in 2020. The increase was primarily due to an increase of $34 million in generation expenses associated with scheduled outages and Rate CNP Compliance-related expenses primarily related to the addition of new environmental systems in 2021. These increases reflect the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. Also contributing to the increase were increases of $17 million in compensation and benefit expenses and $7 million related to unregulated services, as well as $22 million of reliability NDR credits applied in 2020 and a $10 million decrease in nuclear property insurance refunds. These increases were partially offset by gains of $10 million primarily related to property sales and an $8 million decrease in bad debt expense.

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

Depreciation and Amortization

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$12	5.9	$23	5.7

In the second quarter 2021, depreciation and amortization was $214 million compared to $202 million in the corresponding period in 2020. For year-to-date 2021, depreciation and amortization was $425 million compared to $402 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

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$7	26.9	$14	29.2

In the second quarter 2021, other income (expense), net was $33 million compared to $26 million for the corresponding period in 2020. For year-to-date 2021, other income (expense), net was $62 million compared to $48 million for the corresponding period in 2020. These increases were primarily due to an increase in non-service cost-related retirement benefits income. The year-to-date 2021 increase was partially offset by a decrease in interest income associated with lower interest rates. See Note (H) to the Condensed Financial Statements herein for additional information.

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Income Taxes

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$11	11.8	$36	20.3

In the second quarter 2021, income taxes were $104 million compared to $93 million for the corresponding period in 2020. For year-to-date 2021, income taxes were $213 million compared to $177 million for the corresponding period in 2020. The increases were primarily due to higher pre-tax earnings.

Georgia Power

Net Income

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(165)	(53.6)	$(144)	(22.6)

Georgia Power's net income for the second quarter 2021 was $143 million compared to $308 million for the corresponding period in 2020. The decrease was primarily due to a $232 million increase in after-tax charges related to the construction of Plant Vogtle Units 3 and 4. Also contributing to the decrease was higher non-fuel operations and maintenance costs, partially offset by higher retail revenues associated with sales growth and rates and pricing.

For year-to-date 2021, net income was $494 million compared to $638 million for the corresponding period in 2020. The decrease was primarily due to a $268 million increase in after-tax charges related to the construction of Plant Vogtle Units 3 and 4. Also contributing to the decrease was higher non-fuel operations and maintenance costs, partially offset by higher retail revenues associated with colder weather in the first quarter 2021 as compared to the corresponding period in 2020 and 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

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$266	15.1	$378	11.0

In the second quarter 2021, retail revenues were $2.03 billion compared to $1.76 billion for the corresponding period in 2020. For year-to-date 2021, retail revenues were $3.81 billion compared to $3.44 billion for the corresponding period in 2020.

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Details of the changes in retail revenues were as follows:

	Second Quarter 2021				Year-To-Date 2021
	(in millions)		(% change)		(in millions)		(% change)
Retail – prior year	$	1,760			$	3,435
Estimated change resulting from –
Rates and pricing	38		2.2	%	20		0.6	%
Sales growth	64		3.6		59		1.7
Weather	18		1.0		59		1.7
Fuel cost recovery	146		8.3		240		7.0
Retail – current year	$	2,026	15.1	%	$	3,813	11.0	%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2021 when compared to the corresponding periods in 2020. These increases were primarily due to higher contributions from commercial and industrial customers with variable demand-driven pricing, pricing effects associated with decreased residential customer usage, and increased ECCR tariff revenues associated with higher KWH sales. The increases were partially offset by a decrease in the NCCR tariff effective January 1, 2021. 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 second quarter and year-to-date 2021 when compared to the corresponding periods in 2020. Weather-adjusted residential KWH sales decreased 0.8% in the second quarter 2021 when compared to the corresponding period in 2020 as customer usage decreased, primarily due to shelter-in-place orders in effect during the second quarter 2020. Weather-adjusted residential KWH sales increased 0.7% for year-to-date 2021 when compared to the corresponding period in 2020 primarily due to customer growth, partially offset by decreased customer usage, primarily due to shelter-in-place orders in effect during 2020. Weather-adjusted commercial KWH sales increased 9.0% and 2.6% in the second quarter and year-to-date 2021, respectively, and weather-adjusted industrial KWH sales increased 14.0% and 7.3% in the second quarter and year-to-date 2021, respectively, when compared to the corresponding periods in 2020, primarily due to the negative impact of the COVID-19 pandemic on energy demand in 2020.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased in the second 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 under "Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.

Wholesale Revenues

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$11	44.0	$29	56.9

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 second quarter 2021, wholesale revenues were $36 million compared to $25 million for the corresponding period in 2020. For year-to-date 2021, wholesale revenues were $80 million compared to $51 million for the corresponding period in 2020. The increases for the second quarter and year-to-date 2021 were primarily due to increases of 4.3% and 8.9%, respectively, in KWH sales as a result of higher market demand and higher natural gas prices.

Other Revenues

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$20	14.0	$34	12.7

In the second quarter 2021, other revenues were $163 million compared to $143 million for the corresponding period in 2020. For year-to-date 2021, other revenues were $302 million compared to $268 million for the corresponding period in 2020. The increases for the second quarter and year-to-date 2021 were primarily due to increases of $20 million and $30 million, respectively, in unregulated sales associated with power delivery construction and maintenance projects and $7 million and $8 million, respectively, 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 $5 million and $7 million in the second quarter and year-to-date 2021, respectively, associated with the timing of certain unregulated energy conservation projects.

Fuel and Purchased Power Expenses

	Second Quarter 2021 vs. Second Quarter 2020			Year-To-Date 2021 vs. Year-To-Date 2020
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	117	51.8	$	198	43.2
Purchased power – non-affiliates	11		8.3	26		9.9
Purchased power – affiliates	27		22.1	34		13.5
Total fuel and purchased power expenses	$	155		$	258

In the second quarter 2021, total fuel and purchased power expenses were $636 million compared to $481 million for the corresponding period in 2020. For year-to-date 2021, total fuel and purchased power expenses were $1.23 billion compared to $0.97 billion for the corresponding period in 2020. The increases for the second quarter and year-to-date 2021 were due to increases of $108 million and $184 million, respectively, related to the average cost of fuel and purchased power and net increases of $47 million and $74 million, respectively, related to the volume of KWHs generated and purchased.

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

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AND RESULTS OF OPERATIONS (Continued)

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

	Second Quarter 2021	Second Quarter 2020	Year-To-Date 2021	Year-To-Date 2020
Total generation (in billions of KWHs)	15	13	30	25
Total purchased power (in billions of KWHs)	7	8	14	16
Sources of generation (percent) —
Gas	46	56	47	57
Nuclear	28	32	27	30
Coal	22	7	22	7
Hydro and solar	4	5	4	6
Cost of fuel, generated (in cents per net KWH) —
Gas	2.65	2.11	2.62	2.11
Nuclear	0.80	0.81	0.79	0.80
Coal	3.09	3.37	3.01	3.60
Average cost of fuel, generated (in cents per net KWH)	2.21	1.76	2.18	1.82
Average cost of purchased power (in cents per net KWH)(*)	4.77	3.58	4.49	3.36

(*)Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.

Fuel

In the second quarter 2021, fuel expense was $343 million compared to $226 million for the corresponding period in 2020. For year-to-date 2021, fuel expense was $656 million compared to $458 million for the corresponding period in 2020. The increases for the second quarter and year-to-date 2021 were primarily due to increases of 261.8% and 247.1%, respectively, in the volume of KWHs generated by coal and increases of 25.6% and 24.2%, respectively, in the average cost of natural gas per KWH generated. The increase for year-to-date 2021 was partially offset by a 16.4% decrease in the average cost of coal per KWH generated.

Purchased Power – Non-Affiliates

In the second quarter 2021, purchased power expense from non-affiliates was $144 million compared to $133 million in the corresponding period in 2020. For year-to-date 2021, purchased power expense from non-affiliates was $288 million compared to $262 million in the corresponding period in 2020. The increases for the second quarter and year-to-date 2021 were primarily due to increases of 19.4% and 21.6%, respectively, in the average cost per KWH purchased primarily due to higher natural gas prices, partially offset by decreases of 7.9% and 8.9%, respectively, in the volume of KWHs purchased as Georgia Power units 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 second quarter 2021, purchased power expense from affiliates was $149 million compared to $122 million in the corresponding period in 2020. For year-to-date 2021, purchased power expense from affiliates was $285 million compared to $251 million in the corresponding period in 2020. The increases for the second quarter and year-to-date 2021 were primarily due to increases of 44.7% and 41.3%, respectively, in the average cost per KWH purchased primarily due to higher natural gas prices, partially offset by decreases of 15.2% and 19.1%, respectively, in the

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volume of KWHs purchased due to higher 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

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$79	17.1	$87	9.4

In the second quarter 2021, other operations and maintenance expenses were $542 million compared to $463 million for the corresponding period in 2020. The increase was primarily associated with increases of $27 million related to distribution maintenance activities, $14 million in generation expenses associated with non-outage maintenance costs and environmental projects, and $8 million in transmission overhead line costs. These increases reflect the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. Also contributing to the increase were increases of $16 million related to unregulated power delivery construction and maintenance projects and $7 million in benefit expenses.

For year-to-date 2021, other operations and maintenance expenses were $1.02 billion compared to $0.93 billion for the corresponding period in 2020. The increase was primarily associated with increases of $27 million related to distribution maintenance activities, $9 million in transmission overhead line costs, and $8 million in generation environmental projects. These increases reflect the impacts of cost containment activities implemented for 2020 during the COVID-19 pandemic. Also contributing to the increase were increases of $23 million related to unregulated power delivery construction and maintenance projects and $10 million in benefit expenses, as well as an $8 million decrease in nuclear property insurance refunds, partially offset by a decrease of $9 million in expenses associated with the timing of certain unregulated energy conservation projects.

Depreciation and Amortization

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(12)	(3.4)	$(27)	(3.8)

In the second quarter 2021, depreciation and amortization was $342 million compared to $354 million for the corresponding period in 2020. For year-to-date 2021, depreciation and amortization was $680 million compared to $707 million for the corresponding period in 2020. The decreases for the second quarter and year-to-date 2021 primarily reflect decreased amortization of regulatory assets related to CCR AROs of $22 million and $44 million, respectively, under the terms of the 2019 ARP, partially offset by increases of $10 million and $20 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.

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Taxes Other Than Income Taxes

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$10	9.3	$14	6.3

In the second quarter 2021, taxes other than income taxes was $118 million compared to $108 million for the corresponding period in 2020. For year-to-date 2021, taxes other than income taxes was $235 million compared to $221 million for the corresponding period in 2020. The increases for the second quarter and year-to-date 2021 were primarily due to increases of $7 million and $9 million, respectively, in municipal franchise fees largely related to higher retail revenues and increases of $3 million and $7 million, respectively, in property taxes primarily associated with the construction 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.

Estimated Loss on Plant Vogtle Units 3 and 4

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$311	208.7	$359	240.9

In the second quarter 2021 and 2020, Georgia Power recorded estimated probable losses on Plant Vogtle Units 3 and 4 of $460 million and $149 million, respectively. For year-to-date 2021 and 2020, Georgia Power recorded estimated probable losses on Plant Vogtle Units 3 and 4 of $508 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

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$10	50.0	$21	52.5

In the second quarter 2021, allowance for equity funds used during construction was $30 million compared to $20 million for the corresponding period in 2020. For year-to-date 2021, allowance for equity funds used during construction was $61 million compared to $40 million for the corresponding period in 2020. The increases were primarily 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

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$11	35.5	$20	31.7

In the second quarter 2021, other income (expense), net was $42 million compared to $31 million for the corresponding period in 2020. For year-to-date 2021, other income (expense), net was $83 million compared to $63 million for the corresponding period in 2020. The increases were primarily due to increases of $12 million and $25 million, respectively, in non-service cost-related retirement benefits income. The increase for year-to-date 2021 was

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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 (Benefit)

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(61)	N/M	$(59)	N/M

N/M - Not meaningful

In the second quarter 2021, income tax benefit was $50 million compared to income tax expense of $11 million for the corresponding period in 2020. For year-to-date 2021, income tax benefit was $32 million compared to income tax expense of $27 million for the corresponding period in 2020. The changes were primarily due to lower pre-tax earnings resulting from higher charges in 2021 compared to the corresponding periods in 2020 associated with the construction 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" and Note (G) to the Condensed Financial Statements herein for additional information.

Mississippi Power

Net Income

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(1)	(2.6)	$12	16.9

In the second quarter 2021, net income was $38 million compared to $39 million for the corresponding period in 2020. The decrease was primarily due to an increase in operations and maintenance expenses and income taxes, largely offset by an increase in base rates that became effective for the first billing cycle of April 2021 and higher customer usage in the second quarter 2021 when compared to the corresponding period in 2020.

For year-to-date 2021, net income was $83 million compared to $71 million for the corresponding period in 2020. The increase was primarily due to an increase in base revenues primarily due to colder weather in the first quarter 2021 as compared to the corresponding period in 2020, as well as an increase in other income.

Retail Revenues

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$20	10.1	$24	6.0

In the second quarter 2021, retail revenues were $219 million compared to $199 million for the corresponding period in 2020. For year-to-date 2021, retail revenues were $422 million compared to $398 million for the corresponding period in 2020.

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Details of the changes in retail revenues were as follows:

	Second Quarter 2021				Year-To-Date 2021
	(in millions)		(% change)		(in millions)		(% change)
Retail – prior year	$	199			$	398
Estimated change resulting from –
Rates and pricing	8		4.0	%	1		0.3	%
Sales growth	6		3.0		—		—
Weather	(3)		(1.5)		5		1.3
Fuel and other cost recovery	9		4.5		18		4.5
Retail – current year	$	219	10.0	%	$	422	6.1	%

Revenues associated with changes in rates and pricing increased in the second quarter 2021 when compared to the corresponding period 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.

Revenues attributable to changes in sales increased in the second quarter 2021 when compared to the corresponding period in 2020. Weather-adjusted residential KWH sales decreased 1.9% and 1.3% in the second quarter and year-to-date 2021, respectively, when compared to the corresponding periods in 2020 as customer usage decreased, primarily due to shelter-in-place orders in effect during 2020. Weather-adjusted commercial KWH sales increased 9.0% and 2.4% in the second quarter and year-to-date 2021, respectively, and industrial KWH sales increased 7.2% in the second quarter 2021 when compared to the corresponding periods in 2020, primarily due to the negative impact of the COVID-19 pandemic on energy demand in 2020. Industrial KWH sales decreased 2.1% for year-to-date 2021 when compared to the corresponding period in 2020 as a result of decreased customer usage due to continued disruptions of supply chain and business operations driven by the COVID-19 pandemic, as well as non-pandemic related customer outages.

Fuel and other cost recovery revenues increased in the second 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

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$2	3.8	$14	13.6

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.

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For year-to-date 2021, wholesale revenues from sales to non-affiliates were $117 million compared to $103 million for the corresponding period in 2020. The increase was primarily due to higher fuel costs and an increase in revenue from MRA customers and opportunity sales as a result of colder weather in the first quarter 2021.

Wholesale Revenues – Affiliates

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$10	21.3

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 both the second quarter 2021 and 2020, wholesale revenues from sales to affiliates were $25 million. Wholesale revenues from sales to affiliates in the second quarter 2021 reflected a decrease of $11 million associated with lower KWH sales offset by an $11 million increase associated with higher natural gas prices when compared to the corresponding period in 2020.

For year-to-date 2021, wholesale revenues from sales to affiliates were $57 million compared to $47 million for the corresponding period in 2020. The increase was primarily due to a $20 million increase related to higher natural gas prices, partially offset by a $10 million decrease related to lower KWH sales.

Fuel and Purchased Power Expenses

	Second Quarter 2021 vs. Second Quarter 2020			Year-To-Date 2021 vs. Year-To-Date 2020
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	8	9.6	$	30	18.5
Purchased power	4		57.1	4		33.3
Total fuel and purchased power expenses	$	12		$	34

In the second quarter 2021, total fuel and purchased power expenses were $102 million compared to $90 million for the corresponding period in 2020. The increase was primarily due to a $17 million increase in the average cost of fuel, partially offset by a $5 million decrease associated with the volume of KWHs generated and purchased.

For year-to-date 2021, total fuel and purchased power expenses were $208 million compared to $174 million for the corresponding period in 2020. The increase was primarily due to an increase in the average cost of fuel.

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.

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

	Second Quarter 2021	Second Quarter 2020	Year-To-Date 2021	Year-To-Date 2020
Total generation (in millions of KWHs)	3,813	4,484	8,137	8,651
Total purchased power (in millions of KWHs)	317	208	438	396
Sources of generation (percent) –
Gas	91	96	91	96
Coal	9	4	9	4
Cost of fuel, generated (in cents per net KWH) –
Gas	2.50	1.88	2.45	1.92
Coal	3.06	3.82	3.12	4.02
Average cost of fuel, generated (in cents per net KWH)	2.56	1.97	2.52	2.00
Average cost of purchased power (in cents per net KWH)	3.38	3.27	3.57	2.97

Fuel

In the second quarter 2021, fuel expense was $91 million compared to $83 million for the corresponding period in 2020. The increase was primarily due to a 93.4% increase in the volume of KWHs generated by coal and a 33.0% increase in the average cost of natural gas per KWH generated, partially offset by a 21.0% decrease in the volume of KWHs generated by natural gas and a 19.9% decrease in the average cost of coal per KWH generated.

For year-to-date 2021, fuel expense was $192 million compared to $162 million for the corresponding period in 2020. The increase was due to a 146.5% increase in the volume of KWHs generated by coal and a 27.6% increase in the average cost of natural gas per KWH generated, partially offset by a 22.4% decrease in the average cost of coal per KWH generated and a 12.5% decrease in the volume of KWHs generated by natural gas.

Purchased Power

In the second quarter 2021, purchased power expense was $11 million compared to $7 million for the corresponding period in 2020. For year-to-date 2021, purchased power expense was $16 million compared to $12 million for the corresponding period in 2020. The second quarter and year-to-date 2021 increases reflect increases of 52.4% and 10.6%, respectively, in the volume of KWHs purchased and increases of 3.4% and 20.2%, respectively, in the average cost per KWH purchased primarily due to higher natural gas prices.

Other Operations and Maintenance Expenses

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$9	13.4	$2	1.4

In the second quarter 2021, other operations and maintenance expenses were $76 million compared to $67 million for the corresponding period in 2020. The increase was primarily due to increases of $7 million related to planned generation outage and baseline costs and $2 million related to compensation and benefit costs.

Other Income (Expense), Net

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$5	83.3	$6	42.9

In the second quarter 2021, other income (expense), net was $11 million compared to $6 million for the corresponding period in 2020. For year-to-date 2021, other income (expense), net was $20 million compared to $14

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million for the corresponding period in 2020. The second quarter and year-to-date 2021 increases were primarily related to increases of $3 million and $2 million, respectively, in contributions in aid of construction and $2 million and $3 million, respectively, in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.

Income Taxes

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$6	N/M	$4	50.0

N/M - Not meaningful

In the second quarter 2021, income taxes were $8 million compared to $2 million for the corresponding period in 2020. The increase was primarily due to a $4 million increase associated with the flowback of excess deferred income taxes as a result of the Mississippi Power Rate Case Settlement and a $1 million increase due to higher pre-tax earnings.

For year-to-date 2021, income taxes were $12 million compared to $8 million for the corresponding period in 2020. The increase was primarily due to higher pre-tax earnings.

Southern Power

Net Income Attributable to Southern Power

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(27)	(42.9)	$(5)	(3.6)

Net income attributable to Southern Power for the second quarter 2021 was $36 million compared to $63 million for the corresponding period in 2020. Net income attributable to Southern Power for year-to-date 2021 was $133 million compared to $138 million for the corresponding period in 2020. The decreases were primarily due to an increase in other operations and maintenance expenses associated with scheduled outages and maintenance. Partially offsetting the year-to-date 2021 decrease was a $16 million tax benefit due to changes in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in February 2021.

Operating Revenues

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$51	11.6	$116	14.3

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

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prices of wholesale energy compared to the cost of Southern Power's energy. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.

Solar and Wind Energy Revenue

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

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

Operating Revenues Details

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

	Second Quarter 2021		Second Quarter 2020		Year-To-Date 2021		Year-To-Date 2020
	(in millions)
PPA capacity revenues	$	96	$	92	$	192	$	181
PPA energy revenues	296		270		541		475
Total PPA revenues	392		362		733		656
Non-PPA revenues	93		73		188		151
Other revenues	5		4		9		7
Total operating revenues	$	490	$	439	$	930	$	814

In the second quarter 2021, total operating revenues were $490 million, reflecting a $51 million, or 12%, increase from the corresponding period in 2020. The increase in operating revenues was primarily due to the following:

•PPA capacity revenues increased $4 million, or 4%, primarily due to new natural gas PPAs, which began subsequent to the second quarter 2020, and increased capacity on existing contracts, partially offset by the contractual expiration of natural gas PPAs.

•PPA energy revenues increased $26 million, or 10%, primarily due to a $31 million increase in sales from natural gas facilities resulting from a $39 million increase in the price of fuel and purchased power, partially offset by an $8 million decrease in the volume of KWHs sold.

•Non-PPA revenues increased $20 million, or 27%, due to a $31 million increase in the market price of energy, partially offset by an $11 million decrease in the volume of KWHs sold through short-term sales.

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For year-to-date 2021, total operating revenues were $930 million, reflecting a $116 million, or 14%, increase from the corresponding period in 2020. The increase in operating revenues was primarily due to the following:

•PPA capacity revenues increased $11 million, or 6%, primarily due to new natural gas PPAs, which began subsequent to the second quarter 2020, and increased capacity on existing contracts, partially offset by the disposition of Plant Mankato in the first quarter 2020 and the contractual expiration of natural gas PPAs.

•PPA energy revenues increased $66 million, or 14%, due to a $66 million increase in sales from natural gas facilities resulting from an $82 million increase in the price of fuel and purchased power, partially offset by a $16 million decrease in the volume of KWHs sold.

•Non-PPA revenues increased $37 million, or 25%, due to a $69 million increase in the market price of energy, partially offset by a $32 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:

	Second Quarter 2021	Second Quarter 2020	Year-To-Date 2021	Year-To-Date 2020
	(in billions of KWHs)
Generation	10.3	11.3	19.7	22.0
Purchased power	0.7	0.9	1.3	1.5
Total generation and purchased power	11.0	12.2	21.0	23.5
Total generation and purchased power, excluding solar, wind, and tolling agreements	6.3	7.4	12.4	14.5

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:

	Second Quarter 2021 vs. Second Quarter 2020			Year-To-Date 2021 vs. Year-To-Date 2020
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	38	37.3	$	72	34.4
Purchased power	7		38.9	14		43.8
Total fuel and purchased power expenses	$	45		$	86

In the second quarter 2021, total fuel and purchased power expenses increased $45 million, or 38%, compared to the corresponding period in 2020. Fuel expense increased $38 million due to a $52 million increase in the average cost of fuel per KWH generated, partially offset by a $14 million decrease associated with the volume of KWHs

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generated. Purchased power expense increased $7 million due to a $10 million increase associated with the average cost of purchased power, partially offset by a $3 million decrease associated with the volume of KWHs purchased.

For year-to-date 2021, total fuel and purchased power expenses increased $86 million, or 36%, compared to the corresponding period in 2020. Fuel expense increased $72 million due to a $102 million increase in the average cost of fuel per KWH generated, partially offset by a $30 million decrease associated with the volume of KWHs generated. Purchased power expense increased $14 million due to a $19 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

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$34	44.2	$55	35.3

In the second quarter 2021, other operations and maintenance expenses were $111 million compared to $77 million for the corresponding period in 2020. The increase was primarily due to increases of $20 million in scheduled outage and maintenance expenses and $4 million in expenses associated with new wind facilities placed in service in 2020 and 2021.

For year-to-date 2021, other operations and maintenance expenses were $211 million compared to $156 million for the corresponding period in 2020. The increase was primarily due to increases of $27 million in scheduled outage and maintenance expenses, $6 million in expenses associated with new wind facilities placed in service in 2020 and 2021, 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.

Depreciation and Amortization

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$11	9.1	$12	5.0

In the second quarter 2021, depreciation and amortization was $132 million compared to $121 million for the corresponding period in 2020. For year-to-date 2021, depreciation and amortization was $251 million compared to $239 million for the corresponding period in 2020. The increases were primarily associated with new wind facilities placed in service in 2020 and 2021.

(Gain) Loss on Dispositions, Net

Second Quarter 2021 vs. Second 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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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.

Income Taxes (Benefit)

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(8)	(133.3)	$(24)	(184.6)

In the second quarter 2021, income tax benefit was $2 million compared to income tax expense of $6 million for the corresponding period in 2020. The change was primarily due to lower pre-tax earnings.

For year-to-date 2021, income tax benefit was $11 million compared to income tax expense of $13 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.

Southern Company Gas

Operating Metrics

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

Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. Southern Company Gas has various regulatory mechanisms, such as weather and revenue normalization and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its utility's respective service territory. 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.

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Net Income (Loss)

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(136)	(191.5)	$(13)	(3.8)

In the second quarter 2021, net loss was $65 million compared to income of $71 million for the corresponding period in 2020. The decrease was primarily due to an $89 million decrease at wholesale gas services primarily due to an increase in derivative losses, partially offset by higher commercial activities, and an after-tax impairment charge of $58 million at gas pipeline investments related to the PennEast Pipeline project. These decreases were partially offset by a $6 million increase at gas distribution operations primarily due to base rate increases and continued investment in infrastructure replacement.

For year-to-date 2021, net income was $333 million compared to $346 million for the corresponding period in 2020. The decrease was primarily due to an after-tax impairment charge of $58 million at gas pipeline investments related to the PennEast Pipeline project, partially offset by a $25 million increase at gas distribution operations primarily due to base rate increases and continued investment in infrastructure replacement and a $14 million increase at wholesale gas services primarily due to higher commercial activities as a result of Winter Storm Uri, partially offset by derivative losses.

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

Natural Gas Revenues, including Alternative Revenue Programs

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$41	6.4	$486	25.8

In the second quarter 2021, natural gas revenues, including alternative revenue programs, were $677 million compared to $636 million for the corresponding period in 2020. For year-to-date 2021, natural gas revenues, including alternative revenue programs, were $2.4 billion compared to $1.9 billion for the corresponding period in 2020.

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

	Second Quarter 2021				Year-To-Date 2021
	(in millions)		(% change)		(in millions)		(% change)
Natural gas revenues – prior year	$	636			$	1,885
Estimated change resulting from –
Infrastructure replacement programs and base rate changes	41		6.4	%	81		4.3	%
Gas costs and other cost recovery	88		13.8		240		12.7
Wholesale gas services	(91)		(14.3)		156		8.3
Other	3		0.5		9		0.5
Natural gas revenues – current year	$	677	6.4	%	$	2,371	25.8	%

Revenues from infrastructure replacement programs and base rate changes increased in the second 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.

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

Revenues from wholesale gas services decreased in the second quarter 2021 compared to the corresponding period in 2020 due to derivative losses, partially offset by higher commercial activities. Revenues from wholesale gas services increased for year-to-date 2021 compared to the corresponding period in 2020 due to higher volumes sold and higher commercial activities as a result of Winter Storm Uri, partially offset by derivative losses. 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 information regarding the sale of Sequent on July 1, 2021.

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.

	Second Quarter			2021 vs. normal		2021 vs. 2020		Year-to-Date			2021 vs. normal		2021 vs. 2020
	Normal(*)	2021	2020	colder (warmer)		(warmer)		Normal(*)	2021	2020	(warmer)		colder
	(in thousands)							(in thousands)
Illinois	657	634	736	(3.5)	%	(13.9)	%	3,681	3,580	3,495	(2.7)	%	2.4	%
Georgia	125	142	188	13.6	%	(24.5)	%	1,451	1,396	1,279	(3.8)	%	9.1	%

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

	June 30,
	2021		2020		2021 vs. 2020
	(in thousands, except market share %)				(% change)
Gas distribution operations	4,300		4,275		0.6	%
Gas marketing services
Energy customers(*)	612		671		(8.8)	%
Market share of energy customers in Georgia	29.1	%	29.0	%	0.3	%

(*)Gas marketing services' customers are primarily located in Georgia and Illinois. June 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 continued customer growth as it expects continued low natural gas prices. Southern Company Gas uses a variety of targeted marketing programs to attract new customers and to retain existing customers.

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Cost of Natural Gas

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$87	60.4	$231	39.6

Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. Cost of natural gas at gas distribution operations represented 87% of total cost of natural gas for both the second quarter and year-to-date 2021. 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 second quarter 2021, cost of natural gas was $231 million compared to $144 million for the corresponding period in 2020. The increase reflects higher gas cost recovery and a 65.0% increase in natural gas prices in the second quarter 2021 compared to the corresponding period in 2020.

For year-to-date 2021, cost of natural gas was $814 million compared to $583 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 50.6% increase in natural gas prices for year-to-date 2021 compared to the corresponding period in 2020.

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

	Second Quarter		2021 vs. 2020		Year-to-Date		2021 vs. 2020
	2021	2020			2021	2020
Gas distribution operations (mmBtu in millions)
Firm	103	100	3.0	%	391	357	9.5	%
Interruptible	23	21	9.5		50	45	11.1
Total	126	121	4.1	%	441	402	9.7	%
Wholesale gas services (mmBtu in millions/day)
Daily physical sales	6.1	6.4	(4.7)	%	6.6	6.6	—	%
Gas marketing services (mmBtu in millions)
Firm:
Georgia	4	4	—	%	23	18	27.8	%
Illinois	1	1	—		5	6	(16.7)
Other	2	3	(33.3)		8	7	14.3
Interruptible large commercial and industrial	3	3	—		7	7	—
Total	10	11	(9.1)	%	43	38	13.2	%

Other Operations and Maintenance Expenses

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$13	5.9	$53	11.1

In the second quarter 2021, other operations and maintenance expenses were $233 million compared to $220 million for the corresponding period in 2020. For year-to-date 2021, other operations and maintenance expenses were $532 million compared to $479 million for the corresponding period in 2020. The increases were primarily

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due to higher compensation expenses, primarily related to an increase in variable compensation at wholesale gas services.

Depreciation and Amortization

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$10	8.1	$20	8.2

In the second quarter 2021, depreciation and amortization was $133 million compared to $123 million for the corresponding period in 2020. For year-to-date 2021, depreciation and amortization was $263 million compared to $243 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

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$2	4.3	$12	10.2

In the second quarter 2021, taxes other than income taxes were $49 million compared to $47 million for the corresponding period in 2020. For year-to-date 2021, taxes other than income taxes were $130 million compared to $118 million for the corresponding period in 2020. The increases primarily reflect 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.

Earnings (Loss) from Equity Method Investments

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(82)	(273.3)	$(83)	(115.3)

In the second quarter 2021, loss from equity method investments was $52 million compared to earnings of $30 million for the corresponding period in 2020. For year-to-date 2021, loss from equity method investments was $11 million compared to earnings of $72 million for the corresponding period in 2020. The decreases were primarily due to a pre-tax impairment charge of $82 million recorded in the second quarter 2021 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, for additional information.

Other Income (Expense), Net

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(26)	(216.7)	$(99)	(471.4)

In the second quarter 2021, other income (expense), net was $14 million of expense compared to $12 million of income for the corresponding period in 2020. For year-to-date 2021, other income (expense), net was $78 million of expense compared to $21 million of income for the corresponding period in 2020. The increases in other expense were primarily due to charitable contributions of $26 million and $101 million in the second quarter and year-to-date 2021, respectively.

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Income Taxes (Benefit)

Second Quarter 2021 vs. Second Quarter 2020		Year-To-Date 2021 vs. Year-To-Date 2020
(change in millions)	(% change)	(change in millions)	(% change)
$(45)	(281.3)	$(3)	(3.2)

In the second quarter 2021, income tax benefit was $29 million compared to income tax expense of $16 million for the corresponding period in 2020. The change was primarily the result of a pre-tax impairment charge at gas pipeline investments related to the PennEast Pipeline project and a pre-tax loss at wholesale gas services in the second quarter 2021. For year-to-date 2021, income taxes were $92 million compared to $95 million for the corresponding period in 2020. The pre-tax impairment charge at gas pipeline investments was largely offset by higher pre-tax earnings at wholesale gas services and gas distribution operations. 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.

Performance and Non-GAAP Measures

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

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

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

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

	Second Quarter 2021		Second Quarter 2020		Year-To-Date 2021		Year-To-Date 2020
	(in millions)
Operating Income	$	31	$	102	$	632	$	462
Other operating expenses(a)	415		390		925		840
Revenue taxes(b)	(22)		(22)		(75)		(67)
Adjusted Operating Margin	$	424	$	470	$	1,482	$	1,235

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

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

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Segment Information

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

	Second Quarter 2021						Second Quarter 2020
	Adjusted Operating Margin(*)		Operating Expenses(*)		Net Income (Loss)		Adjusted Operating Margin(*)		Operating Expenses(*)		Net Income (Loss)
	(in millions)						(in millions)
Gas distribution operations	$	486	$	340	$	80	$	441	$	314	$	74
Gas pipeline investments	8		3		(36)		8		3		21
Wholesale gas services	(110)		11		(112)		(19)		11		(23)
Gas marketing services	35		25		6		35		28		5
All other	6		15		(3)		7		14		(6)
Intercompany eliminations	(1)		(1)		—		(2)		(2)		—
Consolidated	$	424	$	393	$	(65)	$	470	$	368	$	71

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

	Year-To-Date 2021						Year-To-Date 2020
	Adjusted Operating Margin(*)		Operating Expenses(*)		Net Income (Loss)		Adjusted Operating Margin(*)		Operating Expenses(*)		Net Income (Loss)
	(in millions)						(in millions)
Gas distribution operations	$	1,130	$	697	$	263	$	1,036	$	654	$	238
Gas pipeline investments	16		6		(7)		16		6		51
Wholesale gas services	187		66		14		31		28		—
Gas marketing services	139		54		62		142		58		62
All other	13		30		1		13		30		(5)
Intercompany eliminations	(3)		(3)		—		(3)		(3)		—
Consolidated	$	1,482	$	850	$	333	$	1,235	$	773	$	346

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

Gas Distribution Operations

Gas distribution operations is the largest component of Southern Company Gas' business and is subject to regulation and oversight by regulatory agencies in each of the states it serves. These agencies approve natural gas rates designed to provide Southern Company Gas with the opportunity to generate revenues to recover the cost of natural gas delivered to its customers and its fixed and variable costs, including depreciation, interest expense, operations and maintenance, taxes, and overhead costs, and to earn a reasonable return on its investments.

With the exception of Atlanta Gas Light, Southern Company Gas' second largest utility that operates in a deregulated natural gas market and has a straight-fixed-variable rate design that minimizes the variability of its revenues based on consumption, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas, and general economic conditions that may impact customers' ability to pay for natural gas consumed. Southern Company Gas has various regulatory and other mechanisms, such as weather and revenue normalization mechanisms and weather derivative

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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 second quarter and year-to-date 2021, net income increased $6 million, or 8.1%, and $25 million, or 10.5%, respectively, when compared to the corresponding periods in 2020. In the second quarter and year-to-date 2021, adjusted operating margin increased $45 million and $94 million, respectively, when compared to the corresponding periods in 2020 primarily due to rate increases for Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas and continued investment in infrastructure replacement. In the second quarter and year-to-date 2021, operating expenses increased $26 million and $43 million, respectively, when compared to the corresponding periods in 2020 primarily due to higher depreciation resulting from additional assets placed in service, as well as higher compensation expenses. In the second quarter and year-to-date 2021, interest expense, net of amounts capitalized increased $5 million and $10 million, respectively, when compared to the corresponding periods in 2020 primarily due to additional debt issued to finance continued investments. In the second quarter and year-to-date 2021, income taxes increased $6 million and $12 million, respectively, when compared to the corresponding periods in 2020 primarily due to higher pre-tax earnings.

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.

For the second quarter and year-to-date 2021, net income decreased $57 million and $58 million, respectively, when compared to the corresponding periods in 2020. The decreases were due to a pre-tax impairment charge of $82 million ($58 million after tax) related to the equity method investment in 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, for additional information.

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 second quarter 2021, net income decreased $89 million when compared to the corresponding period in 2020. The decrease primarily relates to a $91 million decrease in adjusted operating margin and a $26 million decrease in other income and (expense) related to higher charitable contributions, partially offset by a $27 million decrease in income tax expense due to lower pre-tax earnings.

For year-to-date 2021, net income increased $14 million when compared to the corresponding period in 2020. The increase primarily relates to a $156 million increase in adjusted operating margin, partially offset by a $38 million increase in operating expenses primarily related to an increase in variable compensation. The increase was also partially offset by a $101 million decrease in other income and (expense) related to higher charitable contributions and a $4 million increase in income tax expense due to higher pre-tax earnings.

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

	Second Quarter 2021		Second Quarter 2020		Year-To-Date 2021		Year-To-Date 2020
	(in millions)
Commercial activity recognized	$	(6)	$	(33)	$	309	$	(42)
Gain (loss) on storage derivatives	(24)		(5)		(26)		(11)
Gain (loss) on transportation and forward commodity derivatives	(80)		19		(96)		85
Purchase accounting adjustments to fair value inventory and contracts	—		—		—		(1)
Adjusted operating margin	$	(110)	$	(19)	$	187	$	31

Change in Commercial Activity

The commercial activity at wholesale gas services includes recognition of storage and transportation values that were generated in prior periods, which reflect the impact of prior period hedge gains and losses as associated physical transactions occur. The increase in commercial activity in the second quarter 2021 compared to the corresponding period in 2020 was primarily due to large losses in the second quarter 2020 driven by mild weather and tight transportation spreads. 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.

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. 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.

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Segment Reconciliations

Reconciliations of operating income to adjusted operating margin for the second quarter and year-to-date 2021 and 2020 are reflected in the following tables. See Note (L) to the Condensed Financial Statements herein for additional information.

	Gas Distribution Operations		Gas Pipeline Investments		Wholesale Gas Services		Gas Marketing Services		All Other		Intercompany Elimination		Consolidated
	(in millions)
Second Quarter 2021
Operating Income (Loss)	$	146	$	5	$	(121)	$	10	$	(9)	$	—	$	31
Other operating expenses(a)	362		3		11		25		15		(1)		415
Revenue tax expense(b)	(22)		—		—		—		—		—		(22)
Adjusted Operating Margin	$	486	$	8	$	(110)	$	35	$	6	$	(1)	$	424
Second Quarter 2020
Operating Income (Loss)	$	127	$	5	$	(30)	$	7	$	(7)	$	—	$	102
Other operating expenses(a)	336		3		11		28		14		(2)		390
Revenue tax expense(b)	(22)		—		—		—		—		—		(22)
Adjusted Operating Margin	$	441	$	8	$	(19)	$	35	$	7	$	(2)	$	470
Year-To-Date 2021
Operating Income (Loss)	$	433	$	10	$	121	$	85	$	(17)	$	—	$	632
Other operating expenses(a)	772		6		66		54		30		(3)		925
Revenue tax expense(b)	(75)		—		—		—		—		—		(75)
Adjusted Operating Margin	$	1,130	$	16	$	187	$	139	$	13	$	(3)	$	1,482
Year-To-Date 2020
Operating Income (Loss)	$	382	$	10	$	3	$	84	$	(17)	$	—	$	462
Other operating expenses(a)	721		6		28		58		30		(3)		840
Revenue tax expense(b)	(67)		—		—		—		—		—		(67)
Adjusted Operating Margin	$	1,036	$	16	$	31	$	142	$	13	$	(3)	$	1,235

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

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

FUTURE EARNINGS POTENTIAL

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

For the traditional electric operating companies, these factors include the ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs during a time of increasing costs, continued customer growth, and the trend of reduced electricity usage per customer, especially in residential and

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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. The combination of rising inoculation rates in the U.S. population and the recent federal COVID-19 relief package is expected to help boost economic recovery in 2021. 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 half 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 in the second half 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 half 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 optimize its transportation and storage positions and to re-contract storage rates at favorable prices. The volatility of natural gas prices has an impact on Southern Company Gas' customer rates, its long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services business to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a portion of Southern Company Gas' operations to earnings variability. Over the longer term, volatility is expected to be low to moderate and locational and/or transportation spreads are expected to decrease as new pipelines are built to reduce the existing supply constraints in the shale areas of the Northeast U.S. To the extent these pipelines are delayed or not built, volatility could increase. See Note 3 to the financial statements in Item 8 of the Form 10-K and Note (C) to the Condensed Financial Statements herein under "Other Matters – Southern Company Gas" for additional information on challenges experienced by the PennEast Pipeline project. Additional economic factors may contribute to this environment, including a significant drop in oil and natural gas prices, which could lead to consolidation of natural gas producers or reduced levels of natural gas production. In addition, if the COVID-19 pandemic results in continued economic uncertainty for a sustained

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period, demand for natural gas may decrease, resulting in further downward pressure on natural gas prices and lower volatility in the natural gas markets on a longer-term basis.

Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather, competition, developing new and maintaining existing energy contracts and associated load requirements with wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, 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.

Alabama Power is assessing the viability of complying with the ELG Rules for certain of its coal units (totaling approximately 2,000 MWs) due to the timing and anticipated cost to comply with the ELG Rules. The results of the assessment could accelerate a determination to discontinue or modify operation of the units. Alabama Power will review all of the facts and circumstances and evaluate all alternatives prior to reaching a final determination. The units under evaluation have net book values totaling approximately $2.3 billion at June 30, 2021. Additionally, net capitalized asset retirement costs associated with these facilities totaled approximately $900 million at June 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 " –

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Environmental Accounting Order" in Item 8 of the Form 10-K for additional information. The ultimate outcome of this matter cannot be determined at this time.

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 July 16, 2021, Alabama Power filed a petition with the Alabama PSC to extend its Renewable Generation Certificate (RGC) expiration from September 16, 2021 to September 16, 2027. The RGC currently in place 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. The ultimate outcome of this matter cannot be determined at this time.

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 Notes 2 and 3 to the financial statements in Item 8 of the Form 10-K and Notes (B) and (C) to the Condensed Financial Statements herein under "Southern Company Gas" and "Other Matters – Southern Company Gas – PennEast Pipeline Project," respectively, 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.

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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. Implementation of the agreement is subject to certain regulatory approvals, including approvals of the Rural Utilities Service, the SERC Reliability Corporation, and the FERC, and is expected to be completed by March 2022. The ultimate outcome of this matter cannot be determined at this time.

ACCOUNTING POLICIES

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

Application of Critical Accounting Policies and Estimates

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

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

(Southern Company and Georgia Power)

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 and fuel load for Unit 3. Hot functional testing for Unit 3 was completed in July 2021. 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. The site work plan currently targets fuel load for Unit 3 in the fourth quarter 2021 and an in-service date of March 2022. As the site work plan includes minimal margin to these milestone dates, an in-service date in the second 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. The site work plan targets an in-service date of November 2022 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

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added and maintained. As the site work plan includes minimal margin to the milestone dates, an in-service date in the first 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. Considering the factors above, during the second quarter 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 described above, 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. Georgia Power's revised base capital cost forecast and contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 is $9.10 billion and $0.12 billion, respectively, for a total capital cost forecast of $9.22 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 and the second quarter 2021 of $48 million ($36 million after tax) and $460 million ($343 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 June 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 second quarter 2021, the market price of Southern Company's common stock was $60.51 per share (based on the closing price as reported on the NYSE) and the book value was $26.63 per share, representing a market-to-book ratio of 227%, compared to $61.43, $26.48, and 232%, respectively, at the end of 2020. Southern Company's common stock dividend for the second quarter 2021 was $0.66 per share compared to $0.64 per share in the second 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

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replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; abnormal weather; delays in construction due to judicial or regulatory action; storm impacts; and the cost of capital. The continued 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.

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 financial statements and are accounted for using HLBV methodology to allocate partnership gains and losses. In March 2021, Southern Power obtained tax equity funding for the Deuel Harvest wind facility and received proceeds of $220 million. In addition, during the first six months of 2021, Southern Power received tax equity funding totaling $17 million from existing partnerships. Subsequent to June 30, 2021, Southern Power obtained tax equity funding for the Garland battery energy storage facility and received initial proceeds of $11 million. See Note 1 to

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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 June 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 June 30, 2021 for the applicable Registrants:

At June 30, 2021	Southern Company		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Current liabilities in excess of current assets	$	2,109	$	1,438	$	20	$	720	$	477

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 June 30, 2021, the Registrants' unused committed credit arrangements with banks were as follows:

At June 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	$	1,228	$	1,728	$	250	$	568	$	1,747	$	30	$	7,550

(a)At June 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 June 30, 2021 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, and $34 million at Mississippi Power). In addition, at June 30, 2021, Georgia Power and Mississippi Power had approximately $105 million and $50 million, respectively, of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months.

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

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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 June 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	$	1,402	0.3	%	$	990	0.3	%	$	1,621
Alabama Power	—		—		50		0.1		200
Georgia Power	310		0.2		183		0.2		407
Mississippi Power	—		—		39		0.2		81
Southern Power	119		0.2		152		0.2		315
Southern Company Gas:
Southern Company Gas Capital	$	444	0.2	%	$	85	0.2	%	$	485
Nicor Gas	390		0.5		396		0.5		512
Southern Company Gas Total	$	834	0.3	%	$	481	0.5	%

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

Analysis of Cash Flows

Net cash flows provided from (used for) operating, investing, and financing activities for the six months ended June 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)
Six Months Ended June 30, 2021
Operating activities	$	2,904	$	584	$	1,313	$	41	$	411	$	722
Investing activities	(4,026)		(893)		(1,730)		(117)		(601)		(668)
Financing activities	1,671		506		457		515		196		(25)
Six Months Ended June 30, 2020
Operating activities	$	2,847	$	674	$	1,124	$	71	$	195	$	1,046
Investing activities	(2,655)		(783)		(1,659)		(145)		490		(570)
Financing activities	(285)		116		869		(178)		(808)		(401)

Fluctuations in cash flows from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

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Southern Company

Net cash provided from operating activities increased $0.1 billion for the six months ended June 30, 2021 as compared to the corresponding period in 2020 primarily due to the timing of vendor payments and customer bill credits issued in 2020 at Georgia Power, partially offset by under recovered natural gas costs at Southern Company Gas resulting from Winter Storm Uri and decreased fuel cost recovery at the traditional electric operating companies resulting from an increase in the cost of fuel.

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

The net cash provided from financing activities for the six months ended June 30, 2021 was primarily related to net issuances of long-term debt, commercial paper, and short-term bank loans, partially offset by common stock dividend payments.

Alabama Power

Net cash provided from operating activities decreased $90 million for the six months ended June 30, 2021 as compared to the corresponding period in 2020 primarily due to the timing of income tax payments and decreased fuel cost recovery, partially offset by an increase in retail revenues associated with an increase in Rate RSE effective in January 2021 and colder weather in Alabama Power's service territory in the first quarter 2021 compared to the corresponding period in 2020, as well as the timing of fossil fuel stock purchases.

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

The net cash provided from financing activities for the six months ended June 30, 2021 was primarily related to a capital contribution from Southern Company and the net issuance of senior notes, partially offset by common stock dividend payments.

Georgia Power

Net cash provided from operating activities increased $189 million for the six months ended June 30, 2021 as compared to the corresponding period in 2020 primarily due to customer bill credits issued in 2020 associated with Tax Reform and 2018 earnings in excess of the allowed retail ROE range and the timing of fossil fuel stock purchases and vendor payments, partially offset by decreased fuel cost recovery.

The net cash used for investing activities for the six months ended June 30, 2021 was primarily related to gross property additions, including a total of approximately $640 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 six months ended June 30, 2021 was primarily related to net issuances of senior notes, borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, capital contributions from Southern Company, and an increase in notes payable, partially offset by common stock dividend payments.

Mississippi Power

Net cash provided from operating activities decreased $30 million for the six months ended June 30, 2021 as compared to the corresponding period in 2020 primarily due to decreased fuel cost recovery and the timing of vendor payments.

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

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

Southern Power

Net cash provided from operating activities increased $216 million for the six months ended June 30, 2021 as compared to the corresponding period in 2020 primarily due to an increase in the utilization of tax credits in 2021.

The net cash used for investing activities for the six months ended June 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 six months ended June 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 and common stock dividend payments.

Southern Company Gas

Net cash provided from operating activities decreased $324 million for the six months ended June 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 six months ended June 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.

The net cash used for financing activities for the six months ended June 30, 2021 was primarily related to the repayment of long-term debt and common stock dividend payments, largely offset by the issuance of short-term debt, an increase in commercial paper borrowings, and capital contributions from Southern Company.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

Significant Balance Sheet Changes

Southern Company

Significant balance sheet changes for the six months ended June 30, 2021 included:

•an increase of $2.1 billion in long-term debt (including securities due within one year) related to new issuances;

•an increase of $2.0 billion in total property, plant, and equipment (net of pre-tax charges totaling $508 million recorded in the first half of 2021 for estimated probable losses associated with the construction of Plant Vogtle Units 3 and 4) primarily related to the Subsidiary Registrants' construction programs, as well as Southern Power's acquisition of the Deuel Harvest wind facility;

•an increase of $0.8 billion in notes payable related to net issuances of short-term bank debt and commercial paper;

•an increase of $0.7 billion in both assets and liabilities held for sale, due to the reclassification of assets and liabilities associated with Southern Company Gas' sale of Sequent, including $0.5 billion of energy marketing receivables and $0.5 billion of energy marketing trade payables;

•an increase of $0.5 billion in accumulated deferred income taxes primarily related to the utilization and expected further utilization of tax credits in 2021;

•an increase of $0.5 billion in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Southern Company" herein;

•an increase of $0.5 billion in natural gas cost under recovery, which was impacted by an increase in Southern Company Gas' cost of gas purchased during Winter Storm Uri; and

•an increase of $0.5 billion in total stockholders' equity primarily related to net income, partially offset by common stock dividend payments.

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

Alabama Power

Significant balance sheet changes for the six months ended June 30, 2021 included:

•an increase of $827 million in common stockholder's equity primarily due to capital contributions from Southern Company;

•an increase of $450 million in total property, plant, and equipment primarily related to construction of Plant Barry Unit 8 and distribution and transmission facilities, as well as the installation of equipment to comply with environmental standards; and

•an increase of $396 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 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 six months ended June 30, 2021 included:

•an increase of $656 million in total property, plant, and equipment primarily related to the construction of generation, transmission, and distribution facilities, including $151 million for Plant Vogtle Units 3 and 4 (net of pre-tax charges totaling $508 million recorded in the first half of 2021 for estimated probable losses);

•an increase of $680 million in long-term debt (including securities due within one year) primarily due to a net increase in outstanding senior notes and borrowings from the FFB for construction of Plant Vogtle Units 3 and 4; and

•an increase of $250 million in notes payable related to net issuances of commercial paper.

See "Financing Activities – Georgia Power" herein and Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information.

Mississippi Power

Significant balance sheet changes for the six months ended June 30, 2021 included:

•an increase of $439 million in cash and cash equivalents and an increase of $514 million in long-term debt (including securities due within one year) primarily due to the issuance of senior notes;

•an increase of $107 million in common stockholder's equity primarily from capital contributions from Southern Company; and

•a decrease of $51 million in accrued taxes primarily due to the payment of ad valorem taxes.

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

Southern Power

Significant balance sheet changes for the six months ended June 30, 2021 included:

•an increase of $468 million in property, plant, and equipment in service primarily due to the acquisition of the Deuel Harvest wind facility;

•an increase of $356 million in long-term debt (including securities due within one year) primarily related to the issuance of senior notes; and

•an increase of $142 million in prepaid income taxes, a decrease of $262 million in accumulated deferred income tax assets, and a $98 million increase in accumulated deferred income tax liabilities primarily related to the utilization and expected further utilization of ITCs in 2021.

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 six months ended June 30, 2021 included:

•increases of $736 million and $677 million in assets and liabilities held for sale, respectively, due to the reclassification of assets and liabilities associated with the sale of Sequent, including $516 million of energy marketing receivables and $494 million of energy marketing trade payables;

•an increase of $510 million in notes payable due to issuances of short-term debt and an increase in commercial paper borrowings;

•increases of $485 million in natural gas cost under recovery, $82 million in other regulatory assets, deferred, and $148 million in accumulated deferred income taxes, all primarily related to natural gas cost under recovery, reflecting an increase in the cost of gas purchased during Winter Storm Uri;

•an increase of $461 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;

•a decrease of $344 million in long-term debt (including securities due within one year) primarily due to the redemption of senior notes;

•a decrease of $282 million in natural gas for sale primarily due to higher volumes of natural gas sold;

•an increase of $182 million in temporary LIFO liquidation due to higher natural gas prices during Winter Storm Uri;

•an increase of $162 million in common stockholder's equity primarily related to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company;

•an increase of $114 million in prepaid expenses primarily due to the prepayment of income taxes; and

•a decrease of $101 million in equity investments in unconsolidated subsidiaries primarily due to an $82 million impairment charge related to the PennEast Pipeline project.

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

Financing Activities

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

	Issuances				Maturities, Redemptions, and Repurchases
Company	Senior Notes		Other Long-Term Debt		Senior Notes		Revenue Bonds		Other Long-Term Debt(*)
	(in millions)
Southern Company parent	$	1,000	$	1,000	$	1,500	$	—	$	—
Alabama Power	600		—		200		—		—
Georgia Power	750		371		325		69		46
Mississippi Power	525		—		—		—		—
Southern Power	400		—		—		—		—
Southern Company Gas	—		—		300		—		30
Other	—		—		—		—		7
Southern Company	$	3,275	$	1,371	$	2,325	$	69	$	83

(*)Includes reductions in finance lease obligations resulting from cash payments under finance leases and, for Georgia Power, principal amortization payments for FFB borrowings.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

Except as otherwise described herein, the Registrants used the proceeds of debt issuances for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including working capital. The Subsidiary Registrants also used the proceeds for their construction programs.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Registrants plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

Southern Company

During the first six months of 2021, Southern Company issued approximately 2.4 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $24 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.

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.

Subsequent to June 30, 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.

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 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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

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, which may be remarketed to the public at a later date.

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 six months ended June 30, 2021, Georgia Power made principal amortization payments of $45 million under the FFB Credit Facilities. At June 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.

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.

Also in June 2021, Mississippi Power announced the redemption in July 2021 of 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.

Subsequent to June 30, 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, each bearing interest based on one-month LIBOR.

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.

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.

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

Credit Rating Risk

At June 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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

The maximum potential collateral requirements under these contracts at June 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	$	40	$	1	$	—	$	—	$	39	$	—
At BBB- and/or Baa3	431		2		61		1		369		—
At BB+ and/or Ba1 or below	1,942		370		968		310		1,216		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 June 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.

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 second quarter 2021. For an in-depth discussion of Southern Company Gas' market price risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" in Item 7 of the Form 10-K. Also see 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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

The changes in net fair value of Southern Company Gas' energy-related derivative contracts for the periods presented are provided in the table below. Contracts outstanding at the end of the period for Sequent's energy-related derivatives are included in the preliminary gain associated with the transaction, which will be recorded in the third quarter 2021, as discussed further in Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein.

	Second Quarter 2021		Second Quarter 2020		Year-To-Date 2021		Year-To-Date 2020
	(in millions)
Contracts outstanding at beginning of period, assets (liabilities), net	$	40	$	38	$	101	$	70
Contracts realized or otherwise settled	(9)		(8)		(58)		(99)
Current period changes(a)	(75)		19		(87)		78
Contracts outstanding at the end of period, assets (liabilities), net	$	(44)	$	49	$	(44)	$	49
Netting of cash collateral	41		114		41		114
Cash collateral and net fair value of contracts outstanding at end of period(b)	$	(3)	$	163	$	(3)	$	163

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

(b)Includes $(22) million of energy-related derivatives related to Sequent, which are classified as held for sale at June 30, 2021. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" and "Assets and Liabilities Held for Sale" herein for additional information.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk.

During the six months ended June 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 second 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)	-	Eleventh Supplemental Indenture to Subordinated Note Indenture dated as of May 6, 2021, providing for amendments to the Subordinated Note Indenture and the issuance of the Series 2021A 3.75% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due September 15, 2051. (Designated in Form 8-K dated May 3, 2021, File No. 1-3526, as Exhibit 4.4)
		Alabama Power
		(b)	-	Sixty-First Supplemental Indenture to Senior Note Indenture dated as of June 11, 2021, providing for amendments to the Senior Note Indenture and the issuance of the Series 2021A 3.125% Senior Notes due July 15, 2051. (Designated in Form 8-K dated June 7, 2021, File No. 1-3164, as Exhibit 4.6)
		Mississippi Power
		(c)1	-	Sixteenth Supplemental Indenture to Senior Note Indenture dated as of June 29, 2021, providing for amendments to the Senior Note Indenture and the issuance of the Series 2021A Floating Rate Senior Notes due June 28, 2024. (Designated in Form 8-K dated June 24, 2021, File No. 001-11229, as Exhibit 4.2(a))
		(c)2	-	Seventeenth Supplemental Indenture to Senior Note Indenture dated as of June 29, 2021, providing for the issuance of the Series 2021B 3.10% Senior Notes due July 30, 2051. (Designated in Form 8-K dated June 24, 2021, File No. 001-11229, as Exhibit 4.2(b))
		(10) Material Contracts
		Southern Company
#		(a)1	-	The Southern Company 2021 Equity and Incentive Compensation Plan, effective May 26, 2021. (Designated in Form 8-K dated May 26, 2021, File No. 1-3526, as Exhibit 10.1)
#	*	(a)2	-	Deferred Compensation Plan for Outside Directors of The Southern Company, Amended and Restated Effective June 1, 2021.
		Alabama Power
#		(b)1	-	The Southern Company 2021 Equity and Incentive Compensation Plan, effective May 26, 2021. See Exhibit 10(a) herein.
#	*	(b)2	-	Deferred Compensation Plan for Outside Directors of Alabama Power Company, Amended and Restated Effective June 1, 2021.

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	(24) Power of Attorney and Resolutions
	Southern Company
	(a)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2020, File No. 1-3526 as Exhibit 24(a).)
	Alabama Power
	(b)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2020, File No. 1-3164 as Exhibit 24(b).)
	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 Daniel S. Tucker. (Designated in the Form 10-K for the year ended December 31, 2020, File No. 1-6468 as Exhibit 24(c)2.)
	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.

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	Mississippi Power
*	(d)1	-	Certificate of Mississippi Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(d)2	-	Certificate of Mississippi Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	Southern Power
*	(e)1	-	Certificate of Southern Power Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(e)2	-	Certificate of Southern Power Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	Southern Company Gas
*	(f)1	-	Certificate of Southern Company Gas' Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(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.

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	(101) Interactive Data Files
*	INS	-	XBRL Instance Document – The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
*	SCH	-	XBRL Taxonomy Extension Schema Document
*	CAL	-	XBRL Taxonomy Calculation Linkbase Document
*	DEF	-	XBRL Definition Linkbase Document
*	LAB	-	XBRL Taxonomy Label Linkbase Document
*	PRE	-	XBRL Taxonomy Presentation Linkbase Document
	(104) Cover Page Interactive Data File
*			Formatted as inline XBRL with applicable taxonomy extension information contained in Exhibits 101.

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THE SOUTHERN COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

	THE SOUTHERN COMPANY
By	Thomas A. Fanning
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	Andrew W. Evans
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: July 28, 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: July 28, 2021

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GEORGIA POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

	GEORGIA POWER COMPANY
By	Christopher C. Womack
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	Daniel S. Tucker
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: July 28, 2021

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    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: July 28, 2021

164

    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: July 28, 2021

165

    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: July 28, 2021

166

EX-10.A2

Exhibit 10(a)2

DEFERRED COMPENSATION PLAN FOR

OUTSIDE DIRECTORS OF THE SOUTHERN COMPANY

Amended and Restated Effective June 1, 2021

SECTION 1

Purpose and Adoption of Plan

1.1    Adoption

The Southern Company previously established the Deferred Compensation Plan for Outside Directors of The Southern Company. The Plan has been amended from time to time including an amendment and restatement dated January 1, 2000, a good faith amendment and restatement effective January 1, 2008 to comply with Code Section 409A and this amendment and restatement effective June 1, 2021. Except as otherwise provided herein and consistent with Section 1.2, the terms of the Plan as in effect prior to January 1, 2008 shall continue to be applicable to deferrals made pursuant to the Plan prior to January 1, 2008.

1.2    Pre-2005 Deferrals

Compensation paid to Directors and deferred under the Plan prior to January 1, 2005 shall be treated by Southern as not subject to Code Section 409A and therefore “grandfathered.” The Account balance (plus earnings thereon) of the “grandfathered” deferrals shall only be subject to the provisions of the Plan in effect prior to January 1, 2005 as set forth in the Provisions for Pre-2005 Deferrals Under the Deferred Compensation Plan for Outside Directors of The Southern Company (the “Pre-2005 Terms”). In accordance with transition rules under Code Section 409A, Internal Revenue Service Notice 2005-1, and any other applicable guidance from the Department of Treasury, the provisions of the Pre-2005 Terms are only intended to preserve the rights and features of the “grandfathered” deferrals and are, therefore, not intended to be “materially modified” with respect to any aspect of such rights and features. Provisions of the prior Plan should be so construed whenever necessary or appropriate.

SECTION 2

Purpose

The Plan provides Directors with an opportunity to defer compensation paid to them until a date following their Separation from Service.

SECTION 3

Eligibility

An individual who serves as a Director and is not otherwise actively employed by the Company or any of its subsidiaries or affiliates is eligible to participate in the Plan.

SECTION 4

Plan Periods

Except as pertains to a Director’s initial Plan Period, all Plan Periods shall be on a calendar year basis. The initial Plan Period applicable to any person elected to the Board who

was not a Director on the preceding December 31, shall begin on the first day of the calendar quarter following the effective date of the Director’s election to the Board.

SECTION 5

Elections

5.1    Cash Compensation

(a)    Prior to the beginning of a Plan Period, a Director may direct that payment of all or any portion of Cash Compensation that otherwise would be paid to the Director for the Plan Period, be deferred in amounts as designated by the Director, and credited to (i) a Prime Rate Investment Account, (ii) a Phantom Stock Investment Account, or (iii) a Deferred Stock Account. With respect to a Director’s initial Plan Period, such deferral election shall be made in a timely manner prior to the commencement of the Plan Period in accordance with requirements established by the Board consistent with Section 4. Upon the Director’s Separation from Service, such deferred compensation and accumulated investment return held in the Director’s Deferred Compensation Accounts shall be distributed to the Director in accordance with the Director’s Distribution Election and the provisions of Section 7.

(b)    An election to defer Cash Compensation is irrevocable for a Plan Period. Such an election shall continue from Plan Period to Plan Period unless the Director timely changes his or her election to defer Cash Compensation payable in a future Plan Period prior to the beginning of such future Plan Period.

(c)    Cash Compensation deferred under this Section 5.1 shall be invested in Deferred Compensation Accounts as directed by the Director prior to the Compensation Payment Date in accordance with procedures established by the Board.

5.2    Stock Retainer

Director compensation designated as Stock Retainer shall be credited to the Director’s Deferred Stock Account as of the Compensation Payment Date. Upon the Director’s Separation from Service, such compensation and accumulated investment return held in the Director’s Deferred Stock Account shall be distributed to the Director in accordance with the Director’s Distribution Election and the provisions of Section 7.

5.3    No Transfers Between Deferred Compensation Accounts

A Participant may not transfer any portion of the Participant’s Deferred Compensation Account(s) to another Deferred Compensation Account(s).

5.4    Distribution Election

(a)    Except as set forth in Section 5.4(b), prior to the initial establishment of a Deferred Compensation Account for a Director, the Director must elect that upon Separation from Service the values and quantities held in the Director’s Deferred Compensation Accounts be distributed to the Director, pursuant to the provisions of Section 7 in a single lump sum or in a series of annual

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installments not to exceed ten (10) years. The time for the commencement of distributions shall be elected by the Director and shall not be later than the first of the month coinciding with or next following the second anniversary of the Director’s Separation from Service. Notwithstanding the foregoing, a Director may elect to modify his or her distribution election to delay distribution under this Section 5.4 provided that such modification is subject to the requirements of the Modification Delay.

(b)    In the event a Director has transferred to the Board and has Deferred Compensation Accounts established under Section 6.4, then upon the Director’s Separation from Service the Transferred Amounts and accumulated investment return held in the Deferred Compensation Accounts shall be distributed to the Director in accordance with the Director’s distribution election in effect under the applicable deferred compensation plan for directors of Alabama Power Company, Georgia Power Company, Mississippi Power Company, or Southern Company Gas on the date the Director transferred to the Board, and the provisions of Section 7, unless such distribution election is modified to delay distribution pursuant to Section 5.4(a).

5.5    Beneficiary Designation

A Director or former Director may designate a beneficiary to receive distributions from the Plan in accordance with the provisions of Section 7 upon the death of the Director. The beneficiary designation may be changed by a Director or former Director at any time, and without the consent of the prior beneficiary, except as required under applicable law.

5.6    Form of Election

All elections pursuant to the provisions of this Section 5 of the Plan shall be made in writing to the Secretary of the Company or Assistant Secretary of the Company or such other person designated by the Board on a form or forms available upon request.

SECTION 6

Accounts

6.1    Prime Rate Investment Account

A Prime Rate Investment Account shall be established for each Director electing deferral of Cash Compensation for investment at the Prime Interest Rate. The amount of Cash Compensation directed by a Director to be credited to the Prime Rate Investment Account shall be credited to it as of the Compensation Payment Date, as applicable, and credited thereafter with interest computed using the Prime Interest Rate. Interest shall be computed from the date such compensation is credited to the account and compounded quarterly at the end of each calendar quarter. The Prime Interest Rate in effect on the first day of a calendar quarter shall be deemed the Prime Interest Rate in effect for that entire quarter. Interest shall accrue and compound on any balance until the amount credited to the account is fully distributed.

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6.2    Phantom Stock Investment Account

(a)    If a Director elects to direct deferred amounts into the Phantom Stock Investment Account, then, on the applicable Compensation Payment Date, the Director’s Phantom Stock Investment Account shall be credited with a number of Phantom Stock Units equal to (i) the amount deferred into the Phantom Stock Investment Account, divided by (ii) the Market Value on such date, and rounded to the nearest ten-thousandth.

(b)    On the date of the payment of dividends on the Common Stock, a Director’s Phantom Stock Investment Account shall be credited with additional Phantom Stock Units, as follows:

(i)    In the case of dividends payable in cash or property other than cash or Common Stock, a number of Phantom Stock Units equal to (A) the cash or fair market value of any dividends declared and made with respect to the Common Stock payable in cash or other property which the Director would have received had the Director been the owner on the record dates for the payment of such dividends of the number of shares of Common Stock equal to the number of Phantom Stock Units in the Director’s Phantom Stock Investment Account on such dates, divided by (B) the Market Value on the dividend payment date, rounded to the nearest ten-thousandth; or

(ii)    In the case of dividends payable in Common Stock, a number of Phantom Stock Units equal to the number of shares of Common Stock to which the Director would have been entitled as Common Stock dividends had such Director been the owner on the record dates for the payments of such stock dividends of the number of shares of Common Stock equal to the number of Phantom Stock Units credited to the Director’s Phantom Stock Investment Account on such dates, rounded to the nearest ten-thousandth.

(c)    In the event of (i) a corporate event or transaction involving the Company that results in a change in the Common Stock, or an exchange of Common Stock for cash, securities other than Common Stock, or other property (including, without limitation, any merger, reorganization, recapitalization, combination or exchange of shares), or (ii) any transaction between the Company and the holders of Common Stock that causes the per-share value of the Common Stock to change (including, without limitation, any conversion of shares, share dividend, share split, spin-off, rights offering, or large non-ordinary cash dividend), the Board shall make such equitable adjustments to the Phantom Stock Units as it deems necessary, in its sole discretion, to prevent dilution or enlargement of rights immediately resulting from such transaction. Notwithstanding the preceding sentence and in any event, any adjustment shall comply with the requirements of Section 409A of the Code.

6.3    Deferred Stock Account

(a)    If a Director elects to direct deferred amounts of Cash Compensation into the Deferred Stock Account, then, on the applicable Compensation Payment Date, the Director’s Deferred Stock Account shall be credited with a number of Deferred Stock Units equal to (i) the amount deferred into the Deferred Stock Account, divided by (ii) the Market Value on the Compensation Payment Date, and rounded to the nearest ten-thousandth; provided, however, that

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the Board may adopt another valuation method so long as such method is communicated in writing to Participants prior to the commencement of the Plan Period during which such valuation method will apply.

(b)    With respect to a deferred Stock Retainer under Section 5.2, on the applicable Compensation Payment Date, the Director’s Deferred Stock Account shall be credited with a number of Deferred Stock Units equal to the number of shares of Common Stock the Director would have received for such Stock Retainer if it had not been deferred.

(c)    On the date of the payment of dividends on the Common Stock, a Director’s Deferred Stock Account shall be credited with additional Deferred Stock Units, as follows:

(i)    In the case of dividends payable in cash or property other than cash or Common Stock, a number of Deferred Stock Units equal to (A) the cash or fair market value of any dividends declared and made with respect to the Common Stock payable in cash or other property which the Director would have received had the Director been the owner on the record dates for the payment of such dividends of the number of shares of Common Stock equal to the number of Deferred Stock Units in the Director’s Deferred Stock Account on such dates, divided by (B) the Market Value on the dividend payment date, rounded to the nearest ten-thousandth; provided, however, that the Board may adopt another valuation method so long as such method is communicated in writing to Participants prior to the commencement of the Plan Period during which such valuation method will apply; or

(ii)    In the case of dividends payable in Common Stock, a number of Deferred Stock Units equal to the number of shares of Common Stock to which the Director would have been entitled as Common Stock dividends had such Director been the owner on the record dates for the payments of such stock dividends of the number of shares of Common Stock equal to the number of Deferred Stock Units credited to the Director’s Deferred Stock Account on such dates, rounded to the nearest ten-thousandth.

(d)    Except as expressly provided in this Plan, a Director shall have no rights as a stockholder of Southern with respect to Common Stock credited to the Director’s Deferred Stock Account unless and until such Common Stock is paid to the Director.

(e)    In the event of (i) a corporate event or transaction involving the Company that results in a change in the Common Stock, or an exchange of Common Stock for cash, securities other than Common Stock, or other property (including, without limitation, any merger, reorganization, recapitalization, combination or exchange of shares), or (ii) any transaction between the Company and the holders of Common Stock that causes the per-share value of the Common Stock to change (including, without limitation, any conversion of shares, share dividend, share split, spin-off, rights offering, or large non-ordinary cash dividend), the Board shall make such equitable adjustments to the Deferred Stock Units as it deems necessary, in its sole discretion, to prevent dilution or enlargement of rights immediately resulting from such transaction. Notwithstanding the preceding sentence and in any event, any adjustment shall comply with the requirements of Section 409A of the Code.

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6.4    Transferred Amounts

(a)    As soon as administratively practicable, the Company shall establish for a Director transferring to the Board from Alabama Power Company, Georgia Power Company, Mississippi Power Company, or Southern Company Gas such Deferred Compensation Accounts as are necessary to implement Section 6.4(b).

(b)    Any Transferred Amounts will be credited to the Deferred Compensation Account(s) established that are comparable to the deferred compensation accounts to which such amounts were credited under the applicable deferred compensation plan for directors of Alabama Power Company, Georgia Power Company, Mississippi Power Company, or Southern Company Gas as soon as administratively practicable following the date the Transferred Amounts are transferred to the Plan. Thereafter, the Transferred Amounts shall be credited with investment returns as applicable under this Section 6 of the Plan.

SECTION 7

Distributions

7.1    Manner of Distribution

Upon a Director’s Separation from Service, the amount credited to a Director’s Deferred Compensation Accounts will be paid to the Director or the Director’s beneficiary, as applicable, in the following manner:

(a)    the amount credited to a Director’s Prime Rate Investment Account and Phantom Stock Investment Account shall be paid in cash; and

(b)    the amount credited to a Director’s Deferred Stock Account shall, except as otherwise provided in Section 6.3 and Section 9.5, or to the extent the Company is otherwise, in the reasonable judgment of the Board, precluded from doing so, be paid in shares of Common Stock (with any fractional share interest therein paid in cash to the extent of the then Market Value thereof).

Such payments shall be from the general assets of the Company (including the Deferred Cash Trust and the Deferred Stock Trust) in accordance with this Section 7.

Notwithstanding the foregoing, in the event the Company enters into an agreement described in Section 7.3 with respect to a Director prior to the Director’s Separation from Service, the Company shall have no obligation to make distributions to the Director under this Section 7.1 in connection with such Director’s Separation from Service.

7.2    Timing of Distribution(s)

Subject to Section 5.4, deferred amounts shall be paid in the form of (i) a lump sum payment, or (ii) in approximately equal annual installments, as elected by the Director. Such payments shall be made (or shall commence) as soon as practicable following the Separation from Service except that such period shall not exceed ninety (90) days as permitted by Code

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Section 409A or, if so elected by the Director in the Distribution Election, up to twenty-four (24) months following such Separation from Service.

If at the time of a Director’s Separation from Service, the Director’s Deferred Compensation Accounts have a cumulative balance of less than the limit in effect under Code Section 402(g)(1)(B), the balance of the Deferred Compensation Accounts may be distributed in a single lump sum payment.

If the Director elected to receive annual installments, the first installment shall be equal to the balance in the Director’s Deferred Compensation Accounts on such date divided by the number of annual installment payments. Each subsequent annual payment shall be an amount equal to the balance in the Director’s Deferred Compensation Accounts on the date of payment divided by the number of the then-remaining annual payments and shall be paid on the respective anniversary of the preceding date of payment.

The Market Value of any shares of Common Stock credited to a Director’s Phantom Stock Investment Account shall be determined as of the date of any lump sum or installment distribution as determined by the Board.

Upon the death of a Director, or a former Director prior to the payment of all amounts credited to the Director’s Deferred Compensation Accounts, the unpaid balance shall be paid in a lump sum to the designated beneficiary of such Director or former Director within sixty (60) days of the date of death as permitted by Code Section 409A. In the event a beneficiary designation has not been made, or the designated beneficiary is deceased or cannot be located, payment shall be made to the estate of the Director or former Director. The Market Value of any shares of Common Stock credited to a Director’s Phantom Stock Investment Account shall be determined as of the date of any lump sum or installment distribution as determined by the Board.

7.3    Transfers

If the Company enters into a written agreement with a subsidiary, affiliate or former affiliate of the Company under which the subsidiary, affiliate or former affiliate assumes the liability for a Director’s benefits accrued under the Plan in connection with, but prior to, such Director’s Separation from Service and the Director either has been or will be elected to the board of directors of such subsidiary, affiliate or former affiliate of the Company, the liability for the Director’s benefits which have accrued under the Plan as of the date the Director Separates from Service shall be transferred from the Company to the subsidiary, affiliate or former affiliate of the Company, and the Company shall have no further obligation to make any distributions to the Director under Section 7.1 or any other section herein. For the avoidance of doubt, the event described in the preceding sentence shall not constitute a distribution event whereby deferred amounts under the Plan are paid to the Director in accordance with this Section 7.

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SECTION 8

Funding Change in Control and Other Special Provisions

8.1    Funding Change in Control

Notwithstanding any other terms of the Plan to the contrary, following a Funding Event, the provisions of this Section 8 shall apply to the payment of benefits under the Plan with respect to any Director who is a Participant on such date.

8.2    Funding of Trusts

The Deferred Cash Trust and the Deferred Stock Trust (collectively “Trusts”) have been established to hold assets of the Company under certain circumstances as a reserve for the discharge of the Company’s obligations under the Plan. In the event of a Funding Event involving a Funding Change in Control, the Company shall be obligated to immediately contribute such amounts to the Trusts as may be necessary to fully fund all benefits payable under the Plan in accordance with the procedures set forth in Section 8.3 hereof. All assets held in the Trusts remain subject only to the claims of the general creditors of the Company under federal or state law in the event of Insolvency (as defined in the Trusts). No Participant has any preferred claim on, or beneficial ownership interest in, any assets of the Trusts before the assets are paid to the Participant and all rights created under the Trusts, as under the Plan, are unsecured contractual claims of the Participant against the Company.

8.3    Funding Timing and Dispute Resolution

As soon as practicable following a Funding Event, the Company shall contribute to each Trust an amount based upon the funding strategy adopted by the Trust Administrator with the assistance of an appointed actuary necessary to fulfill the Company’s obligations pursuant to this Section 8. In the event of a dispute over such actuary’s determination with respect to either or both Trusts, the Company and any complaining Participant(s) shall refer such dispute to an independent, third party actuarial consultant, chosen by the Company and such Participant. If the Company and the Participant cannot agree on an independent, third party actuarial consultant, the actuarial consultant shall be chosen by lot from an equal number of actuaries submitted by the Company and the applicable Trust Administrator. Any such referral shall only occur once in total and the determination by the third-party actuarial consultant shall be final and binding upon both parties. The Company shall be responsible for all of the fees and expenses of the independent actuarial consultant.

8.4    Lump Sum Payment

In the event of a Funding Change in Control, notwithstanding anything to the contrary in the Plan, upon a Director’s Separation from Service, that amount in the Deferred Compensation Plan Account(s) of a Participant who was a Director determined as of the date of such Funding Change in Control shall be paid out in a lump sum provided that such Separation from Service occurred within two calendar years following the Funding Change in Control and that such Funding Change in Control constitutes a change in control event for purposes of Code

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Section 409A. The lump sum payment shall be made within ninety (90) days of such Separation from Service as permitted by Code Section 409A.

SECTION 9

General Provisions

9.1    In the event that the Company shall decide to establish an advance accrual reserve on its books against the future expense of payments from any Deferred Compensation Accounts, such reserve shall not under any circumstances be deemed to be an asset of this Plan but, at all times, shall remain a part of the general assets of the Company, subject to claims of the Company’s creditors.

9.2    A person entitled to any amount under this Plan shall be a general unsecured creditor of the Company with respect to such amount. Furthermore, a person entitled to a payment or distribution with respect to a Deferred Compensation Account shall have a claim upon the Company only to the extent of the balance in such person’s Deferred Compensation Accounts.

9.3    The Company will pay all commissions, fees, and expenses that may be incurred in operating the Plan.

9.4    The Company will pay its prorated share of all commissions, fees, and expenses that may be incurred in operating any trust(s) established under the Plan (including the Deferred Stock Trust and the Deferred Cash Trust).

9.5    Notwithstanding any other provision of this Plan:

(a)    elections under this Plan may only be made by Directors while they are directors of the Company; (with the exception of the designation of beneficiaries); and

(b)    distributions otherwise payable to a Director in the form of Common Stock or other corporation’s stock shall be delayed and/or instead paid in cash in an amount equal to the fair market value thereof if such payment in stock would violate any federal or State securities laws (including Section 16(b) of the Securities Exchange Act of 1934, as amended) and/or rules and regulations promulgated thereunder.

9.6    Directors, their legal representatives and their beneficiaries shall have no right to anticipate, alienate, sell, assign, transfer, pledge or encumber their interests in the Plan, nor shall such interests be subject to attachment, garnishment, levy or execution by or on behalf of creditors of the Directors or of their beneficiaries.

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SECTION 10

Administration

10.1    General Provisions

The Board shall administer the Plan in accordance with its terms and shall have all powers necessary to carry out the provisions of the Plan as may be more particularly set forth herein. The Board shall interpret the Plan and shall determine all questions arising in the administration, interpretation, and application of the Plan. Any such determination by the Board shall be conclusive and binding on all persons. The Board shall be the Plan’s agent for service of process. The Board may designate a committee of the Board to be responsible for administering the Plan.

The Board may delegate to such officers, employees, or departments of the Company or Southern, such authority, duties, and responsibilities of the Board as it, in its sole discretion, considers necessary or appropriate for the proper and efficient operation of the Plan, including, without limitation, (i) interpretation of the Plan, (ii) approval and payment of claims, and (iii) establishment of procedures for administration of the Plan.

10.2    Claims Process

If a claim for benefits under the Plan is denied, in whole or in part, the Board will provide a written notice of the denial within a reasonable period of time, but not later than 90 days after the claim is received. If special circumstances require more time to process the claim, the Board will issue a written explanation of the special circumstances prior to the end of the 90 day period and a decision will be made as soon as possible, but not later than 180 days after the claim is received.

The written notice of claim denial will include:

•    Specific reasons why the claim was denied;

•    Specific references to applicable provisions of the Plan document or other relevant records or papers on which the denial is based, and information about where a Participant or the Participant’s beneficiary may see them;

•    A description of any additional material or information needed to process the claim, and an explanation of why such material or information is necessary; and

•    An explanation of the claims review procedure, including the time limits applicable to such procedure, as well as a statement notifying the Participant or the Participant’s beneficiary of their right to file suit if the claim for benefits is denied, in whole or in part, on review.

Upon request, a Participant or the Participant’s beneficiary will be provided without charge, reasonable access to, and copies of, all non-confidential documents that are relevant to any denial of benefits. A claimant has 60 days from the day the claimant receives the original

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denial to request a review. Such request must be made in writing and sent to the Board. The request should state the reasons why the claim should be reviewed and may also include evidence or documentation to support the claimant’s position.

The Board will reconsider the claimant’s claim, taking into account all evidence, documentation, and other information related to the claim and submitted on the claimant’s behalf, regardless of whether such information was submitted or considered in the initial denial of the claim. The Board will make a decision within 60 days. If special circumstances require more time for this process, the claimant will receive written explanation of the special circumstances prior to the end of the initial 60 day period and a decision will be sent as soon as possible, but not later than 120 days after the Board receives the request.

No legal action to recover benefits or enforce or clarify rights under a Plan can be commenced until the Participant or the Participant’s beneficiary has first exhausted the claims and review procedures provided under the Plan.

SECTION 11

Definitions

11.1    “Beneficial Ownership” means beneficial ownership within the meaning of Rule 13d-3 promulgated under the Exchange Act.

11.2    “Board” or “Board of Directors” means the Board of Directors of the Company. In the event the Board designates a committee of the Board to be responsible for administering the Plan under Section 10.1, the term “Board” or “Board of Directors” shall mean such committee.

11.3    “Business Combination” means a reorganization, merger or consolidation or sale of Southern with another corporation or an entity treated as a corporation for United States federal income tax purposes.

11.4    “Cash Compensation” means the annual cash retainer fees and cash meeting fees payable to a Director.

11.5    “Code” means the Internal Revenue Code of 1986, as amended, or any successor statute.

11.6    “Common Stock” means the common stock of Southern including any shares into which it may be split, subdivided, or combined.

11.7    “Company” means The Southern Company, or any successor thereto.

11.8    “Compensation Payment Date” means the date on which compensation, including Cash Compensation and the Stock Retainer, is payable to a Director or would otherwise be payable to a Director if an election to defer such compensation had not been made.

11.9    “Consummation” means the completion of the final act necessary to complete a transaction as a matter of law, including, but not limited to, any required approvals by the

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corporation’s shareholders and board of directors, the transfer of legal and beneficial title to securities or assets and the final approval of the transaction by any applicable domestic or foreign governments or agencies.

11.10    “Control” means, in the case of a corporation, Beneficial Ownership of more than 50% of the combined voting power of the corporation’s Voting Securities, or in the case of any other entity, Beneficial Ownership of more than 50% of such entity’s voting equity interests.

11.11    “Deferred Cash Trust” means the Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of The Southern Company and its Subsidiaries, as amended or amended and restated from time to time.

11.12    “Deferred Compensation Account” means the Prime Rate Investment Account, the Phantom Stock Investment Account and/or the Deferred Stock Account.

11.13    “Deferred Stock Account” means the bookkeeping account established under Section 6.3 on behalf of a Director and includes shares of Common Stock credited thereto to reflect the reinvestment of dividends.

11.14    “Deferred Stock Trust” means the Amended and Restated Deferred Stock Trust Agreement for Directors of The Southern Company and its Subsidiaries, as amended or amended and restated from time to time.

11.15    “Deferred Stock Unit” means a bookkeeping unit, having at all times a value equal to one share of Common Stock, credited to a Participant’s Deferred Stock Account.

11.16    “Director” means a member of the Board.

11.17    “Distribution Election” means the designation by a Director of the manner of distribution of the amounts and quantities held in the Director’s Deferred Compensation Accounts upon the director’s Separation from Service pursuant to Section 5.4.

11.18    “Employee” means an employee of Southern or any of its subsidiaries that are “employing companies” as defined in the Southern Company Deferred Compensation Plan as amended and restated effective June 1, 2021, and as may be amended from time to time.

11.19    “Exchange Act” means the Securities Exchange Act of 1934, as amended.

11.20    “Funding Change in Control” means any of the following:

(a)    The Consummation of an acquisition by any Person of Beneficial Ownership (during the 12-month period ending on the date of the most recent acquisition by such Person) of 35% or more of Southern’s Voting Securities; provided, however, that for purposes of this subsection (a), the following acquisitions of Southern’s Voting Securities shall not constitute a Funding Change in Control:

(i)    any acquisition directly from Southern;

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(ii)    any acquisition by Southern;

(iii)    any acquisition by any employee benefit plan (or related trust) sponsored or maintained by Southern or any corporation controlled by Southern;

(iv)    any acquisition by a qualified pension plan or publicly held mutual fund;

(v)    any acquisition by an employee of Southern or its subsidiary or affiliate, or Group composed exclusively of such employees; or

(vi)    any Business Combination which would not otherwise constitute a Funding Change in Control because of the application of clauses (i), (ii) and (iii) of this Section 11.20(a);

(b)    The date a majority of members of the Board is replaced during any 12-month period by directors whose appointment or election is not endorsed by a majority of the members of the Board before the date of the appointment or election;

(c)    The Consummation of a Business Combination, unless, following such Business Combination, all of the following three conditions are met:

(i)    all or substantially all of the individuals and entities who held Beneficial Ownership, respectively, of Southern’s Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, 50% or more of the combined voting power of the Voting Securities of the corporation surviving or resulting from such Business Combination, (including, without limitation, a corporation which as a result of such transaction holds Beneficial Ownership of all or substantially all of Southern’s Voting Securities or all or substantially all of Southern’s assets) (such surviving or resulting corporation to be referred to as “Surviving Company”), in substantially the same proportions as their ownership, immediately prior to such Business Combination, of Southern’s Voting Securities;

(ii)    no Person (excluding any corporation resulting from such Business Combination, any qualified pension plan, publicly held mutual fund, Group composed exclusively of employees or employee benefit plan (or related trust) of Southern, its subsidiaries or Surviving Company) holds Beneficial Ownership, directly or indirectly, of 35% or more of the combined voting power of the then outstanding Voting Securities of Surviving Company except to the extent that such ownership existed prior to the Business Combination; and

(iii)    the majority of the members of the board of directors of Surviving Company during the 12-month period following the Business Combination were members of the Southern Board at the earlier of the date of execution of the initial agreement, or of the action of the Southern Board, providing for such Business Combination or such members of the board of directors of the Surviving Company are directors whose appointment or election was endorsed by a majority of the members of such Southern Board.

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11.21    “Funding Event” means the occurrence of any of the following events as administratively determined by the Southern Committee:

(a)    The Company has entered into a written agreement, such as, but not limited to, a letter of intent, which, if Consummated, would result in a Funding Change in Control;

(b)    The Company or any other Person publicly announces an intention to take or to consider taking actions which, if Consummated, would result in a Funding Change in Control under circumstances where the Consummation of the announced action or intended action is legally and financially possible;

(c)    Any Person acquires Beneficial Ownership of fifteen percent (15%) or more of the Common Stock; or

(d)    The Board elects to otherwise fund the Deferred Cash Trust and Deferred Stock Trust in accordance with the provisions of Section 8.

11.22    “Group” has the meaning set forth in Section 14(d) of the Exchange Act.

11.23    “Incumbent Board” means those individuals who constitute the Southern Board as of June 1, 2021, plus any individual who shall become a director subsequent to such date whose election or nomination for election by Southern’s shareholders was approved by a vote of at least 75% of the directors then comprising the Incumbent Board. Notwithstanding the foregoing, no individual who shall become a director of the Southern Board subsequent to June 1, 2021, whose initial assumption of office occurs as a result of an actual or threatened election contest (within the meaning of Rule 14a-11 of the regulations promulgated under the Exchange Act) with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Southern Board shall be a member of the Incumbent Board.

11.24    “Market Value” means the closing price at which a share of the Common Stock shall have been traded on the date such Market Value is to be determined, as specified herein (or on the next preceding trading day on which a sale was reported if such date was not a trading date), as reported by the principal securities exchange on which the Common Stock is traded. If the Common Stock is not listed for trading on a national securities exchange, the fair market value of the shares shall be determined by the Board in good faith and in accordance with a reasonable valuation method as determined under Code Section 409A and the rules and regulations promulgated thereunder.

11.25    “Modification Delay” means that the modified election shall not take effect until twelve (12) months after the date the modified election is made, the payment which is the subject of the modified election shall be deferred five (5) years from the date previously elected by the Director, and where applicable in the case of a payment made pursuant to a fixed schedule or specified time, the modified election must be made at least twelve (12) months prior to the time payment is scheduled to be made.

11.26    “Participant” means a Director or former Director who has an unpaid Deferred Compensation Account balance under the Plan.

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11.27    “Person” means any individual, entity or group within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act.

11.28    “Phantom Stock Investment Account” means the bookkeeping account established pursuant to Section 6.2 in which a Director may elect to defer Cash Compensation or make investments, and includes amounts credited thereto to reflect the reinvestment of dividends.

11.29    “Phantom Stock Unit” means a bookkeeping unit, having at all times a value equal to one share of Common Stock, credited to a Participant’s Phantom Stock Investment Account.

11.30    “Plan” means the Deferred Compensation Plan for Outside Directors of The Southern Company as from time to time in effect.

11.31    “Plan Period” means the period designated in Section 4.

11.32    “Preliminary Change in Control” means the occurrence of any of the following as determined by the Southern Committee:

(a)    The Company has entered into a written agreement, such as, but not limited to, a letter of intent, which, if Consummated, would result in a Southern Change in Control;

(b)    The Company or any Person publicly announces an intention to take or to consider taking actions which, if Consummated, would result in a Southern Change in Control under circumstances where the Consummation of the announced action or intended action is legally and financially possible; or

(c)    Any Person becomes the Beneficial Owner of fifteen percent (15%) or more of the Common Stock.

11.33    “Prime Interest Rate” means the prime rate of interest as published in the Wall Street Journal or its successor on the first day of the applicable calendar quarter.

11.34    “Prime Rate Investment Account” means the bookkeeping account established pursuant to Section 6.1 in which a Director may elect to defer Cash Compensation or make investments, the investment return on which is computed at the Prime Interest Rate.

11.35    “Separation from Service” means a separation from service as such term is defined in Code Section 409A or any other applicable regulations or guidance from the Department of Treasury.

11.36    “Southern” means The Southern Company.

11.37    “Southern Change in Control” means any of the following:

(a)    The Consummation of an acquisition by any Person of Beneficial Ownership of 20% or more of Southern’s Voting Securities; provided, however, that for purposes of this subsection (a), the following acquisitions of Southern’s Voting Securities shall not constitute a Change in Control:

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(i)    any acquisition directly from Southern,

(ii)    any acquisition by Southern,

(iii)    any acquisition by any employee benefit plan (or related trust) sponsored or maintained by Southern or any corporation controlled by Southern,

(iv)    any acquisition by a qualified pension plan or publicly held mutual fund,

(v)    any acquisition by an Employee or Group composed exclusively of Employees, or

(vi)    any Business Combination which would not otherwise constitute a Southern Change in Control because of the application of clauses (i), (ii) and (iii) of Section 11.37(a) of this Plan;

(b)    A change in the composition of the Southern Board whereby individuals who constitute the Incumbent Board cease for any reason to constitute at least a majority of the Southern Board; or

(c)    Consummation of a Business Combination, unless, following such Business Combination, all of the following three conditions are met:

(i)    all or substantially all of the individuals and entities who held Beneficial Ownership, respectively, of Southern’s Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, 65% or more of the combined voting power of the Voting Securities of the corporation surviving or resulting from such Business Combination, (including, without limitation, a corporation which as a result of such transaction holds Beneficial Ownership of all or substantially all of Southern’s Voting Securities or all or substantially all of Southern’s assets) (such surviving or resulting corporation to be referred to as “Surviving Company”), in substantially the same proportions as their ownership, immediately prior to such Business Combination, of Southern’s Voting Securities;

(ii)    no Person (excluding any corporation resulting from such Business Combination, any qualified pension plan, publicly held mutual fund, Group composed exclusively of employees or employee benefit plan (or related trust) of Southern, its subsidiaries, or Surviving Company) holds Beneficial Ownership, directly or indirectly, of 20% or more of the combined voting power of the then outstanding Voting Securities of Surviving Company except to the extent that such ownership existed prior to the Business Combination; and

(iii)    at least a majority of the members of the board of directors of Surviving Company were members of the Incumbent Board at the earlier of the date of execution of the initial agreement, or of the action of the Southern Board, providing for such Business Combination.

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11.38    “Southern Committee” means a committee comprised of the Chairman of the Board, the Chief Financial Officer of the Company and the General Counsel of the Company.

11.39    “Stock Retainer” means the portion of the Director’s retainer fee that is required to be paid to the Director in Common Stock pursuant to the Company’s compensation policy for directors. Such amount may be denominated in dollars and/or shares of Common Stock.

11.40    “Transferred Amount” means an amount (a) equal to the value of a Director’s accounts under the applicable deferred compensation plan for directors of Alabama Power Company, Georgia Power Company, Mississippi Power Company, or Southern Company Gas and (b) which has been transferred to the Plan in connection with the Director’s transfer from the board of directors of Alabama Power Company, Georgia Power Company Mississippi Power Company, or Southern Company Gas to the Board.

11.41    “Trust Administrator” means the individual or committee that is established in the Deferred Stock Trust and the Deferred Cash Trust, to administer such trusts.

11.42    “Voting Securities” means the outstanding voting securities of a corporation entitling the holder thereof to vote generally in the election of such corporation’s directors.

Where the context requires, words in the masculine gender shall include the feminine gender, words in the singular shall include the plural, and words in the plural shall include the singular.

SECTION 12

Amendment, Termination and Effective Date

12.1    Amendment of the Plan

The Plan may be amended or terminated at any time by the Board of Directors, provided, however, that no such amendment or termination of the Plan shall be effective if such amendment or termination is made or is effective within a period that is (a) six (6) months before, or at any time after, a Preliminary Change in Control and (b) prior to (x) the earlier of such time as the Southern Committee shall have determined that the event that gave rise to such Preliminary Change in Control shall not be Consummated or (y) two years following the Southern Change in Control, unless such amendment or termination during such period has the effect of increasing benefits to Participants under the Plan, is determined by the Board of Directors to be immaterial, or applies solely to Directors who, in the case of a Southern Change in Control, are not Directors on the date of the respective Preliminary Change in Control. Following a Southern Change in Control, nothing in this Section 12.1 shall prevent the Board of Directors from amending or terminating the Plan as to any subsequent Southern Change in Control provided that no such amendment or termination shall impair any rights or reduce any benefits previously accrued under the Plan as a result of a previous Southern Change in Control.

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12.2    No Impairment of Benefits

Notwithstanding the provisions of Section 12.1 herein, no amendment to or termination of the Plan shall impair any rights to benefits that have accrued hereunder.

12.3    Code Section 409A

All payments of “non-qualified deferred compensation” (within the meaning of Code Section 409A) under this Plan, whether or not expressly designated as such, are intended to comply with the requirements of Code Section 409A, and shall be interpreted in accordance therewith. Neither the Participant nor the Company may accelerate any such deferred payment, except in compliance with Code Section 409A for such events that include but may not be limited to a termination of the Plan.

To the extent of the reimbursement of expenses, (a) there shall be an objectively determinable nondiscretionary definition of expenses eligible for reimbursement; (b) such expenses shall be only those incurred during the Participant’s lifetime; (c) the amount of expenses eligible for reimbursement during a calendar year shall not affect the expenses eligible for reimbursement in any other taxable year; (d) the 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 (e) the right to reimbursement shall not be subject to liquidation or exchange for another benefit.

12.4    Governing Law

This Plan shall be construed in accordance with and governed by the laws of the State of Georgia to the extent not inconsistent with the requirements of the Employee Retirement Income Security Act of 1974, as amended, and Code Section 409A.

IN WITNESS WHEREOF, the Plan, as amended and restated effective June 1, 2021, has been executed pursuant to resolutions of the Board, this day of June 1, 2021.

THE SOUTHERN COMPANY
By:	/s/Myra C. Bierria
	Vice President and Corporate Secretary

Attest:
By:	/s/Marcia R. DeMar
	Shareholder Services Manager

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PROVISIONS FOR PRE-2005 DEFERRALS UNDER
THE DEFERRED COMPENSATION PLAN FOR OUTSIDE DIRECTORS OF THE SOUTHERN COMPANY

SECTION 1

Purpose

1.1    Provisions for Pre-2005 Deferrals: This document (the “Pre-2005 Addendum”) sets forth the operative provisions of the Deferred Compensation Plan for Outside Directors of The Southern Company (as amended or amended and restated from time to time, the “Plan”) applicable to “grandfathered” deferrals of Cash Compensation and Stock Retainer made by Participants which are treated by the Company as not subject to Code Section 409A. The Deferred Compensation Account balance (plus earnings thereon) of the grandfathered deferrals shall only be subject to the provisions set forth in this Pre-2005 Addendum. In accordance with transition rules under Code Section 409A, Internal Revenue Service Notice 2005-1, Treasury Regulation Section 1.409A-1 et seq., or any other applicable guidance from the Department of Treasury, these provisions are only intended to preserve the rights and features of the “grandfathered” deferrals and are, therefore, not intended to “materially modify” any aspect of such rights and features. Provisions of this Pre-2005 Addendum should be so construed whenever necessary or appropriate. Provisions in this Pre-2005 Addendum shall only be amended in accordance with this Pre-2005 Addendum’s terms. Capitalized terms used herein but not defined herein shall have the meanings given to such terms in the Plan (as in effect prior to January 1, 2005).

SECTION 2

Definitions

2.1    “Beneficial Ownership” means beneficial ownership within the meaning of Rule 13d-3 promulgated under the Exchange Act.

2.2    “Board” or “Board of Directors” means the Board of Directors of the Company.

2.3    “Business Combination” means a reorganization, merger or consolidation or sale of Southern with another corporation or an entity treated as a corporation for United States federal income tax purposes.

2.4    “Cash Compensation” means the annual retainer fees and meeting fees payable to a Director in cash.

2.5    “Code” means the Internal Revenue Code of 1986, as amended, or any successor statute.

2.6    “Committee” means the Governance Committee of the Board, or such other committee as may be designated by the Board to be responsible for administering the Plan and this Pre-2005 Addendum.

2.7    “Common Stock” means the common stock of Southern, including any shares into which it may be split, subdivided, or combined.

2.8    “Company” means The Southern Company or any successor thereto.

2.9    “Compensation Payment Date” means the date on which compensation, including Cash Compensation, and the Stock Retainer, is payable to a Director or compensation which would otherwise be payable to a Director if an election to defer such compensation had not been made.

2.10    “Consummation” means the completion of the final act necessary to complete a transaction as a matter of law, including, but not limited to, any required approvals by the corporation’s shareholders and board of directors, the transfer of legal and beneficial title to securities or assets and the final approval of the transaction by any applicable domestic or foreign governments or agencies.

2.11    “Control” means, in the case of a corporation, Beneficial Ownership of more than 50% of the combined voting power of the corporation’s Voting Securities, or in the case of any other entity, Beneficial Ownership of more than 50% of such entity’s voting equity interests.

2.12    “Deferred Cash Trust” means the Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of The Southern Company and its Subsidiaries, as amended or amended and restated from time to time.

2.13    “Deferred Compensation Account” means the Prime Rate Investment Account, the Phantom Stock Investment Account, the Deferred Stock Account, and/or the Stock Dividend Investment Account applicable to “grandfathered” deferrals of Cash Compensation and Stock Retainer made by Participants which are treated by the Company as not subject to Code Section 409A.

2.14    “Deferred Pension Election” means the election by a Director who had a Pension Benefit as of the Termination Date, who made a single one-time election, to credit all his Pension Benefit into (i) the Prime Rate Investment Account or (ii) thePhantom Stock Investment Account in connection with the deferral of receipt of the Director’s Pension Benefit until termination from the Board.

2.15    “Deferred Stock Account” means the bookkeeping account established under Section 5.3 of this Pre-2005 Addendum on behalf of a Director and includes shares of Common Stock credited thereto to reflect the reinvestment of dividends pursuant to Section 5.3(a)(iii) of this Pre-2005 Addendum.

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2.16    “Deferred Stock Trust” means the Amended and Restated Deferred Stock Trust Agreement for Directors of The Southern Company and its Subsidiaries, as amended or amended and restated from time to time.

2.17    “Director” means a member of the Board.

2.18    “Distribution Election” means the designation by a Director of the manner of distribution of the amounts and quantities held in the Director’s Deferred Compensation Accounts upon the director’s termination from the Board pursuant to Section 6.4 of this Pre-2005 Addendum.

2.19    “Employee” means an employee of Southern or any of its subsidiaries that are “employing companies” as defined in the Southern Company Deferred Compensation Plan as amended and restated effective January 1, 2005, and as may be amended from time to time.

2.20    “Exchange Act” means the Securities Exchange Act of 1934, as amended.

2.21    “Funding Change in Control means any of the following:

(a)    The Consummation of an acquisition by any Person of Beneficial Ownership (during the 12-month period ending on the date of the most recent acquisition by such Person) of 35% or more of Southern’s Voting Securities; provided, however, that for purposes of this subsection (a), the following acquisitions of Southern’s Voting Securities shall not constitute a Funding Change in Control:

(i)    any acquisition directly from Southern;

(ii)    any acquisition by Southern;

(iii)    any acquisition by any employee benefit plan (or related trust) sponsored or maintained by Southern or any corporation controlled by Southern;

(iv)    any acquisition by a qualified pension plan or publicly held mutual fund;

(v)    any acquisition by an employee of Southern or its subsidiary or affiliate, or Group composed exclusively of such employees; or

(vi)    any Business Combination which would not otherwise constitute a Funding Change in Control because of the application of clauses (i), (ii) and (iii) of this Section 2.21(a);

(b)    The date a majority of members of the Southern Board of Directors is replaced during any 12-month period by directors whose appointment or

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election is not endorsed by a majority of the members of the Southern Board of Directors before the date of the appointment or election;

(c)    The Consummation of a Business Combination, unless, following such Business Combination, all of the following three conditions are met:

(i)    all or substantially all of the individuals and entities who held Beneficial Ownership, respectively, of Southern’s Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, 50% or more of the combined voting power of the Voting Securities of the corporation surviving or resulting from such Business Combination, (including, without limitation, a corporation which as a result of such transaction holds Beneficial Ownership of all or substantially all of Southern’s Voting Securities or all or substantially all of Southern’s assets) (such surviving or resulting corporation to be referred to as “Surviving Company”), in substantially the same proportions as their ownership, immediately prior to such Business Combination, of Southern’s Voting Securities;

(ii)    no Person (excluding any corporation resulting from such Business Combination, any qualified pension plan, publicly held mutual fund, Group composed exclusively of employees or employee benefit plan (or related trust) of Southern, its subsidiaries or Surviving Company) holds Beneficial Ownership, directly or indirectly, of 35% or more of the combined voting power of the then outstanding Voting Securities of Surviving Company except to the extent that such ownership existed prior to the Business Combination; and

(iii)    the majority of the members of the board of directors of Surviving Company during the 12-month period following the Business Combination were members of the Southern Board of Directors at the earlier of the date of execution of the initial agreement, or of the action of the Southern Board of Directors, providing for such Business Combination or such members of the board of directors of the Surviving Company are directors whose appointment or election was endorsed by a majority of the members of such Southern Board of Directors.

2.22    “Funding Event” shall mean the occurrence of any of the following events as administratively determined by the Southern Committee:

(a)    The Company has entered into a written agreement, such as, but not limited to, a letter of intent, which, if Consummated, would result in a Funding Change in Control;

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(b)    The Company or any other Person publicly announces an intention to take or to consider taking actions which, if Consummated, would result in a Funding Change in Control under circumstances where the Consummation of the announced action or intended action is legally and financially possible;

(c)    Any Person acquires Beneficial Ownership of fifteen percent (15%) or more of the Common Stock; or

(d)    The Southern Board of Directors elects to otherwise fund the Deferred Cash Trust and Deferred Stock Trust in accordance with the provisions of Section 7 of this Pre-2005 Addendum.

2.23    “Group” has the meaning set forth in Section 14(d) of the Exchange Act.

2.24    “Incumbent Board” means those individuals who constitute the Southern board of directors as of January 1, 2008, plus any individual who shall become a director subsequent to such date whose election or nomination for election by Southern’s shareholders was approved by a vote of at least 75% of the directors then comprising the Incumbent Board. Notwithstanding the foregoing, no individual who shall become a director of the Southern board of directors subsequent to January 1, 2008, whose initial assumption of office occurs as a result of an actual or threatened election contest (within the meaning of Rule 14a-11 of the regulations promulgated under the Exchange Act) with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Southern board of directors shall be a member of the Incumbent Board.

2.25    “Market Value” means the average of the high and low prices of the Common Stock, as published in the Wall Street Journal in its report of New York Stock Exchange composite transactions, on the date such Market Value is to be determined, as specified herein (or the average of the high and low sale prices on the trading day immediately preceding such date if the Common Stock is not traded on the New York Stock Exchange on such date).

2.26    “Outside Directors Stock Plan” means the Outside Directors Stock Plan for The Southern Company and Its Subsidiaries, effective May 26, 2004 in accordance with its terms, as may be amended from time to time.

2.27    “Participant” means a Director or former Director who has an unpaid Deferred Compensation Account balance under this Pre-2005 Addendum.

2.28    “Participating Companies” means those companies that are affiliated with the Company whose boards of directors have authorized the establishment of trust(s) for the funding of their respective directors’ Deferred Compensation Accounts under their respective Deferred Compensation Plans for Directors, including the Plan as maintained by the Company for its Directors.

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2.29    “Pension Benefit” means the U.S. dollar amount of the actuarially-determined present value of benefits based on a Director’s expected service at the required retirement date under The Southern Company Outside Directors Pension Plan, as calculated as of the Termination Date, plus accrued earnings on such amount calculated as if invested at the Prime Interest Rate from the Termination Date, until such amount is invested in Deferred Compensation Accounts.

2.30    “Pension Benefit Investment Date” means the date to be determined by the Committee, as of which the Director’s Pension Benefit will be credited to a Deferred Compensation Account in accordance with the director’s Deferred Pension Election.

2.31    “Person” means any individual, entity or group within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act.

2.32    “Phantom Stock Investment Account” means the bookkeeping account established pursuant to Section 5.2 of this Pre-2005 Addendum in which a Director may elect to defer Cash Compensation or make investments, and includes amounts credited thereto to reflect the reinvestment of dividends.

2.33    “Plan” means the Deferred Compensation Plan for Outside Directors of The Southern Company as from time to time in effect.

2.34    “Plan Period” means the period designated in Section 4.

2.35    “Preliminary Change in Control” means the occurrence of any of the following as determined by the Southern Committee:

(a)    The Company has entered into a written agreement, such as, but not limited to, a letter of intent, which, if Consummated, would result in a Southern Change in Control;

(b)    The Company or any Person publicly announces an intention to take or to consider taking actions which, if Consummated, would result in a Southern Change in Control under circumstances where the Consummation of the announced action or intended action is legally and financially possible; or

(c)    Any Person becomes the Beneficial Owner of fifteen percent (15%) or more of the Common Stock.

2.36     “Prime Interest Rate” means the prime rate of interest as published in the Wall Street Journal, or its successor on the first day of the applicable calendar quarter.

2.37    “Prime Rate Investment Account” means the bookkeeping account established pursuant to Section 5.1 of this Pre-2005 Addendum in which a Director may elect to defer CashCompensation or make investments, the investment return on which is computed at the Prime Interest Rate.

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2.38    “Southern” means The Southern Company.

2.39    “Southern Change in Control” means any of the following:

(a)    The Consummation of an acquisition by any Person of Beneficial Ownership of 20% or more of Southern’s Voting Securities; provided, however, that for purposes of this subsection (a), the following acquisitions of Southern’s Voting Securities shall not constitute a Change in Control:

(i)    any acquisition directly from Southern,

(ii)    any acquisition by Southern,

(iii)    any acquisition by any employee benefit plan (or related trust) sponsored or maintained by Southern or any corporation controlled by Southern,

(iv)    any acquisition by a qualified pension plan or publicly held mutual fund,

(v)    any acquisition by an Employee or Group composed exclusively of Employees, or

(vi)    any Business Combination which would not otherwise constitute a Change in Control because of the application of clauses (i), (ii) and (iii) of Section 2.39(a) of this Pre-2005 Addendum;

(b)    A change in the composition of Southern’s board of directors whereby individuals who constitute the Incumbent Board cease for any reason to constitute at least a majority of Southern’s board of directors; or

(c)    Consummation of a Business Combination, unless, following such Business Combination, all of the following three conditions are met:

(i)    all or substantially all of the individuals and entities who held Beneficial Ownership, respectively, of Southern’s Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, 65% or more of the combined voting power of the Voting Securities of the corporation surviving or resulting from such Business Combination, (including, without limitation, a corporation which as a result of such transaction holds Beneficial Ownership of all or substantially all of Southern’s Voting Securities or all or substantially all of Southern’s assets) (such surviving or resulting corporation to be referred to as “Surviving Company”), in substantially the same proportions as their ownership, immediately prior to such Business Combination, of Southern’s Voting Securities;

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(ii)    no Person (excluding any corporation resulting from such Business Combination, any qualified pension plan, publicly held mutual fund, Group composed exclusively of employees or employee benefit plan (or related trust) of Southern, its subsidiaries, or Surviving Company) holds Beneficial Ownership, directly or indirectly, of 20% or more of the combined voting power of the then outstanding Voting Securities of Surviving Company except to the extent that such ownership existed prior to the Business Combination; and

(iii)    at least a majority of the members of the Board were members of the Incumbent Board at the earlier of the date of execution of the initial agreement, or of the action of the Board, providing for such Business Combination.

2.40    “Southern Committee” means a committee comprised of the Chairman of the Board, the Chief Financial Officer of the Company, and the General Counsel of the Company.

2.41    “Stock Dividend Investment Account” means the bookkeeping account(s) established pursuant to Section 5.4 of this Pre-2005 Addendum on behalf of a Director that is credited with shares of stock, other than Common Stock, paid as a dividend on shares of Common Stock.

2.42    “Stock Retainer” means the portion of the retainer fee that the Board has determined to credit to a Director’s Deferred Stock Account. Such amount may be denominated in dollars and/or shares of Common Stock.

2.43    “Termination Date” means January 1, 1997, the date as of which The Southern Company Outside Directors Pension Plan was effectively terminated.

2.44    “Transferred Amount” means an amount (a) equal to the value of a Director’s accounts under the applicable deferred compensation plan for directors of Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, or Savannah Electric and Power Company and (b) which has been transferred to the Plan in connection with the Director’s transfer from the board of directors of Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, or Savannah Electric and Power Company to the Board.

2.45    “Transferred Amount Investment Date” means the date as of which a Director’s Transferred Amount will be credited to a Deferred Compensation Account in accordance with Section 5.5 of this Pre-2005 Addendum.

2.46    “Trust Administrator” means the individual or committee that is established in the Deferred Stock Trust and the Deferred Cash Trust, to administer such trusts on behalf of the Participating Companies.

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2.47    “Voting Securities” means the outstanding voting securities of a corporation entitling the holder thereof to vote generally in the election of such corporation’s directors.

Where the context requires, words in the masculine gender shall include the feminine gender, words in the singular shall include the plural, and words in the plural shall include the singular.

SECTION 3

Eligibility

For so long as a Director has a Deferred Compensation Account balance governed by this Pre-2005 Addendum, he or she shall be a Participant in the Plan for purposes of this Pre-2005 Addendum, and such Deferred Compensation Account balance shall be maintained and administered solely in accordance with the terms of this Pre-2005 Addendum.

SECTION 4

Plan Periods

No new deferral elections may be made which are subject to this Pre-2005 Addendum.

SECTION 5

Accounts

5.1    Prime Rate Investment Account

A Prime Rate Investment Account shall be established for each Director electing deferral of Cash Compensation for investment at the Prime Interest Rate. The amount directed by the Director to such account shall be credited to it as of the Pension Benefit Investment Date, Compensation Payment Date, or Transferred Amount Investment Date, as applicable, and credited thereafter with interest computed using the Prime Interest Rate. Interest shall be computed from the date such compensation is credited to the account and compounded quarterly at the end of each calendar quarter. The Prime Interest Rate in effect on the first day of a calendar quarter shall be deemed the Prime Interest Rate in effect for that entire quarter. Interest shall accrue and compound on any balance until the amount credited to the account is fully distributed.

5.2    Phantom Stock Investment Account

The Phantom Stock Investment Account established for each Director electing deferral of Cash Compensation for investment at the Common Stock investment rate shall be credited with the number of shares (including fractional shares rounded to the nearest ten-thousandth) of Common Stock which could have been purchased on the Pension Benefit Investment Date, the Compensation Payment Date, or Transferred Amount Investment Date, as applicable, as determined by dividing the applicable compensation by the Market Value on such date. On the date of the payment of dividends on the Common Stock, the Director’s Phantom Stock Investment

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Account shall be credited with additional shares (including fractional shares rounded to the nearest ten-thousandth) of Common Stock, as follows:

(a)    In the case of cash dividends, such additional shares as would have been purchased as of the Common Stock dividend record date as if the credited shares had been outstanding on such date and dividends reinvested thereon under the Southern Company Southern Investment Plan;

(b)    In the case of dividends payable in property other than cash or Common Stock, such additional shares as could be purchased at the Market Value as of the date of payment with the fair market value of the property which would have been payable if the credited shares had been outstanding; and

(c)    In the case of dividends payable in Common Stock, such additional shares as would have been payable on the credited shares as if they had been outstanding.

5.3    Deferred Stock Account

(a)    A Director’s Deferred Stock Account will be credited:

(i)    with the number of shares of Common Stock (rounded to the nearest ten thousandth of a share) determined by dividing the sum of the amount of Cash Compensation subject to deferral or investment in the Deferred Stock Account and the Stock Retainer (that is denominated in dollars), by the average price paid by the Trust Administrator of the Deferred Stock Trust for shares of Common Stock with respect to the Pension Benefit Investment Date or the Compensation Payment Date, as applicable, as reported by the Trust Administrator, or if the Trust Administrator shall not at such time purchase any shares of Common Stock, by the Market Value on such date;

(ii)    as of the date on which the Stock Retainer (that is denominated in shares of Common Stock) is paid, with the number of shares of Common Stock payable to the Director as his Stock Retainer; and

(iii)    as of each date on which dividends are paid on the Common Stock, with the number of shares of Common Stock (rounded to the nearest ten thousandth of a share) determined by multiplying the number of shares of Common Stock credited in the Director’s Deferred Stock Account on the dividend record date, by the dividend rate per share of Common Stock, and dividing the product by the price per share of Common Stock attributable to the reinvestment of dividends on the shares of Common Stock held in the Deferred Stock Trust on the applicable dividend payment date or, if the Trust Administrator of the Deferred Stock Trust has not reinvested in shares of Common

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Stock on the applicable dividend reinvestment date, the product shall be divided by the Market Value on the dividend payment date.

(b)    If Southern enters into transactions involving stock splits, stock dividends, reverse splits or any other recapitalization transactions, the number of shares of Common Stock credited to a Director’s Deferred Stock Account will be adjusted (rounded to the nearest ten thousandth of a share) so that the Director’s Deferred Stock Account reflects the same equity percentage interest in Southern after the recapitalization as was the case before such transaction.

(c)    If at least a majority of Southern’s stock is sold or exchanged by its shareholders pursuant to an integrated plan for cash or property (including stock of another corporation) or if substantially all of the assets of Southern are disposed of and, as a consequence thereof, cash or property is distributed to Southern’s shareholders, each Director’s Deferred Stock Account will, to the extent not already so credited under this Section 5.3, be (i) credited with the amount of cash or property receivable by a Southern shareholder directly holding the same number of shares of Common Stock as is credited to such Director’s Deferred Stock Account and (ii) debited by that number of shares of Common Stock surrendered by such equivalent Southern shareholder.

(d)    Except as expressly provided in this Pre-2005 Addendum, a Director shall have no rights as a stockholder of Southern with respect to the Director’s Deferred Stock Account unless and until such Common Stock is paid to the Director.

5.4    Stock Dividend Investment Account

(a)    A Director’s Stock Dividend Investment Account will be credited as of the date on which a dividend is paid in stock other than Common Stock to the Company’s common stockholders with the number of shares of such other corporation’s stock receivable by such Southern common stockholder. Thereafter, if dividends are paid on the above-described non-Common Stock dividends, such subsequent dividends shall be credited in the same manner as described in Section 5.3(a)(iii) of this Pre-2005 Addendum.

(b)    Except as expressly provided herein, a Director shall have no rights as a stockholder of any corporation the common stock of which is credited to the Director’s Stock Dividend Investment Account.

5.5    Transferred Amounts

(a)    As soon as administratively practicable, the Company shall establish for a Director transferring to the Board from Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, or Savannah Electric and Power Company, such Deferred Compensation Accounts as are necessary to implement Section 5.5 (b) below.

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(b)    Any Transferred Amounts will be credited to the Deferred Compensation Account(s) established that are comparable to the deferred compensation accounts to which such amounts were credited under the applicable deferred compensation plan for directors of Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, or Savannah Electric and Power Company, as soon as administratively practicable following the date the Transferred Amounts are transferred to the Plan. Thereafter, the Transferred Amounts shall be credited with investment returns as applicable under this Section 5 of the Schedule.

SECTION 6

Distributions

6.1    Upon the termination of a Director’s membership on the Board the amount credited to a Director’s Deferred Compensation Accounts will be paid to the Director or his beneficiary, as applicable, in the following manner:

(a)    the amount credited to a Director’s Prime Rate Investment Account and Phantom Stock Investment Account shall be paid in cash;

(b)    the amount credited to a Director’s Deferred Stock Account shall, except as otherwise provided in Sections 5.3 and 6.7 of this Pre-2005 Addendum, or to the extent the Company is otherwise, in the reasonable judgment of the Committee, precluded from doing so, be paid in shares of Common Stock (with any fractional share interest therein paid in cash to the extent of the then Market Value thereof); and

(c)    the amount credited to a Stock Dividend Investment Account shall, except as otherwise provided in Section 6.7 of this Pre-2005 Addendum, be paid from the assets in the Deferred Stock Trust in shares of the applicable corporation, however if there is not a sufficient number of shares held in the Trust, the remainder shall be paid in cash based upon the Market Value of such shares.

Such payments shall be from the general assets of the Company (including the Deferred Cash Trust and the Deferred Stock Trust) in accordance with this Section 6.

Notwithstanding the foregoing, in the event the Company enters into an agreement described in Section 6.3 of this Schedule with respect to a Director prior to the Director’s termination of membership, the Company shall have no obligation to make distributions to the Director under this Section 6.1 in connection with such Director’s termination of membership on the Board.

6.2    Unless other arrangements are specified by the Committee on a uniform and nondiscriminatory basis, deferred amounts shall be paid in the form of (i) a lump sum payment, or (ii) in approximately equal annual installments, as elected by the Director pursuant to the provisions of Section 6.4 of this Pre-2005 Addendum,

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provided, however, that payments shall be made only in a single lump sum if payment commences due to termination for cause. Such payments shall be made (or shall commence) as soon as practicable following the termination of Board membership or, if so elected in the Distribution Election, up to twenty-four (24) months following such termination.

In the event a Director elected to receive the balance of his Deferred Compensation Accounts in a lump sum, distribution shall be made on the first day of the month selected by the Director on his Distribution Election, or as soon as reasonably possible thereafter. If the Director elected to receive annual installments, the first payment shall be made on the first day of the month selected by a Director, or as soon as reasonably possible thereafter, and shall be equal to the balance in the Director’s Deferred Compensation Accounts on such date divided by the number of annual installment payments. Each subsequent annual payment shall be an amount equal to the balance in the Director’s Deferred Compensation Accounts on the date of payment divided by the number of remaining annual payments and shall be paid on the anniversary of the preceding date of payment.

The Market Value of any shares of Common Stock credited to a Director’s Phantom Stock Investment Account shall be determined as of the date of any lump sum or installment distribution as determined by the Committee.

Upon the death of a Director, or a former Director prior to the payment of all amounts credited to the Director’s Deferred Compensation Accounts, the unpaid balance shall be paid in the sole discretion of the Committee (i) in a lump sum to the designated beneficiary of such Director or former Director within thirty (30) days of the date of death (or as soon as reasonably possible thereafter) or (ii) in accordance with the Distribution Election made by such Director or former Director. In the event a beneficiary designation has not been made, or the designated beneficiary is deceased or cannot be located, payment shall be made to the estate of the Director or former Director. The Market Value of any shares of Common Stock credited to a Director’s Phantom Stock Investment Account shall be determined as of the date of any lump sum or installment distribution as determined by the Committee.

6.3    If the Company enters into a written agreement with a subsidiary, affiliate or former affiliate of the Company under which the subsidiary, affiliate or former affiliate assumes liability for a Director’s benefits accrued under the Schedule in connection with, but prior to, such Director’s termination of membership on the Board and the Director either has been or will be elected to the board of directors of such subsidiary, affiliate or former affiliate of the Company, the value of the Director’s benefits which have accrued under this Schedule as of the date the Director terminates from the Board shall be transferred from the Company to the subsidiary, affiliate or former affiliate of the Company, and the Company shall have no further obligation to make any distributions to the Director under Section 6.1 of the Schedule or any other section herein.

6.4    Distribution Election

(a)    Except as set forth in Section 6.4 (b) and (c) of this Pre-2005 Addendum, prior to the initial establishment of a Deferred Compensation Account for a

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Director, the Director must elect, in writing, that upon termination from the Board of Directors the values and quantities held in the Directors Deferred Compensation Accounts be distributed to the Director, pursuant to the provisions of this Section 6, in a lump sum or in a series of annual installments not to exceed ten (10) years. The time for the commencement of distribution shall not be later than the first day of the month coinciding with or next following the second anniversary of termination of Board membership.

(b)    Any Director who made a Deferred Pension Election made a Distribution Election at the time the Deferred Pension Election was made attributable to the Pension Benefit and any accumulated investment return.

(c)    In the event a Director terminates from the Board with Deferred Compensation Accounts established under Section 5.5 of this Schedule, the Transferred Amounts and accumulated investment return held in such Accounts shall be distributed to the Director in accordance with the Director’s distribution election in effect under the applicable deferred compensation plan for directors of Southern or one of its subsidiaries or affiliates on the date the Director is transferred to the Board and the provisions of this Section 6, unless such election is changed pursuant to Section 6.4(d) below.

(d)    Distribution Elections made under Sections 6.4(a), (b) and (c) above are irrevocable except that a Director may amend any of the Distribution Elections then in effect while the Director is still a director of the Company as required under Section 6.7 of this Pre-2005 Addendum and not later than the 361st day prior to the date of the earliest distribution elected and in place under this Pre-2005 Addendum. Any amendment to a Director’s Distribution Election pursuant to the preceding sentence shall not accelerate the commencement of the Director’s distribution to a date which is prior to the 13th month following the date of such amendment. In addition, any amendment to a Distribution Election must be made on a form prescribed by the Committee and delivered to the Secretary or Assistant Secretary of the Company.

6.5    Beneficiary Designation

A Director or former Director may designate a beneficiary to receive distributions under this Pre-2005 Addendum in accordance with the provisions of this Section 6 upon the death of the director. The beneficiary designation may be changed by a Director or former Director at any time, and without the consent of the prior beneficiary.

6.6    Form of Election

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All elections pursuant to the provisions of this Section 6 of the Pre-2005 Addendum shall be made in writing to the Secretary or Assistant Secretary of the Company on a form or forms available upon request of the Secretary or Assistant Secretary.

6.7    Distribution Limitations

Notwithstanding any other provision of this Pre-2005 Addendum: (i) elections under this Pre-2005 Addendum may only be made by Directors while they are directors of the Company (with the exception of the designation of beneficiaries), and (ii) distributions otherwise payable to a Director in the form of Common Stock shall be delayed and/or instead paid in cash in an amount equal to the fair market value thereof if such payment in Common Stock would violate any federal or State securities laws (including Section 16(b) of the Securities Exchange Act of 1934, as amended) and/or rules and regulations promulgated thereunder.

SECTION 7

Change in Control and Other Special Provisions

7.1    Notwithstanding any other terms of this Pre-2005 Addendum to the contrary, following a Funding Event or a Preliminary Change in Control as the case may be, the provisions of this Section 7 shall apply to the payment of benefits under this Pre-2005 Addendum with respect to any Director who is a Participant on such date.

7.2    The Deferred Cash Trust and the Deferred Stock Trust (collectively “Trusts”) have been established to hold assets of the Participating Companies under certain circumstances as a reserve for the discharge of the Company’s obligations under the Pre-2005 Addendum. In the event of a Funding Event involving a Funding Change in Control, the Company shall be obligated to immediately contribute such amounts to the Trusts as may be necessary to fully fund all benefits payable under this Pre-2005 Addendum in accordance with the procedures set forth in Section 7.3 hereof. All assets held in the Trusts remain subject only to the claims of Southern’s and the Participating Companies’ general creditors whose claims against Southern and the Participating Companies are not satisfied because of Southern’s or the Participating Companies’ bankruptcy or insolvency (as those terms were defined in the Trusts as in effect prior to January 1, 2005). No Participant has any preferred claim on, or beneficial ownership interest in, any assets of the Trusts before the assets are paid to the Participant and all rights created under the Trusts, as under this Pre-2005 Addendum, are unsecured contractual claims of the Participant against the Company.

7.3    As soon as practicable following a Funding Event, the Company shall contribute an amount based upon the funding strategy adopted by the Trust Administrator with the assistance of an appointed actuary necessary to fulfill the Company’s obligations pursuant to this Section 7. In the event of a dispute over such actuary’s determination, the Company and any complaining Participant(s) shall refer such dispute to an independent, third party actuarial consultant, chosen by the Company and such Participant. If the Company and the Participant cannot agree on an

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independent, third party actuarial consultant, the actuarial consultant shall be chosen by lot from an equal number of actuaries submitted by the Company and the applicable Trust Administrator. Any such referral shall only occur once in total and the determination by the third-party actuarial consultant shall be final and binding upon both parties. The Company shall be responsible for all of the fees and expenses of the independent actuarial consultant.

7.4    In the event of a Southern Change in Control, notwithstanding anything to the contrary in this Pre-2005 Addendum, upon termination as a Director, that amount in the Deferred Compensation Plan Account(s) of a Participant who was a Director determined as of such Change in Control shall be paid out in a lump sum if such Participant makes an election pursuant to procedures established by the Trust Administrator, in its sole and absolute discretion. If no such election is made, the Director shall receive payment of his Accounts solely in accordance with Section 6 of this Pre-2005 Addendum.

SECTION 8

General Provisions

8.1    In the event that the Company shall decide to establish an advance accrual reserve on its books against the future expense of payments from any Deferred Compensation Accounts, such reserve shall not under any circumstances be deemed to be an asset of this Pre-2005 Addendum but, at all times, shall remain a part of the general assets of the Company, subject to claims of the Company’s creditors.

8.2    A person entitled to any amount under this Pre-2005 Addendum shall be a general unsecured creditor of the Company with respect to such amount. Furthermore, a person entitled to a payment or distribution with respect to a Deferred Compensation Account shall have a claim upon the Company only to the extent of the balance in his Deferred Compensation Accounts.

8.3    The Company will pay all commissions, fees, and expenses that may be incurred in operating the Pre-2005 Addendum.

8.4    The Company will pay its prorated share of all commissions, fees, and expenses that may be incurred in operating any trust(s) established under the Pre-2005 Addendum (including the Deferred Stock Trust and the Deferred Cash Trust).

8.5    Notwithstanding any other provision of this Pre-2005 Addendum:

(a)    elections under this Pre-2005 Addendum may only be made by Directors while they are directors of the Company; (with the exception of the designation of beneficiaries); and

(b)    distributions otherwise payable to a Director in the form of Common Stock or other corporation’s stock shall be delayed and/or instead paid in cash in

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an amount equal to the fair market value thereof if such payment in stock would violate any federal or State securities laws (including Section 16(b) of the Securities Exchange Act of 1934, as amended) and/or rules and regulations promulgated thereunder.

8.6    Directors, their legal representatives and their beneficiaries shall have no right to anticipate, alienate, sell, assign, transfer, pledge or encumber their interests in the Pre-2005 Addendum, nor shall such interests be subject to attachment, garnishment, levy or execution by or on behalf of creditors of the Directors or of their beneficiaries.

SECTION 9

Administration

9.1    General Provisions

The Committee shall administer the Pre-2005 Addendum in accordance with its terms and shall have all powers necessary to carry out the provisions of the Pre-2005 Addendum as may be more particularly set forth herein. The Committee shall interpret the Pre-2005 Addendum and shall determine all questions arising in the administration, interpretation, and application of the Pre-2005 Addendum. Any such determination by the Committee shall be conclusive and binding on all persons. The Committee shall be the Pre-2005 Addendum’s agent for service of process.

The Committee may delegate to such officers, employees, or departments of the Company or Southern, such authority, duties, and responsibilities of the Committee as it, in its sole discretion, considers necessary or appropriate for the proper and efficient operation of the Pre-2005 Addendum, including, without limitation, (i) interpretation of the Pre-2005 Addendum, (ii) approval and payment of claims, and (iii) establishment of procedures for administration of the Pre-2005 Addendum.

9.2    Claims Process

If a claim for benefits under the Pre-2005 Addendum is denied, in whole or in part, the Committee will provide a written notice of the denial within a reasonable period of time, but not later than 90 days after the claim is received. If special circumstances require more time to process the claim, the Committee will issue a written explanation of the special circumstances prior to the end of the 90 day period and a decision will be made as soon as possible, but not later than 180 days after the claim is received.

The written notice of claim denial will include:

•    Specific reasons why the claim was denied;

•    Specific references to applicable provisions of the Pre-2005 Addendum document or other relevant records or papers on which the denial is based, and information about where a Participant or his or her beneficiary may see them;

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•    A description of any additional material or information needed to process the claim, and an explanation of why such material or information is necessary; and

•    An explanation of the claims review procedure, including the time limits applicable to such procedure, as well as a statement notifying the Participant or his or her beneficiary of their right to file suit if the claim for benefits is denied, in whole or in part, on review.

Upon request, a Participant or his or her beneficiary will be provided without charge, reasonable access to, and copies of, all non-confidential documents that are relevant to any denial of benefits. A claimant has 60 days from the day he or she receives the original denial to request a review. Such request must be made in writing and sent to the Committee. The request should state the reasons why the claim should be reviewed and may also include evidence or documentation to support the claimant’s position.

The Committee will reconsider the claimant’s claim, taking into account all evidence, documentation, and other information related to the claim and submitted on the claimant’s behalf, regardless of whether such information was submitted or considered in the initial denial of the claim. The Committee will make a decision within 60 days. If special circumstances require more time for this process, the claimant will receive written explanation of the special circumstances prior to the end of the initial 60 day period and a decision will be sent as soon as possible, but not later than 120 days after the Committee receives the request.

No legal action to recover benefits or enforce or clarify rights under a Pre-2005 Addendum can be commenced until the Participant or his or her beneficiary has first exhausted the claims and review procedures provided under the Pre-2005 Addendum.

SECTION 10

Amendment and Termination

10.1    Amendment of the Pre-2005 Addendum

This Pre-2005 Addendum may be amended or terminated at any time by the Board in its sole discretion at any time and from time to time by written resolution expressly modifying this Pre-2005 Addendum provided, however, that no such amendment or termination shall impair any rights to any benefits that have accrued hereunder, and further provided that no such amendment or termination of the Pre-2005 Addendum shall be effective if such amendment or termination is made or is effective within a period that is (a) six (6) months before, or at any time after, a Preliminary Change in Control and (b) prior to (x) the earlier of such time as the Southern Committee shall have determined that the event that gave rise to such Preliminary Change in Control shall not be Consummated or (y) two years following the Southern Change in Control, unless such amendment or termination during such period has the effect of increasing benefits to Participants under the Pre-2005 Addendum, is determined by the Board of Directors to be immaterial, or applies solely to Directors who in the case of a Southern Change in Control are not Directors on the date of the Southern Change in Control. Following a Southern Change in Control, nothing in this Section 10.1 shall prevent the Board of Directors from amending or terminating the

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Pre-2005 Addendum as to any subsequent Southern Change in Control provided that no such amendment or termination shall impair any rights or reduce any benefits previously accrued under the Pre-2005 Addendum as a result of a previous Southern Change in Control. It is the Company’s intent that any modification to this Pre-2005 Addendum shall not constitute nor shall it be interpreted to be a “material modification” of any right or feature of this Pre-2005 Addendum as such term is defined under Code Section 409A, Internal Revenue Service Notice 2005-1, Treasury Regulation Section 1.409A-1 et seq., or any subsequent guidance promulgated by the Treasury Department, unless the Pre-2005 Addendum is amended contemporaneously to comply with Code Section 409A.

10.2    Governing Law

This Pre-2005 Addendum shall be construed in accordance with and governed by the laws of the State of Georgia to the extent not inconsistent with the requirements of the Employee Retirement Income Security Act of 1974, as amended, and Code Section 409A.

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EX-10.B2

Exhibit 10(b)2

DEFERRED COMPENSATION PLAN FOR

OUTSIDE DIRECTORS OF ALABAMA POWER COMPANY

Amended and Restated Effective June 1, 2021

SECTION 1

Purpose and Adoption of Plan

1.1    Adoption

Alabama Power Company previously established the Deferred Compensation Plan for Outside Directors of Alabama Power Company. The Plan has been amended from time to time including an amendment and restatement dated January 1, 2000, a good faith amendment and restatement effective January 1, 2008 to comply with Code Section 409A and this amendment and restatement effective June 1, 2021. Except as otherwise provided herein and consistent with Section 1.2, the terms of the Plan as in effect prior to January 1, 2008 shall continue to be applicable to deferrals made pursuant to the Plan prior to January 1, 2008.

1.2    Pre-2005 Deferrals

Compensation paid to Directors and deferred under the Plan prior to January 1, 2005 shall be treated by the Company as not subject to Code Section 409A and therefore “grandfathered.” The Account balance (plus earnings thereon) of the “grandfathered” deferrals shall only be subject to the provisions of the Plan in effect prior to January 1, 2005 as set forth in the Provisions for Pre-2005 Deferrals Under the Deferred Compensation Plan for Outside Directors of Alabama Power Company (the “Pre-2005 Terms”). In accordance with transition rules under Code Section 409A, Internal Revenue Service Notice 2005-1, and any other applicable guidance from the Department of Treasury, the provisions of the Pre-2005 Terms are only intended to preserve the rights and features of the “grandfathered” deferrals and are, therefore, not intended to be “materially modified” with respect to any aspect of such rights and features. Provisions of the prior Plan should be so construed whenever necessary or appropriate.

SECTION 2

Purpose

The Plan provides Directors with an opportunity to defer compensation paid to them until a date following their Separation from Service.

SECTION 3

Eligibility

An individual who serves as a Director and is not otherwise actively employed by the Company or any of its subsidiaries or affiliates is eligible to participate in the Plan.

SECTION 4

Plan Periods

Except as pertains to a Director’s initial Plan Period, all Plan Periods shall be on a calendar year basis. The initial Plan Period applicable to any person elected to the Board who

was not a Director on the preceding December 31, shall begin on the first day of the calendar quarter following the effective date of the Director’s election to the Board.

SECTION 5

Elections

5.1    Cash Compensation

(a)    Prior to the beginning of a Plan Period, a Director may direct that payment of all or any portion of Cash Compensation that otherwise would be paid to the Director for the Plan Period, be deferred in amounts as designated by the Director, and credited to (i) a Prime Rate Investment Account, (ii) a Phantom Stock Investment Account, or (iii) a Deferred Stock Account. With respect to a Director’s initial Plan Period, such deferral election shall be made in a timely manner prior to the commencement of the Plan Period in accordance with requirements established by the Board consistent with Section 4. Upon the Director’s Separation from Service, such deferred compensation and accumulated investment return held in the Director’s Deferred Compensation Accounts shall be distributed to the Director in accordance with the Director’s Distribution Election and the provisions of Section 7.

(b)    An election to defer Cash Compensation is irrevocable for a Plan Period. Such an election shall continue from Plan Period to Plan Period unless the Director timely changes his or her election to defer Cash Compensation payable in a future Plan Period prior to the beginning of such future Plan Period.

(c)    Cash Compensation deferred under this Section 5.1 shall be invested in Deferred Compensation Accounts as directed by the Director prior to the Compensation Payment Date in accordance with procedures established by the Board.

5.2    Stock Retainer

(a)    Prior to the beginning of a Plan Period, a Director may direct that payment of all of the Stock Retainer that otherwise would be paid to the Director for the Plan Period, be deferred by the Director, and credited to the Director’s Deferred Stock Account. Such deferred compensation and accumulated investment return held in the Director’s Deferred Stock Account shall be distributed to the Director in accordance with the Director’s Distribution Election and the provisions of Section 7.

(b)    An election to defer the Stock Retainer is irrevocable for a Plan Period. Such an election shall continue from Plan Period to Plan Period unless the Director timely changes the Director’s election to defer the Director’s Stock Retainer paid in a future Plan Period prior to the beginning of such future Plan Period.

(c)    Any Stock Retainer deferred under this Section 5.2 shall be invested in the Deferred Stock Account.

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5.3    No Transfers Between Deferred Compensation Accounts

A Participant may not transfer any portion of the Participant’s Deferred Compensation Account(s) to another Deferred Compensation Account(s).

5.4    Distribution Election

(a)    Except as set forth in Section 5.4(b), prior to the initial establishment of a Deferred Compensation Account for a Director, the Director must elect that upon Separation from Service the values and quantities held in the Director’s Deferred Compensation Accounts be distributed to the Director, pursuant to the provisions of Section 7 in a single lump sum or in a series of annual or quarterly installments not to exceed fifteen (15) years; provided that the Board may establish in writing alternative installment payment schedules for any or all of the Deferred Compensation Accounts. In accordance with this Section 5.4(a), distributions from the Prime Rate Investment Account and Phantom Stock Investment Account can be in a lump sum or in annual or quarterly installments. In accordance with this Section 5.4(a), distributions from the Deferred Stock Account can be lump sum or annual installments. The time for the commencement of distributions shall be elected by the Director and shall not be later than the first of the month coinciding with or next following the second anniversary of the Director’s Separation from Service. Notwithstanding the foregoing, a Director may elect to modify his or her distribution election to delay distribution under this Section 5.4 provided that such modification is subject to the requirements of the Modification Delay.

(b)    In the event a Director has transferred to the Board and has Deferred Compensation Accounts established under Section 6.4, then upon the Director’s Separation from Service the Transferred Amounts and accumulated investment return held in the Deferred Compensation Accounts shall be distributed to the Director in accordance with the Director’s distribution election in effect under the applicable deferred compensation plan for directors of Alabama Power Company, Georgia Power Company, Mississippi Power Company, or Southern Company Gas on the date the Director transferred to the Board, and the provisions of Section 7, unless such distribution election is modified to delay distribution pursuant to Section 5.4(a).

5.5    Beneficiary Designation

A Director or former Director may designate a beneficiary to receive distributions from the Plan in accordance with the provisions of Section 7 upon the death of the Director. The beneficiary designation may be changed by a Director or former Director at any time, and without the consent of the prior beneficiary, except as required under applicable law.

5.6    Form of Election

All elections pursuant to the provisions of this Section 5 of the Plan shall be made in writing to the Secretary of the Company or Assistant Secretary of the Company or such other person designated by the Board on a form or forms available upon request.

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SECTION 6

Accounts

6.1    Prime Rate Investment Account

A Prime Rate Investment Account shall be established for each Director electing deferral of Cash Compensation for investment at the Prime Interest Rate. The amount of Cash Compensation directed by a Director to be credited to the Prime Rate Investment Account shall be credited to it as of the Compensation Payment Date, as applicable, and credited thereafter with interest computed using the Prime Interest Rate. Interest shall be computed from the date such compensation is credited to the account and compounded quarterly at the end of each calendar quarter. The Prime Interest Rate in effect on the first day of a calendar quarter shall be deemed the Prime Interest Rate in effect for that entire quarter. Interest shall accrue and compound on any balance until the amount credited to the account is fully distributed.

6.2    Phantom Stock Investment Account

(a)    If a Director elects to direct deferred amounts into the Phantom Stock Investment Account, then, on the applicable Compensation Payment Date, the Director’s Phantom Stock Investment Account shall be credited with a number of Phantom Stock Units equal to (i) the amount deferred into the Phantom Stock Investment Account, divided by (ii) the Market Value on such date, and rounded to the nearest ten-thousandth.

(b)    On the date of the payment of dividends on the Common Stock, a Director’s Phantom Stock Investment Account shall be credited with additional Phantom Stock Units, as follows:

(i)    In the case of dividends payable in cash or property other than cash or Common Stock, a number of Phantom Stock Units equal to (A) the cash or fair market value of any dividends declared and made with respect to the Common Stock payable in cash or other property which the Director would have received had the Director been the owner on the record dates for the payment of such dividends of the number of shares of Common Stock equal to the number of Phantom Stock Units in the Director’s Phantom Stock Investment Account on such dates, divided by (B) the Market Value on the dividend payment date, rounded to the nearest ten-thousandth; or

(ii)    In the case of dividends payable in Common Stock, a number of Phantom Stock Units equal to the number of shares of Common Stock to which the Director would have been entitled as Common Stock dividends had such Director been the owner on the record dates for the payments of such stock dividends of the number of shares of Common Stock equal to the number of Phantom Stock Units credited to the Director’s Phantom Stock Investment Account on such dates, rounded to the nearest ten-thousandth.

(c)    In the event of (i) a corporate event or transaction involving Southern that results in a change in the Common Stock, or an exchange of Common Stock for cash, securities other than Common Stock, or other property (including, without limitation, any merger, reorganization, recapitalization, combination or exchange of shares), or (ii) any transaction between Southern and

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the holders of Common Stock that causes the per-share value of the Common Stock to change (including, without limitation, any conversion of shares, share dividend, share split, spin-off, rights offering, or large non-ordinary cash dividend), the Board shall make such equitable adjustments to the Phantom Stock Units as it deems necessary, in its sole discretion, to prevent dilution or enlargement of rights immediately resulting from such transaction. Notwithstanding the preceding sentence and in any event, any adjustment shall comply with the requirements of Section 409A of the Code.

6.3    Deferred Stock Account

(a)    If a Director elects to direct deferred amounts into the Deferred Stock Account, then, on the applicable Compensation Payment Date, the Director’s Deferred Stock Account shall be credited with a number of Deferred Stock Units equal to (i) the amount deferred into the Deferred Stock Account, divided by (ii) the Market Value on the Compensation Payment Date, and rounded to the nearest ten-thousandth; provided, however, that the Board may adopt another valuation method so long as such method is communicated in writing to Participants prior to the commencement of the Plan Period during which such valuation method will apply.

(b)    If a Director elects to defer a Stock Retainer under Section 5.2, then on the applicable Compensation Payment Date, the Director’s Deferred Stock Account shall be credited with a number of Deferred Stock Units equal to the number of shares of Common Stock the Director would have received for such Stock Retainer if it had not been deferred.

(c)    On the date of the payment of dividends on the Common Stock, a Director’s Deferred Stock Account shall be credited with additional Deferred Stock Units, as follows:

(i)    In the case of dividends payable in cash or property other than cash or Common Stock, a number of Deferred Stock Units equal to (A) the cash or fair market value of any dividends declared and made with respect to the Common Stock payable in cash or other property which the Director would have received had the Director been the owner on the record dates for the payment of such dividends of the number of shares of Common Stock equal to the number of Deferred Stock Units in the Director’s Deferred Stock Account on such dates, divided by (B) the Market Value on the dividend payment date, rounded to the nearest ten-thousandth; provided, however, that the Board may adopt another valuation method so long as such method is communicated in writing to Participants prior to the commencement of the Plan Period during which such valuation method will apply; or

(ii)    In the case of dividends payable in Common Stock, a number of Deferred Stock Units equal to the number of shares of Common Stock to which the Director would have been entitled as Common Stock dividends had such Director been the owner on the record dates for the payments of such stock dividends of the number of shares of Common Stock equal to the number of Deferred Stock Units credited to the Director’s Deferred Stock Account on such dates, rounded to the nearest ten-thousandth.

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(d)    Except as expressly provided in this Plan, a Director shall have no rights as a stockholder of Southern with respect to Common Stock credited to the Director’s Deferred Stock Account unless and until such Common Stock is paid to the Director.

(e)    In the event of (i) a corporate event or transaction involving Southern that results in a change in the Common Stock, or an exchange of Common Stock for cash, securities other than Common Stock, or other property (including, without limitation, any merger, reorganization, recapitalization, combination or exchange of shares), or (ii) any transaction between Southern and the holders of Common Stock that causes the per-share value of the Common Stock to change (including, without limitation, any conversion of shares, share dividend, share split, spin-off, rights offering, or large non-ordinary cash dividend), the Board shall make such equitable adjustments to the Deferred Stock Units as it deems necessary, in its sole discretion, to prevent dilution or enlargement of rights immediately resulting from such transaction. Notwithstanding the preceding sentence and in any event, any adjustment shall comply with the requirements of Section 409A of the Code.

6.4    Transferred Amounts

(a)    As soon as administratively practicable, the Company shall establish for a Director transferring to the Board from the Southern Board or from the board of directors of Georgia Power Company, Mississippi Power Company, or Southern Company Gas such Deferred Compensation Accounts as are necessary to implement Section 6.4(b).

(b)    Any Transferred Amounts will be credited to the Deferred Compensation Account(s) established that are comparable to the deferred compensation accounts to which such amounts were credited under the applicable deferred compensation plan for directors of Southern, Georgia Power Company, Mississippi Power Company, or Southern Company Gas as soon as administratively practicable following the date the Transferred Amounts are transferred to the Plan. Thereafter, the Transferred Amounts shall be credited with investment returns as applicable under this Section 6 of the Plan.

SECTION 7

Distributions

7.1    Manner of Distribution

Upon a Director’s Separation from Service, the amount credited to a Director’s Deferred Compensation Accounts will be paid to the Director or the Director’s beneficiary, as applicable, in the following manner:

(a)    the amount credited to a Director’s Prime Rate Investment Account and Phantom Stock Investment Account shall be paid in cash; and

(b)    the amount credited to a Director’s Deferred Stock Account shall, except as otherwise provided in Section 6.3 and Section 9.5, or to the extent the Company is otherwise, in the reasonable judgment of the Board, precluded from doing so, be paid in shares of Common

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Stock (with any fractional share interest therein paid in cash to the extent of the then Market Value thereof).

Such payments shall be from the general assets of the Company (including the Deferred Cash Trust and the Deferred Stock Trust) in accordance with this Section 7.

Notwithstanding the foregoing, in the event the Company enters into an agreement described in Section 7.3 with respect to a Director prior to the Director’s Separation from Service, the Company shall have no obligation to make distributions to the Director under this Section 7.1 in connection with such Director’s Separation from Service.

7.2    Timing of Distribution(s)

Subject to Section 5.4, deferred amounts shall be paid in the form of (i) a lump sum payment, or (ii) in approximately equal annual or quarterly installments, as elected by the Director. Such payments shall be made (or shall commence) as soon as practicable following the Separation from Service except that such period shall not exceed ninety (90) days as permitted by Code Section 409A or, if so elected by the Director in the Distribution Election, up to twenty-four (24) months following such Separation from Service.

If at the time of a Director’s Separation from Service, the Director’s Deferred Compensation Accounts have a cumulative balance of less than the limit in effect under Code Section 402(g)(1)(B), the balance of the Deferred Compensation Accounts may be distributed in a single lump sum payment.

If the Director elected to receive annual or quarterly installments, the first installment shall be equal to the balance in the Director’s Deferred Compensation Accounts on such date divided by the number of annual or quarterly installment payments. Each subsequent annual or quarterly payment shall be an amount equal to the balance in the Director’s Deferred Compensation Accounts on the date of payment divided by the number of the then-remaining annual or quarterly payments and shall be paid on the next appropriate date of payment.

The Market Value of any shares of Common Stock credited to a Director’s Phantom Stock Investment Account shall be determined as of the date of any lump sum or installment distribution as determined by the Board.

Upon the death of a Director, or a former Director prior to the payment of all amounts credited to the Director’s Deferred Compensation Accounts, the unpaid balance shall be paid in a lump sum to the designated beneficiary of such Director or former Director within sixty (60) days of the date of death as permitted by Code Section 409A. In the event a beneficiary designation has not been made, or the designated beneficiary is deceased or cannot be located, payment shall be made to the estate of the Director or former Director.

To the maximum extent permitted under Treasury Regulations § 1.409A-3(i)(3), the Board, in its sole discretion, may determine to pay an amount credited to a Director’s Deferred Compensation Accounts on account of an unforeseeable emergency.

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The Market Value of any shares of Common Stock credited to a Director’s Phantom Stock Investment Account shall be determined as of the date of any lump sum or installment distribution as determined by the Board.

7.3    Transfers

If the Company enters into a written agreement with the parent, subsidiary, affiliate or former affiliate of the Company under which the parent or subsidiary, affiliate or former affiliate assumes the liability for a Director’s benefits accrued under the Plan in connection with, but prior to, such Director’s Separation from Service and the Director either has been or will be elected to the board of directors of such parent or subsidiary, affiliate or former affiliate of the Company, the liability for the Director’s benefits which have accrued under the Plan as of the date the Director Separates from Service shall be transferred from the Company to the parent or subsidiary, affiliate or former affiliate of the Company, and the Company shall have no further obligation to make any distributions to the Director under Section 7.1 or any other section herein. For the avoidance of doubt, the event described in the preceding sentence shall not constitute a distribution event whereby deferred amounts under the Plan are paid to the Director in accordance with this Section 7.

SECTION 8

Funding Change in Control and Other Special Provisions

8.1    Funding Change in Control

Notwithstanding any other terms of the Plan to the contrary, following a Funding Event, the provisions of this Section 8 shall apply to the payment of benefits under the Plan with respect to any Director who is a Participant on such date.

8.2    Funding of Trusts

The Deferred Cash Trust and the Deferred Stock Trust (collectively “Trusts”) have been established to hold assets of Southern and the Participating Companies under certain circumstances as a reserve for the discharge of the Company’s obligations under the Plan. In the event of a Funding Event involving a Funding Change in Control, the Company shall be obligated to immediately contribute such amounts to the Trusts as may be necessary to fully fund all benefits payable under the Plan in accordance with the procedures set forth in Section 8.3 hereof. All assets held in the Trusts remain subject only to the claims of the general creditors of Southern and the respective Participating Company (or Participating Companies) under federal or state law in the event of Insolvency (as defined in the Trusts). No Participant has any preferred claim on, or beneficial ownership interest in, any assets of the Trusts before the assets are paid to the Participant and all rights created under the Trusts, as under the Plan, are unsecured contractual claims of the Participant against the Company.

8.3    Funding Timing and Dispute Resolution

As soon as practicable following a Funding Event, the Company shall contribute to each Trust an amount based upon the funding strategy adopted by the Trust Administrator with the

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assistance of an appointed actuary necessary to fulfill the Company’s obligations pursuant to this Section 8. In the event of a dispute over such actuary’s determination with respect to either or both Trusts, the Company and any complaining Participant(s) shall refer such dispute to an independent, third party actuarial consultant, chosen by the Company and such Participant. If the Company and the Participant cannot agree on an independent, third party actuarial consultant, the actuarial consultant shall be chosen by lot from an equal number of actuaries submitted by the Company and the applicable Trust Administrator. Any such referral shall only occur once in total and the determination by the third-party actuarial consultant shall be final and binding upon both parties. The Company shall be responsible for all of the fees and expenses of the independent actuarial consultant.

8.4    Lump Sum Payment

In the event of a Funding Change in Control, notwithstanding anything to the contrary in the Plan, upon a Director’s Separation from Service, that amount in the Deferred Compensation Plan Account(s) of a Participant who was a Director determined as of the date of such Funding Change in Control shall be paid out in a lump sum provided that such Separation from Service occurred within two calendar years following the Funding Change in Control and that such Funding Change in Control constitutes a change in control event for purposes of Code Section 409A. The lump sum payment shall be made within ninety (90) days of such Separation from Service as permitted by Code Section 409A.

SECTION 9

General Provisions

9.1    In the event that the Company shall decide to establish an advance accrual reserve on its books against the future expense of payments from any Deferred Compensation Accounts, such reserve shall not under any circumstances be deemed to be an asset of this Plan but, at all times, shall remain a part of the general assets of the Company, subject to claims of the Company’s creditors.

9.2    A person entitled to any amount under this Plan shall be a general unsecured creditor of the Company with respect to such amount. Furthermore, a person entitled to a payment or distribution with respect to a Deferred Compensation Account shall have a claim upon the Company only to the extent of the balance in such person’s Deferred Compensation Accounts.

9.3    The Company will pay all commissions, fees, and expenses that may be incurred in operating the Plan.

9.4    The Company will pay its prorated share of all commissions, fees, and expenses that may be incurred in operating any trust(s) established under the Plan (including the Deferred Stock Trust and the Deferred Cash Trust).

9.5    Notwithstanding any other provision of this Plan:

(a)    elections under this Plan may only be made by Directors while they are directors of the Company; (with the exception of the designation of beneficiaries); and

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(b)    distributions otherwise payable to a Director in the form of Common Stock or other corporation’s stock shall be delayed and/or instead paid in cash in an amount equal to the fair market value thereof if such payment in stock would violate any federal or State securities laws (including Section 16(b) of the Securities Exchange Act of 1934, as amended) and/or rules and regulations promulgated thereunder.

9.6    Directors, their legal representatives and their beneficiaries shall have no right to anticipate, alienate, sell, assign, transfer, pledge or encumber their interests in the Plan, nor shall such interests be subject to attachment, garnishment, levy or execution by or on behalf of creditors of the Directors or of their beneficiaries.

SECTION 10

Administration

10.1    General Provisions

The Board shall administer the Plan in accordance with its terms and shall have all powers necessary to carry out the provisions of the Plan as may be more particularly set forth herein. The Board shall interpret the Plan and shall determine all questions arising in the administration, interpretation, and application of the Plan. Any such determination by the Board shall be conclusive and binding on all persons. The Board shall be the Plan’s agent for service of process. The Board may designate a committee of the Board to be responsible for administering the Plan.

The Board may delegate to such officers, employees, or departments of the Company or Southern, such authority, duties, and responsibilities of the Board as it, in its sole discretion, considers necessary or appropriate for the proper and efficient operation of the Plan, including, without limitation, (i) interpretation of the Plan, (ii) approval and payment of claims, and (iii) establishment of procedures for administration of the Plan.

10.2    Claims Process

If a claim for benefits under the Plan is denied, in whole or in part, the Board will provide a written notice of the denial within a reasonable period of time, but not later than 90 days after the claim is received. If special circumstances require more time to process the claim, the Board will issue a written explanation of the special circumstances prior to the end of the 90 day period and a decision will be made as soon as possible, but not later than 180 days after the claim is received.

The written notice of claim denial will include:

•    Specific reasons why the claim was denied;

•    Specific references to applicable provisions of the Plan document or other relevant records or papers on which the denial is based, and information about where a Participant or the Participant’s beneficiary may see them;

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•    A description of any additional material or information needed to process the claim, and an explanation of why such material or information is necessary; and

•    An explanation of the claims review procedure, including the time limits applicable to such procedure, as well as a statement notifying the Participant or the Participant’s beneficiary of their right to file suit if the claim for benefits is denied, in whole or in part, on review.

Upon request, a Participant or the Participant’s beneficiary will be provided without charge, reasonable access to, and copies of, all non-confidential documents that are relevant to any denial of benefits. A claimant has 60 days from the day the claimant receives the original denial to request a review. Such request must be made in writing and sent to the Board. The request should state the reasons why the claim should be reviewed and may also include evidence or documentation to support the claimant’s position.

The Board will reconsider the claimant’s claim, taking into account all evidence, documentation, and other information related to the claim and submitted on the claimant’s behalf, regardless of whether such information was submitted or considered in the initial denial of the claim. The Board will make a decision within 60 days. If special circumstances require more time for this process, the claimant will receive written explanation of the special circumstances prior to the end of the initial 60 day period and a decision will be sent as soon as possible, but not later than 120 days after the Board receives the request.

No legal action to recover benefits or enforce or clarify rights under a Plan can be commenced until the Participant or the Participant’s beneficiary has first exhausted the claims and review procedures provided under the Plan.

SECTION 11

Definitions

11.1    “Beneficial Ownership” means beneficial ownership within the meaning of Rule 13d-3 promulgated under the Exchange Act.

11.2    “Board” or “Board of Directors” means the Board of Directors of the Company. In the event the Board designates a committee of the Board to be responsible for administering the Plan under Section 10.1, the term “Board” or “Board of Directors” shall mean such committee.

11.3    “Business Combination” means a reorganization, merger or consolidation or sale of Southern with another corporation or an entity treated as a corporation for United States federal income tax purposes.

11.4    “Cash Compensation” means the annual cash retainer fees and cash meeting fees payable to a Director.

11.5    “Code” means the Internal Revenue Code of 1986, as amended, or any successor statute.

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11.6    “Common Stock” means the common stock of Southern including any shares into which it may be split, subdivided, or combined.

11.7    “Company” means Alabama Power Company, or any successor thereto.

11.8    “Company Change in Control” means the following:

(a)    The Consummation of an acquisition by any Person of Beneficial Ownership of 50% or more of the combined voting power of the then outstanding Voting Securities of the Company; provided, however, that for purposes of this Section 11.8, any acquisition by an Employee, or Group composed entirely of Employees, any qualified pension plan, any publicly held mutual fund or any employee benefit plan (or related trust) sponsored or maintained by Southern or any corporation Controlled by Southern shall not constitute a Change in Control;

(b)    Consummation of a reorganization, merger or consolidation of the Company (a “Company Business Combination”), in each case, unless, following such Company Business Combination, Southern Controls the corporation surviving or resulting from such Company Business Combination; or

(c)    Consummation of the sale or other disposition of all or substantially all of the assets of the Company to an entity which Southern does not Control.

11.9    “Compensation Payment Date” means the date on which compensation, including Cash Compensation and the Stock Retainer, is payable to a Director or would otherwise be payable to a Director if an election to defer such compensation had not been made.

11.10    “Consummation” means the completion of the final act necessary to complete a transaction as a matter of law, including, but not limited to, any required approvals by the corporation’s shareholders and board of directors, the transfer of legal and beneficial title to securities or assets and the final approval of the transaction by any applicable domestic or foreign governments or agencies.

11.11    “Control” means, in the case of a corporation, Beneficial Ownership of more than 50% of the combined voting power of the corporation’s Voting Securities, or in the case of any other entity, Beneficial Ownership of more than 50% of such entity’s voting equity interests.

11.12    “Deferred Cash Trust” means the Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of The Southern Company and its Subsidiaries, as amended or amended and restated from time to time.

11.13    “Deferred Compensation Account” means the Prime Rate Investment Account, the Phantom Stock Investment Account and/or the Deferred Stock Account.

11.14    “Deferred Stock Account” means the bookkeeping account established under Section 6.3 on behalf of a Director and includes shares of Common Stock credited thereto to reflect the reinvestment of dividends.

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11.15    “Deferred Stock Trust” means the Amended and Restated Deferred Stock Trust Agreement for Directors of The Southern Company and its Subsidiaries, as amended or amended and restated from time to time.

11.16    “Deferred Stock Unit” means a bookkeeping unit, having at all times a value equal to one share of Common Stock, credited to a Participant’s Deferred Stock Account.

11.17    “Director” means a member of the Board.

11.18    “Distribution Election” means the designation by a Director of the manner of distribution of the amounts and quantities held in the Director’s Deferred Compensation Accounts upon the director’s Separation from Service pursuant to Section 5.4.

11.19    “Employee” means an employee of Southern or any of its subsidiaries that are “employing companies” as defined in the Southern Company Deferred Compensation Plan as amended and restated effective June1, 2021, and as may be amended from time to time.

11.20    “Exchange Act” means the Securities Exchange Act of 1934, as amended.

11.21    “Funding Change in Control” means any of the following:

(a)    The Consummation of an acquisition by any Person of Beneficial Ownership (during the 12-month period ending on the date of the most recent acquisition by such Person) of 35% or more of Southern’s Voting Securities; provided, however, that for purposes of this subsection (a), the following acquisitions of Southern’s Voting Securities shall not constitute a Funding Change in Control:

(i)    any acquisition directly from Southern;

(ii)    any acquisition by Southern;

(iii)    any acquisition by any employee benefit plan (or related trust) sponsored or maintained by Southern or any corporation controlled by Southern;

(iv)    any acquisition by a qualified pension plan or publicly held mutual fund;

(v)    any acquisition by an employee of Southern or its subsidiary or affiliate, or Group composed exclusively of such employees; or

(vi)    any Business Combination which would not otherwise constitute a Funding Change in Control because of the application of clauses (i), (ii) and (iii) of this Section 11.21(a);

(b)    The date a majority of members of the Southern Board is replaced during any 12-month period by directors whose appointment or election is not endorsed by a majority of the members of the Southern Board before the date of the appointment or election;

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(c)    The Consummation of a Business Combination, unless, following such Business Combination, all of the following three conditions are met:

(i)    all or substantially all of the individuals and entities who held Beneficial Ownership, respectively, of Southern’s Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, 50% or more of the combined voting power of the Voting Securities of the corporation surviving or resulting from such Business Combination, (including, without limitation, a corporation which as a result of such transaction holds Beneficial Ownership of all or substantially all of Southern’s Voting Securities or all or substantially all of Southern’s assets) (such surviving or resulting corporation to be referred to as “Surviving Company”), in substantially the same proportions as their ownership, immediately prior to such Business Combination, of Southern’s Voting Securities;

(ii)    no Person (excluding any corporation resulting from such Business Combination, any qualified pension plan, publicly held mutual fund, Group composed exclusively of employees or employee benefit plan (or related trust) of Southern, its subsidiaries or Surviving Company) holds Beneficial Ownership, directly or indirectly, of 35% or more of the combined voting power of the then outstanding Voting Securities of Surviving Company except to the extent that such ownership existed prior to the Business Combination; and

(iii)    the majority of the members of the board of directors of Surviving Company during the 12-month period following the Business Combination were members of the Southern Board at the earlier of the date of execution of the initial agreement, or of the action of the Southern Board, providing for such Business Combination or such members of the board of directors of the Surviving Company are directors whose appointment or election was endorsed by a majority of the members of such Southern Board.

(d)    The Consummation of an acquisition by any Person of Beneficial Ownership (during the 12-month period ending on the date of the most recent acquisition by such Person) of 50% or more of the combined voting power of the then outstanding Voting Securities of the Company; provided, however, that for purposes of this Subsection 11.21(d), any acquisition by an employee of Southern or its subsidiary or affiliate, or Group composed entirely of such employees, any qualified pension plan, publicly held mutual fund or any employee benefit plan (or related trust) sponsored or maintained by Southern or any corporation Controlled by Southern shall not constitute a Funding Change in Control;

(e)    The Consummation of a reorganization, merger or consolidation of the Company with another corporation (a “Funding Subsidiary Business Combination”), in each case, unless, following such Funding Subsidiary Business Combination, Southern Controls the corporation surviving or resulting from such Funding Subsidiary Business Combination, or

(f)    The Consummation of the sale or other disposition of all or substantially all of the assets of the Company to an entity that Southern does not Control; provided, however, that for purposes of this subsection (f) the following sales or dispositions otherwise described herein shall not constitute a Funding Change in Control:

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(i)    the sale or other disposition of all or substantially all of the assets of the Company to Southern or to a shareholder of Southern in exchange for or with respect to such shareholder’s stock of Southern;

(ii)    the sale of other disposition of all or substantially all of the assets of the Company to a Person that owns, directly or indirectly, 50% or more of the total value or voting power of the outstanding stock of Southern; or

(iii)    the sale or other disposition of all or substantially all of the assets of the Company to an entity Controlled by shareholders of Southern that hold, directly or indirectly, 50% or more of the total value or voting power of all of the outstanding stock of Southern.

For purposes of this Section 11.21(f) “all or substantially all of the assets” means at least 80% of the gross value of the assets of the entity immediately before the acquisition.

11.22    “Funding Event” means the occurrence of any of the following events as administratively determined by the Southern Committee:

(a)    Southern or the Company has entered into a written agreement, such as, but not limited to, a letter of intent, which, if Consummated, would result in a Funding Change in Control;

(b)    Southern, the Company or any other Person publicly announces an intention to take or to consider taking actions which, if Consummated, would result in a Funding Change in Control under circumstances where the Consummation of the announced action or intended action is legally and financially possible;

(c)    Any Person acquires Beneficial Ownership of fifteen percent (15%) or more of the Common Stock; or

(d)    The Southern Board or the Company elects to otherwise fund the Deferred Cash Trust and Deferred Stock Trust in accordance with the provisions of Section 8.

11.23    “Funding Subsidiary Business Combination” shall have the meaning set forth in Section 11.21(e) hereof.

11.24    “Group” has the meaning set forth in Section 14(d) of the Exchange Act.

11.25    “Incumbent Board” means those individuals who constitute the Southern Board as of June 1, 2021, plus any individual who shall become a director subsequent to such date whose election or nomination for election by Southern’s shareholders was approved by a vote of at least 75% of the directors then comprising the Incumbent Board. Notwithstanding the foregoing, no individual who shall become a director of the Southern Board subsequent to June 1, 2021, whose initial assumption of office occurs as a result of an actual or threatened election contest (within the meaning of Rule 14a-11 of the regulations promulgated under the Exchange Act) with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Southern Board shall be a member of the Incumbent Board.

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11.26    “Market Value” means the closing price at which a share of the Common Stock shall have been traded on the date such Market Value is to be determined, as specified herein (or on the next preceding trading day on which a sale was reported if such date was not a trading date), as reported by the principal securities exchange on which the Common Stock is traded. If the Common Stock is not listed for trading on a national securities exchange, the fair market value of the shares shall be determined by the Board in good faith and in accordance with a reasonable valuation method as determined under Code Section 409A and the rules and regulations promulgated thereunder.

11.27    “Modification Delay” means that the modified election shall not take effect until twelve (12) months after the date the modified election is made, the payment which is the subject of the modified election shall be deferred five (5) years from the date previously elected by the Director, and where applicable in the case of a payment made pursuant to a fixed schedule or specified time, the modified election must be made at least twelve (12) months prior to the time payment is scheduled to be made.

11.28    “Participant” means a Director or former Director who has an unpaid Deferred Compensation Account balance under the Plan.

11.29    “Participating Companies” means those companies that are affiliated with Southern whose boards of directors have authorized the establishment of trust(s) for the funding of directors’ Deferred Compensation Accounts and for which a Participant is providing (or has provided) services.

11.30    “Person” means any individual, entity or group within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act.

11.31    “Phantom Stock Investment Account” means the bookkeeping account established pursuant to Section 6.2 in which a Director may elect to defer Cash Compensation or make investments, and includes amounts credited thereto to reflect the reinvestment of dividends.

11.32    “Phantom Stock Unit” means a bookkeeping unit, having at all times a value equal to one share of Common Stock, credited to a Participant’s Phantom Stock Investment Account.

11.33    “Plan” means the Deferred Compensation Plan for Outside Directors of Alabama Power Company as from time to time in effect.

11.34    “Plan Period” means the period designated in Section 4.

11.35    “Preliminary Change in Control” means the occurrence of any of the following as determined by the Southern Committee:

(a)    Southern or the Company has entered into a written agreement, such as, but not limited to, a letter of intent, which, if Consummated, would result in a Southern Change in Control or a Company Change in Control, as the case may be;

(b)    Southern, the Company or any Person publicly announces an intention to take or to consider taking actions which, if Consummated, would result in a Southern Change in Control or

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a Company Change in Control under circumstances where the Consummation of the announced action or intended action is legally and financially possible;

(c)    Any Person becomes the Beneficial Owner of fifteen percent (15%) or more of the Common Stock; or

(d)    The Southern Board or the Board has declared that a Preliminary Change in Control has occurred.

11.36    “Prime Interest Rate” means the prime rate of interest as published in the Wall Street Journal or its successor on the first day of the applicable calendar quarter.

11.37    “Prime Rate Investment Account” means the bookkeeping account established pursuant to Section 6.1 in which a Director may elect to defer Cash Compensation or make investments, the investment return on which is computed at the Prime Interest Rate.

11.38    “Separation from Service” means a separation from service as such term is defined in Code Section 409A or any other applicable regulations or guidance from the Department of Treasury.

11.39    “Southern” means The Southern Company.

11.40    “Southern Board” means the Board of Directors of Southern.

11.41    “Southern Change in Control” means any of the following:

(a)    The Consummation of an acquisition by any Person of Beneficial Ownership of 20% or more of Southern’s Voting Securities; provided, however, that for purposes of this subsection (a), the following acquisitions of Southern’s Voting Securities shall not constitute a Change in Control:

(i)    any acquisition directly from Southern,

(ii)    any acquisition by Southern,

(iii)    any acquisition by any employee benefit plan (or related trust) sponsored or maintained by Southern or any corporation controlled by Southern,

(iv)    any acquisition by a qualified pension plan or publicly held mutual fund,

(v)    any acquisition by an Employee or Group composed exclusively of Employees, or

(vi)    any Business Combination which would not otherwise constitute a Southern Change in Control because of the application of clauses (i), (ii) and (iii) of Section 11.41(a) of this Plan;

(b)    A change in the composition of the Southern Board whereby individuals who constitute the Incumbent Board cease for any reason to constitute at least a majority of the Southern Board; or

(c)    Consummation of a Business Combination, unless, following such Business Combination, all of the following three conditions are met:

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(i)    all or substantially all of the individuals and entities who held Beneficial Ownership, respectively, of Southern’s Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, 65% or more of the combined voting power of the Voting Securities of the corporation surviving or resulting from such Business Combination, (including, without limitation, a corporation which as a result of such transaction holds Beneficial Ownership of all or substantially all of Southern’s Voting Securities or all or substantially all of Southern’s assets) (such surviving or resulting corporation to be referred to as “Surviving Company”), in substantially the same proportions as their ownership, immediately prior to such Business Combination, of Southern’s Voting Securities;

(ii)    no Person (excluding any corporation resulting from such Business Combination, any qualified pension plan, publicly held mutual fund, Group composed exclusively of employees or employee benefit plan (or related trust) of Southern, its subsidiaries, or Surviving Company) holds Beneficial Ownership, directly or indirectly, of 20% or more of the combined voting power of the then outstanding Voting Securities of Surviving Company except to the extent that such ownership existed prior to the Business Combination; and

(iii)    at least a majority of the members of the board of directors of Surviving Company were members of the Incumbent Board at the earlier of the date of execution of the initial agreement, or of the action of the Southern Board, providing for such Business Combination.

11.42    “Southern Committee” means a committee comprised of the Chairman of the Southern Board, the Chief Financial Officer of Southern and the General Counsel of Southern.

11.43    “Stock Retainer” means the annual Board retainer fee that is paid to the Director in the form of Common Stock.

11.44    “Transferred Amount” means an amount (a) equal to the value of a Director’s accounts under the applicable deferred compensation plan for directors of Southern, Georgia Power Company, Mississippi Power Company, or Southern Company Gas and (b) which has been transferred to the Plan in connection with the Director’s transfer from the Southern Board or the board of directors of Georgia Power Company Mississippi Power Company, or Southern Company Gas.

11.45    “Trust Administrator” means the individual or committee that is established in the Deferred Stock Trust and the Deferred Cash Trust, to administer such trusts.

11.46    “Voting Securities” means the outstanding voting securities of a corporation entitling the holder thereof to vote generally in the election of such corporation’s directors.

Where the context requires, words in the masculine gender shall include the feminine gender, words in the singular shall include the plural, and words in the plural shall include the singular.

SECTION 12

Amendment, Termination and Effective Date

12.1    Amendment of the Plan

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The Plan may be amended or terminated at any time by the Board of Directors, provided, however, that no such amendment or termination of the Plan shall be effective if such amendment or termination is made or is effective within a period that is (a) six (6) months before, or at any time after, a Preliminary Change in Control and (b) prior to (x) the earlier of such time as the Southern Committee shall have determined that the event that gave rise to such Preliminary Change in Control shall not be Consummated or (y) two years following the respective Change in Control, unless such amendment or termination during such period has the effect of increasing benefits to Participants under the Plan, is determined by the Board of Directors to be immaterial, or applies solely to Directors who, in the case of a Company Change in Control, are not Directors on the date of the respective Preliminary Change in Control, or, in the case of a Southern Change in Control, are not Directors on the date of the respective Southern Change in Control. Following a Change in Control, nothing in this Section 12.1 shall prevent the Board of Directors from amending or terminating the Plan as to any subsequent Change in Control provided that no such amendment or termination shall impair any rights or reduce any benefits previously accrued under the Plan as a result of a previous Change in Control.

12.2    No Impairment of Benefits

Notwithstanding the provisions of Section 12.1 herein, no amendment to or termination of the Plan shall impair any rights to benefits that have accrued hereunder.

12.3    Code Section 409A

All payments of “non-qualified deferred compensation” (within the meaning of Code Section 409A) under this Plan, whether or not expressly designated as such, are intended to comply with the requirements of Code Section 409A, and shall be interpreted in accordance therewith. Neither the Participant nor the Company may accelerate any such deferred payment, except in compliance with Code Section 409A for such events that include but may not be limited to a termination of the Plan.

To the extent of the reimbursement of expenses, (a) there shall be an objectively determinable nondiscretionary definition of expenses eligible for reimbursement; (b) such expenses shall be only those incurred during the Participant’s lifetime; (c) the amount of expenses eligible for reimbursement during a calendar year shall not affect the expenses eligible for reimbursement in any other taxable year; (d) the reimbursement of an eligible expense shall

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be made on or before the last day of the calendar year following the calendar year in which the expense was incurred; and (e) the right to reimbursement shall not be subject to liquidation or exchange for another benefit.

12.4    Governing Law

This Plan shall be construed in accordance with and governed by the laws of the state in which the Company is incorporated to the extent not inconsistent with the requirements of the Employee Retirement Income Security Act of 1974, as amended, and Code Section 409A.

IN WITNESS WHEREOF, the Plan, as amended and restated effective June 1, 2021, has been executed pursuant to resolutions of the Board, this day of July 21, 2021.

ALABAMA POWER COMPANY
By:	/s/Ceila H. Shorts

Attest:
By:	/s/Amy Riley

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PROVISIONS FOR PRE-2005 DEFERRALS UNDER
THE DEFERRED COMPENSATION PLAN FOR OUTSIDE DIRECTORS OF ALABAMA POWER COMPANY

SECTION 1

Purpose

1.1    Provisions for Pre-2005 Deferrals: This document (the “Pre-2005 Addendum”) sets forth the operative provisions of the Deferred Compensation Plan for Outside Directors of Alabama Power Company (as amended or amended and restated from time to time, the “Plan”) applicable to “grandfathered” deferrals of Cash Compensation and Stock Retainer made by Participants which are treated by the Company as not subject to Code Section 409A. The Deferred Compensation Account balance (plus earnings thereon) of the grandfathered deferrals shall only be subject to the provisions set forth in this Pre-2005 Addendum. In accordance with transition rules under Code Section 409A, Internal Revenue Service Notice 2005-1, Treasury Regulation Section 1.409A-1 et seq., or any other applicable guidance from the Department of Treasury, these provisions are only intended to preserve the rights and features of the “grandfathered” deferrals and are, therefore, not intended to “materially modify” any aspect of such rights and features. Provisions of this Pre-2005 Addendum should be so construed whenever necessary or appropriate. Provisions in this Pre-2005 Addendum shall only be amended in accordance with this Pre-2005 Addendum’s terms. Capitalized terms used herein but not defined herein shall have the meanings given to such terms in the Plan (as in effect prior to January 1, 2005).

SECTION 2

Definitions

2.1    “Beneficial Ownership” means beneficial ownership within the meaning of Rule 13d-3 promulgated under the Exchange Act.

2.2    “Board” or “Board of Directors” means the Board of Directors of the Company.

2.3    “Business Combination” means a reorganization, merger or consolidation or sale of Southern with another corporation or an entity treated as a corporation for United States federal income tax purposes.

2.4    “Cash Compensation” means the annual retainer fees and meeting fees payable to a Director in cash.

2.5    “Code” means the Internal Revenue Code of 1986, as amended, or any successor statute.

2.6    “Committee” means the Compensation Committee of the Board, or such other committee as may be designated by the Board to be responsible for administering the Plan and this Pre-2005 Addendum.

2.7    “Common Stock” means the common stock of Southern, including any shares into which it may be split, subdivided, or combined.

2.8    “Company” means Alabama Power Company, or any successor thereto.

2.9    “Company Change in Control” means the following:

(a)    The Consummation of an acquisition by any Person of Beneficial Ownership of 50% or more of the combined voting power of the then outstanding Voting Securities of the Company; provided, however, that for purposes of this Section 2.9, any acquisition by an Employee, or Group composed entirely of Employees, any qualified pension plan, any publicly held mutual fund or any employee benefit plan (or related trust) sponsored or maintained by Southern or any corporation Controlled by Southern shall not constitute a Change in Control;

(b)    Consummation of a reorganization, merger or consolidation of the Company (a “Company Business Combination”), in each case, unless, following such Company Business Combination, Southern Controls the corporation surviving or resulting from such Company Business Combination; or

(c)    Consummation of the sale or other disposition of all or substantially all of the assets of the Company to an entity which Southern does not Control.

2.10    “Compensation Payment Date” means the date on which compensation, including Cash Compensation, and the Stock Retainer, is payable to a Director or compensation which would otherwise be payable to a Director if an election to defer such compensation had not been made.

2.11    “Consummation” means the completion of the final act necessary to complete a transaction as a matter of law, including, but not limited to, any required approvals by the corporation’s shareholders and board of directors, the transfer of legal and beneficial title to securities or assets and the final approval of the transaction by any applicable domestic or foreign governments or agencies.

2.12    “Control” means, in the case of a corporation, Beneficial Ownership of more than 50% of the combined voting power of the corporation’s Voting Securities, or in the case of any other entity, Beneficial Ownership of more than 50% of such entity’s voting equity interests.

2.13    “Deferred Cash Trust” means the Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of The Southern Company and its Subsidiaries, as amended or amended and restated from time to time.

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2.14    “Deferred Compensation Account” means the Prime Rate Investment Account, the Phantom Stock Investment Account, the Deferred Stock Account, and/or the Stock Dividend Investment Account applicable to “grandfathered” deferrals of Cash Compensation and Stock Retainer made by Participants which are treated by the Company as not subject to Code Section 409A.

2.15    “Deferred Pension Election” means the election by a Director who had a Pension Benefit as of the Termination Date, who made a single one-time election, to credit all his Pension Benefit into (i) the Prime Rate Investment Account or (ii) thePhantom Stock Investment Account in connection with the deferral of receipt of the Director’s Pension Benefit until termination from the Board.

2.16    “Deferred Stock Account” means the bookkeeping account established under Section 5.3 of this Pre-2005 Addendum on behalf of a Director and includes shares of Common Stock credited thereto to reflect the reinvestment of dividends pursuant to Section 5.3(a)(iii) of this Pre-2005 Addendum.

2.17    “Deferred Stock Trust” means the Amended and Restated Deferred Stock Trust Agreement for Directors of The Southern Company and its Subsidiaries, as amended or amended and restated from time to time.

2.18    “Director” means a member of the Board.

2.19    “Distribution Election” means the designation by a Director of the manner of distribution of the amounts and quantities held in the Director’s Deferred Compensation Accounts upon the director’s termination from the Board pursuant to Section 6.3 of this Pre-2005 Addendum.

2.20    “Employee” means an employee of Southern or any of its subsidiaries that are “employing companies” as defined in the Southern Company Deferred Compensation Plan as amended and restated effective January 1, 2005, and as may be amended from time to time.

2.21    “Exchange Act” means the Securities Exchange Act of 1934, as amended.

2.22    “Funding Change in Control means any of the following:

(a)    The Consummation of an acquisition by any Person of Beneficial Ownership (during the 12-month period ending on the date of the most recent acquisition by such Person) of 35% or more of Southern’s Voting Securities; provided, however, that for purposes of this subsection (a), the following acquisitions of Southern’s Voting Securities shall not constitute a Funding Change in Control:

(i)    any acquisition directly from Southern;

(ii)    any acquisition by Southern;

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(iii)    any acquisition by any employee benefit plan (or related trust) sponsored or maintained by Southern or any corporation controlled by Southern;

(iv)    any acquisition by a qualified pension plan or publicly held mutual fund;

(v)    any acquisition by an employee of Southern or its subsidiary or affiliate, or Group composed exclusively of such employees; or

(vi)    any Business Combination which would not otherwise constitute a Funding Change in Control because of the application of clauses (i), (ii) and (iii) of this Section 2.22(a);

(b)    The date a majority of members of the Southern Board of Directors is replaced during any 12-month period by directors whose appointment or election is not endorsed by a majority of the members of the Southern Board of Directors before the date of the appointment or election;

(c)    The Consummation of a Business Combination, unless, following such Business Combination, all of the following three conditions are met:

(i)    all or substantially all of the individuals and entities who held Beneficial Ownership, respectively, of Southern’s Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, 50% or more of the combined voting power of the Voting Securities of the corporation surviving or resulting from such Business Combination, (including, without limitation, a corporation which as a result of such transaction holds Beneficial Ownership of all or substantially all of Southern’s Voting Securities or all or substantially all of Southern’s assets) (such surviving or resulting corporation to be referred to as “Surviving Company”), in substantially the same proportions as their ownership, immediately prior to such Business Combination, of Southern’s Voting Securities;

(ii)    no Person (excluding any corporation resulting from such Business Combination, any qualified pension plan, publicly held mutual fund, Group composed exclusively of employees or employee benefit plan (or related trust) of Southern, its subsidiaries or Surviving Company) holds Beneficial Ownership, directly or indirectly, of 35% or more of the combined voting power of the then outstanding Voting Securities of Surviving Company except to the extent that such ownership existed prior to the Business Combination; and

(iii)    the majority of the members of the board of directors of Surviving Company during the 12-month period following the Business Combination were members of the Southern Board of Directors at

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the earlier of the date of execution of the initial agreement, or of the action of the Southern Board of Directors, providing for such Business Combination or such members of the board of directors of the Surviving Company are directors whose appointment or election was endorsed by a majority of the members of such Southern Board of Directors.

(d)    The Consummation of an acquisition by any Person of Beneficial Ownership (during the 12-month period ending on the date of the most recent acquisition by such Person) of 50% or more of the combined voting power of the then outstanding Voting Securities of the Company; provided, however, that for purposes of this Section 2.22(d), any acquisition by an employee of Southern or its subsidiary or affiliate, or Group composed entirely of such employees, any qualified pension plan, publicly held mutual fund or any employee benefit plan (or related trust) sponsored or maintained by Southern or any corporation Controlled by Southern shall not constitute a Funding Change in Control;

(e)    The Consummation of a reorganization, merger or consolidation of the Company with another corporation (a “Funding Subsidiary Business Combination”), in each case, unless, following such Funding Subsidiary Business Combination, Southern Controls the corporation surviving or resulting from such Funding Subsidiary Business Combination, or

(f)    The Consummation of the sale or other disposition of all or substantially all of the assets of the Company to an entity that Southern does not Control; provided, however, that for purposes of this subsection (f) the following sales or dispositions otherwise described herein shall not constitute a Funding Change in Control:

(i)    the sale or other disposition of all or substantially all of the assets of the Company to Southern or to a shareholder of Southern in exchange for or with respect to such shareholder’s stock of Southern;

(ii)    the sale of other disposition of all or substantially all of the assets of the Company to a Person that owns, directly or indirectly, 50% or more of the total value or voting power of the outstanding stock of Southern; or

(iii)    the sale or other disposition of all or substantially all of the assets of the Company to an entity Controlled by shareholders of Southern that hold, directly or indirectly, 50% or more of the total value or voting power of all of the outstanding stock of Southern.

For purposes of this Section 2.22(f) “all or substantially all of the assets” means at least 80% of the gross value of the assets of the entity immediately before the acquisition.

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2.23    “Funding Event” shall mean the occurrence of any of the following events as administratively determined by the Southern Committee:

(a)    Southern or the Company has entered into a written agreement, such as, but not limited to, a letter of intent, which, if Consummated, would result in a Funding Change in Control;

(b)    Southern, the Company or any other Person publicly announces an intention to take or to consider taking actions which, if Consummated, would result in a Funding Change in Control under circumstances where the Consummation of the announced action or intended action is legally and financially possible;

(c)    Any Person acquires Beneficial Ownership of fifteen percent (15%) or more of the Common Stock; or

(d)    The Southern Board of Directors or the board of directors of the Company elects to otherwise fund the Deferred Cash Trust and Deferred Stock Trust in accordance with the provisions of Section 7 of this Pre-2005 Addendum.

2.24    “Funding Subsidiary Business Combination” shall have the meaning set forth in Section 2.22(e) hereof.

2.25    “Group” has the meaning set forth in Section 14(d) of the Exchange Act.

2.26    “Incumbent Board” means those individuals who constitute the Southern board of directors as of January 1, 2008, plus any individual who shall become a director subsequent to such date whose election or nomination for election by Southern’s shareholders was approved by a vote of at least 75% of the directors then comprising the Incumbent Board. Notwithstanding the foregoing, no individual who shall become a director of the Southern board of directors subsequent to January 1, 2008, whose initial assumption of office occurs as a result of an actual or threatened election contest (within the meaning of Rule 14a-11 of the regulations promulgated under the Exchange Act) with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Southern board of directors shall be a member of the Incumbent Board.

2.27    “Market Value” means the average of the high and low prices of the Common Stock, as published in the Wall Street Journal in its report of New York Stock Exchange composite transactions, on the date such Market Value is to be determined, as specified herein (or the average of the high and low sale prices on the trading day immediately preceding such date if the Common Stock is not traded on the New York Stock Exchange on such date).

2.28    “Participant” means a Director or former Director who has an unpaid Deferred Compensation Account balance under this Pre-2005 Addendum.

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2.29    “Participating Companies” means those companies that are affiliated with Southern whose boards of directors have authorized the establishment of trust(s) for the funding of their respective directors’ Deferred Compensation Accounts under their respective Deferred Compensation Plans for Directors, including the Plan as maintained by the Company for its Directors.

2.30    “Pension Benefit” means the U.S. dollar amount of the actuarially-determined present value of benefits based on a Director’s expected service at the required retirement date under The Southern Company Outside Directors Pension Plan, as calculated as of the Termination Date, plus accrued earnings on such amount calculated as if invested at the Prime Interest Rate from the Termination Date, until such amount is invested in Deferred Compensation Accounts.

2.31    “Pension Benefit Investment Date” means the date to be determined by the Committee, as of which the Director’s Pension Benefit will be credited to a Deferred Compensation Account in accordance with the director’s Deferred Pension Election.

2.32    “Person” means any individual, entity or group within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act.

2.33    “Phantom Stock Investment Account” means the bookkeeping account established pursuant to Section 5.2 of this Pre-2005 Addendum in which a Director may elect to defer Cash Compensation or make investments, and includes amounts credited thereto to reflect the reinvestment of dividends.

2.34    “Plan” means the Deferred Compensation Plan for Outside Directors of Alabama Power Company as from time to time in effect.

2.35    “Plan Period” means the period designated in Section 4.

2.36    “Preliminary Change in Control” means the occurrence of any of the following as determined by the Southern Committee:

(a)    Southern or the Company has entered into a written agreement, such as, but not limited to, a letter of intent, which, if Consummated, would result in a Southern Change in Control or a Company Change in Control, as the case may be;

(b)    Southern, the Company or any Person publicly announces an intention to take or to consider taking actions which, if Consummated, would result in a Southern Change in Control or a Company Change in Control under circumstances where the Consummation of the announced action or intended action is legally and financially possible;

(c)    Any Person becomes the Beneficial Owner of fifteen percent (15%) or more of the Common Stock; or

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(d)    The Southern board of directors or the board of directors of the Company has declared that a Preliminary Change in Control has occurred.

2.37    “Prime Interest Rate” means the prime rate of interest as published in the Wall Street Journal, or its successor on the first day of the applicable calendar quarter.

2.38    “Prime Rate Investment Account” means the bookkeeping account established pursuant to Section 5.1 of this Pre-2005 Addendum in which a Director may elect to defer CashCompensation or make investments, the investment return on which is computed at the Prime Interest Rate.

2.39    “Southern” means The Southern Company.

2.40    “Southern Change in Control” means any of the following:

(a)    The Consummation of an acquisition by any Person of Beneficial Ownership of 20% or more of Southern’s Voting Securities; provided, however, that for purposes of this subsection (a), the following acquisitions of Southern’s Voting Securities shall not constitute a Change in Control:

(i)    any acquisition directly from Southern,

(ii)    any acquisition by Southern,

(iii)    any acquisition by any employee benefit plan (or related trust) sponsored or maintained by Southern or any corporation controlled by Southern,

(iv)    any acquisition by a qualified pension plan or publicly held mutual fund,

(v)    any acquisition by an Employee or Group composed exclusively of Employees, or

(vi)    any Business Combination which would not otherwise constitute a Change in Control because of the application of clauses (i), (ii) and (iii) of Section 2.40(a) of this Pre-2005 Addendum;

(b)    A change in the composition of Southern’s board of directors whereby individuals who constitute the Incumbent Board cease for any reason to constitute at least a majority of Southern’s board of directors; or

(c)    Consummation of a Business Combination, unless, following such Business Combination, all of the following three conditions are met:

(i)    all or substantially all of the individuals and entities who held Beneficial Ownership, respectively, of Southern’s Voting Securities immediately prior to such Business Combination beneficially own,

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directly or indirectly, 65% or more of the combined voting power of the Voting Securities of the corporation surviving or resulting from such Business Combination, (including, without limitation, a corporation which as a result of such transaction holds Beneficial Ownership of all or substantially all of Southern’s Voting Securities or all or substantially all of Southern’s assets) (such surviving or resulting corporation to be referred to as “Surviving Company”), in substantially the same proportions as their ownership, immediately prior to such Business Combination, of Southern’s Voting Securities;

(ii)    no Person (excluding any corporation resulting from such Business Combination, any qualified pension plan, publicly held mutual fund, Group composed exclusively of employees or employee benefit plan (or related trust) of Southern, its subsidiaries, or Surviving Company) holds Beneficial Ownership, directly or indirectly, of 20% or more of the combined voting power of the then outstanding Voting Securities of Surviving Company except to the extent that such ownership existed prior to the Business Combination; and

(iii)    at least a majority of the members of the Board were members of the Incumbent Board at the earlier of the date of execution of the initial agreement, or of the action of the Southern board of directors, providing for such Business Combination.

2.41    “Southern Committee” means a committee comprised of the Chairman of the Southern Board, the Chief Financial Officer of Southern, and the General Counsel of Southern.

2.42    “Stock Dividend Investment Account” means the bookkeeping account(s) established pursuant to Section 5.4 of this Pre-2005 Addendum on behalf of a Director that is credited with shares of stock, other than Common Stock, paid as a dividend on shares of Common Stock.

2.43    “Stock Retainer” means the annual Board retainer fee that is paid to the Director in the form of Common Stock.

2.44    “Termination Date” means January 1, 1997, the date as of which The Southern Company Outside Directors Pension Plan was effectively terminated.

2.45    “Trust Administrator” means the individual or committee that is established in the Deferred Stock Trust and the Deferred Cash Trust, to administer such trusts on behalf of the Participating Companies.

2.46    “Voting Securities” means the outstanding voting securities of a corporation entitling the holder thereof to vote generally in the election of such corporation’s directors.

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Where the context requires, words in the masculine gender shall include the feminine gender, words in the singular shall include the plural, and words in the plural shall include the singular.

SECTION 3

Eligibility

For so long as a Director has a Deferred Compensation Account balance governed by this Pre-2005 Addendum, he or she shall be a Participant in the Plan for purposes of this Pre-2005 Addendum, and such Deferred Compensation Account balance shall be maintained and administered solely in accordance with the terms of this Pre-2005 Addendum.

SECTION 4

Plan Periods

No new deferral elections may be made which are subject to this Pre-2005 Addendum.

SECTION 5

Accounts

5.1    Prime Rate Investment Account

A Prime Rate Investment Account shall be established for each Director electing deferral of Cash Compensation for investment at the Prime Interest Rate. The amount directed by the Director to such account shall be credited to it as of the Pension Benefit Investment Date or Compensation Payment Date, as applicable, and credited thereafter with interest computed using the Prime Interest Rate. Interest shall be computed from the date such compensation is credited to the account and compounded quarterly at the end of each calendar quarter. The Prime Interest Rate in effect on the first day of a calendar quarter shall be deemed the Prime Interest Rate in effect for that entire quarter. Interest shall accrue and compound on any balance until the amount credited to the account is fully distributed.

5.2    Phantom Stock Investment Account

The Phantom Stock Investment Account established for each Director electing deferral of Cash Compensation for investment at the Common Stock investment rate shall be credited with the number of shares (including fractional shares rounded to the nearest ten-thousandth) of Common Stock which could have been purchased on the Pension Benefit Investment Date or the Compensation Payment Date, as applicable, as determined by dividing the applicable compensation by the Market Value on such date. On the date of the payment of dividends on the Common Stock, the Director’s Phantom Stock Investment Account shall be credited with additional shares (including fractional shares rounded to the nearest ten-thousandth) of Common Stock, as follows:

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(a)    In the case of cash dividends, such additional shares as would have been purchased as of the Common Stock dividend record date as if the credited shares had been outstanding on such date and dividends reinvested thereon under the Southern Company Southern Investment Plan;

(b)    In the case of dividends payable in property other than cash or Common Stock, such additional shares as could be purchased at the Market Value as of the date of payment with the fair market value of the property which would have been payable if the credited shares had been outstanding; and

(c)    In the case of dividends payable in Common Stock, such additional shares as would have been payable on the credited shares as if they had been outstanding.

5.3    Deferred Stock Account

(a)    A Director’s Deferred Stock Account will be credited:

(i)    with the number of shares of Common Stock (rounded to the nearest ten thousandth of a share) determined by dividing the sum of the amount of Cash Compensation subject to deferral or investment in the Deferred Stock Account and the Stock Retainer (that is denominated in dollars), by the average price paid by the Trust Administrator of the Deferred Stock Trust for shares of Common Stock with respect to the Pension Benefit Investment Date or the Compensation Payment Date, as applicable, as reported by the Trust Administrator, or if the Trust Administrator shall not at such time purchase any shares of Common Stock, by the Market Value on such date;

(ii)    as of the date on which Stock Retainer (that is denominated in shares of Common Stock) is paid, with the number of shares of Common Stock payable to the Director as his Stock Retainer; and

(iii)    as of each date on which dividends are paid on the Common Stock, with the number of shares of Common Stock (rounded to the nearest ten thousandth of a share) determined by multiplying the number of shares of Common Stock credited in the Director’s Deferred Stock Account on the dividend record date, by the dividend rate per share of Common Stock, and dividing the product by the price per share of Common Stock attributable to the reinvestment of dividends on the shares of Common Stock held in the Deferred Stock Trust on the applicable dividend payment date or, if the Trust Administrator of the Deferred Stock Trust has not reinvested in shares of Common Stock on the applicable dividend reinvestment date, the product shall be divided by the Market Value on the dividend payment date.

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(b)    If Southern enters into transactions involving stock splits, stock dividends, reverse splits or any other recapitalization transactions, the number of shares of Common Stock credited to a Director’s Deferred Stock Account will be adjusted (rounded to the nearest ten thousandth of a share) so that the Director’s Deferred Stock Account reflects the same equity percentage interest in Southern after the recapitalization as was the case before such transaction.

(c)    If at least a majority of Southern’s stock is sold or exchanged by its shareholders pursuant to an integrated plan for cash or property (including stock of another corporation) or if substantially all of the assets of Southern are disposed of and, as a consequence thereof, cash or property is distributed to Southern’s shareholders, each Director’s Deferred Stock Account will, to the extent not already so credited under this Section 5.3, be (i) credited with the amount of cash or property receivable by a Southern shareholder directly holding the same number of shares of Common Stock as is credited to such Director’s Deferred Stock Account and (ii) debited by that number of shares of Common Stock surrendered by such equivalent Southern shareholder.

(d)    Except as expressly provided in this Pre-2005 Addendum, a Director shall have no rights as a stockholder of Southern with respect to the Director’s Deferred Stock Account unless and until such Common Stock is paid to the Director.

5.4    Stock Dividend Investment Account

(a)    A Director’s Stock Dividend Investment Account will be credited as of the date on which a dividend is paid in stock other than Common Stock to the Company’s common stockholders with the number of shares of such other corporation’s stock receivable by such Southern common stockholder. Thereafter, if dividends are paid on the above-described non-Common Stock dividends, such subsequent dividends shall be credited in the same manner as described in Section 5.3(a)(iii) of this Pre-2005 Addendum.

(b)    Except as expressly provided herein, a Director shall have no rights as a stockholder of any corporation the common stock of which is credited to the Director’s Stock Dividend Investment Account.

SECTION 6

Distributions

6.1    Upon the termination of a Director’s membership on the Board the amount credited to a Director’s Deferred Compensation Accounts will be paid to the Director or his beneficiary, as applicable, in the following manner:

(a)    the amount credited to a Director’s Prime Rate Investment Account and Phantom Stock Investment Account shall be paid in cash;

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(b)    the amount credited to a Director’s Deferred Stock Account shall, except as otherwise provided in Sections 5.3 and 6.6 of this Pre-2005 Addendum, or to the extent the Company is otherwise, in the reasonable judgment of the Committee, precluded from doing so, be paid in shares of Common Stock (with any fractional share interest therein paid in cash to the extent of the then Market Value thereof); and

(c)    the amount credited to a Stock Dividend Investment Account shall, except as otherwise provided in Section 6.6 of this Pre-2005 Addendum, be paid from the assets in the Deferred Stock Trust in shares of the applicable corporation, however if there is not a sufficient number of shares held in the Trust, the remainder shall be paid in cash based upon the Market Value of such shares held in the Trust, the remainder shall be paid in cash based upon the Market Value of such shares.

Such payments shall be from the general assets of the Company (including the Deferred Cash Trust and the Deferred Stock Trust) in accordance with this Section 6.

6.2    Unless other arrangements are specified by the Committee on a uniform and nondiscriminatory basis, deferred amounts shall be paid in the form of (i) a lump sum payment, or (ii) in approximately equal annual or quarterly installments, as elected by the Director pursuant to the provisions of Section 6.3 of this Pre-2005 Addendum, provided, however, that payments shall be made only in a single lump sum if payment commences due to termination for cause. Such payments shall be made (or shall commence) as soon as practicable following the termination of Board membership or, if so elected in the Distribution Election, up to twenty-four (24) months following such termination.

If at the time of a Director’s termination of Board membership, his Deferred Compensation Accounts have a cumulative balance of less than $75,000, the balance of the Deferred Compensation Accounts may be distributed in a single lump sum payment or in three or fewer approximately equal annual installments, in the discretion of the Committee if the Director has elected a longer installment payout period.

In the event a Director elected to receive the balance of his Deferred Compensation Accounts in a lump sum, distribution shall be made on the first day of the month selected by the Director on his Distribution Election, or as soon as reasonably possible thereafter. If the Director elected to receive annual or quarterly installments, the first payment shall be made on the first day of the month selected by a Director, or as soon as reasonably possible thereafter, and shall be equal to the balance in the Director’s Deferred Compensation Accounts on such date divided by the number of annual or quarterly installment payments. Each subsequent annual or quarterly payment shall be an amount equal to the balance in the Director’s Deferred Compensation Accounts on the date of payment divided by the number of remaining annual or quarterly payments.

Notwithstanding a Director’s election to receive his Deferred Compensation Account balance in installments, the Committee, upon request of the Director and in its sole discretion, may accelerate the payment of any such installments for cause, such as financial hardship or

13

financial emergency. The Market Value of any shares of Common Stock credited to a Director’s Phantom Stock Investment Account shall be determined as of the date of any lump sum or installment distribution as determined by the Committee.

Upon the death of a Director, or a former Director prior to the payment of all amounts credited to the Director’s Deferred Compensation Accounts, the unpaid balance shall be paid in a lump sum to the designated beneficiary of such Director or former Director within sixty (60) days of the date of death (or as soon as reasonably possible thereafter). In the event a beneficiary designation has not been made, or the designated beneficiary is deceased or cannot be located, payment shall be made to the estate of the Director or former Director. The Market Value of any shares of Common Stock credited to a Director’s Phantom Stock Investment Account shall be determined as of the date of any lump sum distribution.

6.3    Distribution Election

(a)    Except as set forth in Section 6.3 (b) of this Pre-2005 Addendum, prior to the initial establishment of a Deferred Compensation Account for a Director, the Director must elect, in writing, that upon termination from the Board of Directors the values and quantities held in the Directors Deferred Compensation Accounts be distributed to the Director, pursuant to the provisions of this Section 6, in a lump sum or in a series of annual or quarterly installments not to exceed fifteen (15) years. Distributions from the Prime Rate Investment Account and Phantom Stock Investment Account can be in a lump sum or in annual or quarterly installments. Distributions from the Deferred Stock Account and Stock Dividend Investment Account can be lump sum or annual installments. The time for the commencement of distribution shall not be later than the first day of the month or quarter coinciding with or next following the second anniversary of termination of Board membership.

(b)    Any Director who made a Deferred Pension Election made a Distribution Election at the time the Deferred Pension Election was made attributable to the Pension Benefit and any accumulated investment return.

(c)    Distribution Elections made under Sections 6.3(a) and (b) above are irrevocable except that a Director may amend any of the Distribution Elections then in effect while the Director is still a director of the Company as required under Section 6.6 of this Pre-2005 Addendum provided the amended election is made not later than the 366th day prior to the Director’s termination of Board membership. In addition, any amendment to a Distribution Election must be made on a form prescribed by the Committee and delivered to the Secretary or Assistant Secretary of the Company.

6.4    Beneficiary Designation

A Director or former Director may designate a beneficiary to receive distributions under this Pre-2005 Addendum in accordance with the provisions of this Section 6 upon the death of the

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director. The beneficiary designation may be changed by a Director or former Director at any time, and without the consent of the prior beneficiary.

6.5    Form of Election

All elections pursuant to the provisions of this Section 6 of the Pre-2005 Addendum shall be made in writing to the Secretary or Assistant Secretary of the Company on a form or forms available upon request of the Secretary or Assistant Secretary.

6.6    Distribution Limitations

    Notwithstanding any other provision of this Pre-2005 Addendum: (i) elections under this Pre-2005 Addendum may only be made by Directors while they are directors of the Company (with the exception of the designation of beneficiaries), and (ii) distributions otherwise payable to a Director in the form of Common Stock or other corporation’s stock shall be delayed and/or instead paid in cash in an amount equal to the fair market value thereof if such payment in Common Stock would violate any federal or State securities laws (including Section 16(b) of the Securities Exchange Act of 1934, as amended) and/or rules and regulations promulgated thereunder.

SECTION 7

Change in Control and Other Special Provisions

7.1    Notwithstanding any other terms of this Pre-2005 Addendum to the contrary, following a Funding Event or a Preliminary Change in Control as the case may be, the provisions of this Section 7 shall apply to the payment of benefits under this Pre-2005 Addendum with respect to any Director who is a Participant on such date.

7.2    The Deferred Cash Trust and the Deferred Stock Trust (collectively “Trusts”) have been established to hold assets of the Participating Companies under certain circumstances as a reserve for the discharge of the Company’s obligations under the Pre-2005 Addendum. In the event of a Funding Event involving a Funding Change in Control of Southern or the Company, the Company shall be obligated to immediately contribute such amounts to the Trusts as may be necessary to fully fund all benefits payable under this Pre-2005 Addendum in accordance with the procedures set forth in Section 7.3 hereof. All assets held in the Trusts remain subject only to the claims of Southern’s and the Participating Companies’ general creditors whose claims against Southern and the Participating Companies are not satisfied because of Southern’s or the Participating Companies’ bankruptcy or insolvency (as those terms were defined in the Trusts as in effect prior to January 1, 2005). No Participant has any preferred claim on, or beneficial ownership interest in, any assets of the Trusts before the assets are paid to the Participant and all rights created under the Trusts, as under this Pre-2005 Addendum, are unsecured contractual claims of the Participant against the Company.

7.3    As soon as practicable following a Funding Event, the Company shall contribute an amount based upon the funding strategy adopted by the Trust Administrator with

15

the assistance of an appointed actuary necessary to fulfill the Company’s obligations pursuant to this Section 7. In the event of a dispute over such actuary’s determination, the Company and any complaining Participant(s) shall refer such dispute to an independent, third party actuarial consultant, chosen by the Company and such Participant. If the Company and the Participant cannot agree on an independent, third party actuarial consultant, the actuarial consultant shall be chosen by lot from an equal number of actuaries submitted by the Company and the applicable Trust Administrator. Any such referral shall only occur once in total and the determination by the third-party actuarial consultant shall be final and binding upon both parties. The Company shall be responsible for all of the fees and expenses of the independent actuarial consultant.

7.4    In the event of a Southern Change in Control or a Company Change in Control, notwithstanding anything to the contrary in this Pre-2005 Addendum, upon termination as a Director, that amount in the Deferred Compensation Plan Account(s) of a Participant who was a Director determined as of such Change in Control shall be paid out in a lump sum if such Participant makes an election pursuant to procedures established by the Trust Administrator, in its sole and absolute discretion. If no such election is made, the Director shall receive payment of his Accounts solely in accordance with Section 6 of this Pre-2005 Addendum.

SECTION 8

General Provisions

8.1    In the event that the Company shall decide to establish an advance accrual reserve on its books against the future expense of payments from any Deferred Compensation Accounts, such reserve shall not under any circumstances be deemed to be an asset of this Pre-2005 Addendum but, at all times, shall remain a part of the general assets of the Company, subject to claims of the Company’s creditors.

8.2    A person entitled to any amount under this Pre-2005 Addendum shall be a general unsecured creditor of the Company with respect to such amount. Furthermore, a person entitled to a payment or distribution with respect to a Deferred Compensation Account shall have a claim upon the Company only to the extent of the balance in his Deferred Compensation Accounts.

8.3    The Company will pay all commissions, fees, and expenses that may be incurred in operating the Pre-2005 Addendum.

8.4    The Company will pay its prorated share of all commissions, fees, and expenses that may be incurred in operating any trust(s) established under this Pre-2005 Addendum (including the Deferred Stock Trust and the Deferred Cash Trust).

8.5    Notwithstanding any other provision of this Pre-2005 Addendum:

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(a)    elections under this Pre-2005 Addendum may only be made by Directors while they are directors of the Company; (with the exception of the designation of beneficiaries); and

(b)    distributions otherwise payable to a Director in the form of Common Stock or other corporation’s stock shall be delayed and/or instead paid in cash in an amount equal to the fair market value thereof if such payment in stock would violate any federal or State securities laws (including Section 16(b) of the Securities Exchange Act of 1934, as amended) and/or rules and regulations promulgated thereunder.

8.6    Directors, their legal representatives and their beneficiaries shall have no right to anticipate, alienate, sell, assign, transfer, pledge or encumber their interests in the Pre-2005 Addendum, nor shall such interests be subject to attachment, garnishment, levy or execution by or on behalf of creditors of the Directors or of their beneficiaries.

SECTION 9

Administration

9.1    General Provisions

The Committee shall administer the Pre-2005 Addendum in accordance with its terms and shall have all powers necessary to carry out the provisions of the Pre-2005 Addendum as may be more particularly set forth herein. The Committee shall interpret the Pre-2005 Addendum and shall determine all questions arising in the administration, interpretation, and application of the Pre-2005 Addendum. Any such determination by the Committee shall be conclusive and binding on all persons. The Committee shall be the Pre-2005 Addendum’s agent for service of process.

The Committee may delegate to such officers, employees, or departments of the Company or Southern, such authority, duties, and responsibilities of the Committee as it, in its sole discretion, considers necessary or appropriate for the proper and efficient operation of the Pre-2005 Addendum, including, without limitation, (i) interpretation of the Pre-2005 Addendum, (ii) approval and payment of claims, and (iii) establishment of procedures for administration of the Pre-2005 Addendum.

9.2    Claims Process

If a claim for benefits under the Pre-2005 Addendum is denied, in whole or in part, the Committee will provide a written notice of the denial within a reasonable period of time, but not later than 90 days after the claim is received. If special circumstances require more time to process the claim, the Committee will issue a written explanation of the special circumstances prior to the end of the 90 day period and a decision will be made as soon as possible, but not later than 180 days after the claim is received.

The written notice of claim denial will include:

17

•    Specific reasons why the claim was denied;

•    Specific references to applicable provisions of the Pre-2005 Addendum document or other relevant records or papers on which the denial is based, and information about where a Participant or his or her beneficiary may see them;

•    A description of any additional material or information needed to process the claim, and an explanation of why such material or information is necessary; and

•    An explanation of the claims review procedure, including the time limits applicable to such procedure, as well as a statement notifying the Participant or his or her beneficiary of their right to file suit if the claim for benefits is denied, in whole or in part, on review.

Upon request, a Participant or his or her beneficiary will be provided without charge, reasonable access to, and copies of, all non-confidential documents that are relevant to any denial of benefits. A claimant has 60 days from the day he or she receives the original denial to request a review. Such request must be made in writing and sent to the Committee. The request should state the reasons why the claim should be reviewed and may also include evidence or documentation to support the claimant’s position.

The Committee will reconsider the claimant’s claim, taking into account all evidence, documentation, and other information related to the claim and submitted on the claimant’s behalf, regardless of whether such information was submitted or considered in the initial denial of the claim. The Committee will make a decision within 60 days. If special circumstances require more time for this process, the claimant will receive written explanation of the special circumstances prior to the end of the initial 60 day period and a decision will be sent as soon as possible, but not later than 120 days after the Committee receives the request.

No legal action to recover benefits or enforce or clarify rights under the Pre-2005 Addendum can be commenced until the Participant or his or her beneficiary has first exhausted the claims and review procedures provided under the Pre-2005 Addendum.

SECTION 10

Amendment and Termination

10.1    Amendment of the Pre-2005 Addendum

This Pre-2005 Addendum may be amended or terminated at any time by the Board in its sole discretion at any time and from time to time by written resolution expressly modifying this Pre-2005 Addendum; provided, however, that no such amendment or termination shall impair any rights to any benefits that have accrued hereunder, and further provided that no such amendment or termination of the Pre-2005 Addendum shall be effective if such amendment or termination is made or is effective within a period that is (a) six (6) months before, or at any time after, a Preliminary Change in Control and (b) prior to (x) the earlier of such time as the Southern Committee shall have determined that the event that gave rise to such Preliminary Change in

18

Control shall not be Consummated or (y) two years following the respective Change in Control, unless such amendment or termination during such period has the effect of increasing benefits to Participants under the Pre-2005 Addendum, is determined by the Board of Directors to be immaterial, or applies solely to Directors who, in the case of a Company Change in Control, are not Directors on the date of the respective Preliminary Change in Control, or, in the case of a Southern Change in Control, are not Directors on the date of the respective Southern Change in Control. Following a Change in Control, nothing in this Section 10.1 shall prevent the Board of Directors from amending or terminating the Pre-2005 Addendum as to any subsequent Change in Control provided that no such amendment or termination shall impair any rights or reduce any benefits previously accrued under the Pre-2005 Addendum as a result of a previous Change in Control. It is the Company’s intent that any modification to this Pre-2005 Addendum shall not constitute nor shall it be interpreted to be a “material modification” of any right or feature of this Pre-2005 Addendum as such term is defined under Code Section 409A, Internal Revenue Service Notice 2005-1, Treasury Regulation Section 1.409A-1 et seq., or any subsequent guidance promulgated by the Treasury Department, unless the Pre-2005 Addendum is amended contemporaneously to comply with Code Section 409A.

10.2    Governing Law

This Pre-2005 Addendum shall be construed in accordance with and governed by the laws of the state in which the Company is incorporated to the extent not inconsistent with the requirements of the Employee Retirement Income Security Act of 1974, as amended, and Code Section 409A.

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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:  July 28, 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, Andrew W. Evans, certify that:

1.I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: July 28, 2021

/s/Andrew W. Evans

Andrew W. Evans

Executive Vice President and Chief Financial Officer

EX-31.B1

Exhibit 31(b)1

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Mark A. Crosswhite, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Alabama Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  July 28, 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:  July 28, 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:  July 28, 2021

/s/Christopher C. Womack

Christopher C. Womack

Chairman and Chief Executive Officer

EX-31.C2

Exhibit 31(c)2

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Daniel S. Tucker, 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:  July 28, 2021

/s/Daniel S. Tucker

Daniel S. Tucker

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:  July 28, 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:  July 28, 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:   July 28, 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:  July 28, 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:  July 28, 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:  July 28, 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 June 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 June 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 June 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/Andrew W. Evans

Andrew W. Evans

Executive Vice President and
Chief Financial Officer

July 28, 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 June 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 June 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 June 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

July 28, 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 June 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 June 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 Annual Report on Form 10-Q of Georgia Power Company for the quarter ended June 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 and Chief Executive Officer

/s/Daniel S. Tucker

Daniel S. Tucker

Executive Vice President, Chief Financial Officer and Treasurer

July 28, 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 June 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 June 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 June 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

July 28, 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 June 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 June 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 June 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

July 28, 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 June 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 June 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 June 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

July 28, 2021

XML

Cover Page	6 Months Ended
	Jun. 30, 2021 shares
Document Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 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)	1,058,825,814
Entity Central Index Key	0000092122
Amendment Flag	false
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q2
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
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		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Operating Revenues:
Operating revenues	$ 5,198	$ 4,620	$ 11,108	$ 9,638
Operating Expenses:
Total cost of sales	231	144	814	583
Other operations and maintenance	1,438	1,203	2,810	2,498
Depreciation and amortization	891	873	1,762	1,730
Taxes other than income taxes	313	298	657	629
Estimated loss on Plant Vogtle Units 3 and 4	460	149	508	149
(Gain) loss on dispositions, net	(11)	0	(54)	(39)
Total operating expenses	4,490	3,562	8,802	7,317
Operating Income	708	1,058	2,306	2,321
Other Income and (Expense):
Allowance for equity funds used during construction	45	35	90	68
Earnings (loss) from equity method investments	(40)	30	5	72
Interest expense, net of amounts capitalized	(450)	(444)	(901)	(900)
Impairment of leveraged leases	(7)	(154)	(7)	(154)
Other income (expense), net	108	101	167	204
Total other income and (expense)	(344)	(432)	(646)	(710)
Earnings (Loss) Before Income Taxes	364	626	1,660	1,611
Income taxes (benefit)	(12)	5	178	150
Consolidated Net Income	376	621	1,482	1,461
Dividends on preferred stock of subsidiaries	4	4	7	7
Net income (loss) attributable to noncontrolling interests	0	5	(33)	(26)
Net Income	$ 372	$ 612	$ 1,508	$ 1,480
Earnings per share -
Basic (in dollars per share)	$ 0.35	$ 0.58	$ 1.42	$ 1.40
Diluted (in dollars per share)	$ 0.35	$ 0.58	$ 1.41	$ 1.39
Average number of shares of common stock outstanding (in millions)
Basic (in shares)	1,061	1,058	1,060	1,057
Diluted (in shares)	1,067	1,063	1,066	1,065
Retail electric revenues
Operating Revenues:
Operating revenues	$ 3,599	$ 3,182	$ 6,941	$ 6,260
Wholesale electric revenues
Operating Revenues:
Operating revenues	546	472	1,091	889
Other electric revenues
Operating Revenues:
Operating revenues	175	168	346	320
Natural gas
Operating Revenues:
Operating revenues	677	636	2,371	1,885
Operating Expenses:
Total cost of sales	231	144	814	583
Other
Operating Revenues:
Operating revenues	201	162	359	284
Operating Expenses:
Total cost of sales	103	74	185	129
Fuel
Operating Expenses:
Total cost of sales	848	621	1,696	1,257
Purchased power
Operating Expenses:
Total cost of sales	217	200	424	381
Alternative revenue programs
Operating Revenues:
Operating revenues	2	(2)	4	7
ALABAMA POWER CO
Operating Revenues:
Operating revenues	1,556	1,365	3,115	2,716
Operating Expenses:
Other operations and maintenance	413	342	775	690
Depreciation and amortization	214	202	425	402
Taxes other than income taxes	101	102	203	208
Total operating expenses	1,078	924	2,123	1,853
Operating Income	478	441	992	863
Other Income and (Expense):
Allowance for equity funds used during construction	12	11	24	22
Interest expense, net of amounts capitalized	(84)	(83)	(168)	(171)
Other income (expense), net	33	26	62	48
Total other income and (expense)	(39)	(46)	(82)	(101)
Earnings (Loss) Before Income Taxes	439	395	910	762
Income taxes (benefit)	104	93	213	177
Consolidated Net Income	335	302	697	585
Dividends on preferred stock of subsidiaries	4	4	7	7
Net Income	331	298	690	578
ALABAMA POWER CO | Retail electric revenues
Operating Revenues:
Operating revenues	1,354	1,223	2,706	2,427
ALABAMA POWER CO | Wholesale electric revenues
Operating Revenues:
Operating revenues	85	54	178	111
ALABAMA POWER CO | Wholesale revenues, affiliates
Operating Revenues:
Operating revenues	24	7	55	26
ALABAMA POWER CO | Other
Operating Revenues:
Operating revenues	93	81	176	152
ALABAMA POWER CO | Fuel
Operating Expenses:
Total cost of sales	263	199	554	415
ALABAMA POWER CO | Purchased power
Operating Expenses:
Total cost of sales	48	49	97	89
ALABAMA POWER CO | Purchased power, affiliates
Operating Expenses:
Total cost of sales	39	30	69	49
GEORGIA POWER CO
Operating Revenues:
Operating revenues	2,225	1,928	4,195	3,754
Operating Expenses:
Other operations and maintenance	542	463	1,015	928
Depreciation and amortization	342	354	680	707
Taxes other than income taxes	118	108	235	221
Estimated loss on Plant Vogtle Units 3 and 4	460	149	508	149
Total operating expenses	2,098	1,555	3,667	2,976
Operating Income	127	373	528	778
Other Income and (Expense):
Allowance for equity funds used during construction	30	20	61	40
Interest expense, net of amounts capitalized	(106)	(105)	(210)	(216)
Other income (expense), net	42	31	83	63
Total other income and (expense)	(34)	(54)	(66)	(113)
Earnings (Loss) Before Income Taxes	93	319	462	665
Income taxes (benefit)	(50)	11	(32)	27
Consolidated Net Income	143	308	494	638
GEORGIA POWER CO | Retail electric revenues
Operating Revenues:
Operating revenues	2,026	1,760	3,813	3,435
GEORGIA POWER CO | Wholesale electric revenues
Operating Revenues:
Operating revenues	36	25	80	51
GEORGIA POWER CO | Other
Operating Revenues:
Operating revenues	163	143	302	268
GEORGIA POWER CO | Fuel
Operating Expenses:
Total cost of sales	343	226	656	458
GEORGIA POWER CO | Purchased power
Operating Expenses:
Total cost of sales	144	133	288	262
GEORGIA POWER CO | Purchased power, affiliates
Operating Expenses:
Total cost of sales	149	122	285	251
MISSISSIPPI POWER CO
Operating Revenues:
Operating revenues	303	283	610	559
Operating Expenses:
Other operations and maintenance	76	67	144	142
Depreciation and amortization	44	46	91	88
Taxes other than income taxes	32	30	63	59
Total operating expenses	254	233	506	463
Operating Income	49	50	104	96
Other Income and (Expense):
Interest expense, net of amounts capitalized	(14)	(15)	(29)	(31)
Other income (expense), net	11	6	20	14
Total other income and (expense)	(3)	(9)	(9)	(17)
Earnings (Loss) Before Income Taxes	46	41	95	79
Income taxes (benefit)	8	2	12	8
Consolidated Net Income	38	39	83	71
MISSISSIPPI POWER CO | Retail electric revenues
Operating Revenues:
Operating revenues	219	199	422	398
MISSISSIPPI POWER CO | Wholesale electric revenues
Operating Revenues:
Operating revenues	54	52	117	103
MISSISSIPPI POWER CO | Wholesale revenues, affiliates
Operating Revenues:
Operating revenues	25	25	57	47
MISSISSIPPI POWER CO | Other
Operating Revenues:
Operating revenues	5	7	14	11
MISSISSIPPI POWER CO | Fuel
Operating Expenses:
Total cost of sales	91	83	192	162
MISSISSIPPI POWER CO | Purchased power
Operating Expenses:
Total cost of sales	11	7	16	12
SOUTHERN POWER CO
Operating Revenues:
Operating revenues	490	439	930	814
Operating Expenses:
Other operations and maintenance	111	77	211	156
Depreciation and amortization	132	121	251	239
Taxes other than income taxes	12	10	24	19
(Gain) loss on dispositions, net	0	0	(39)	(39)
Total operating expenses	420	328	774	616
Operating Income	70	111	156	198
Other Income and (Expense):
Interest expense, net of amounts capitalized	(37)	(38)	(75)	(77)
Other income (expense), net	1	1	8	4
Total other income and (expense)	(36)	(37)	(67)	(73)
Earnings (Loss) Before Income Taxes	34	74	89	125
Income taxes (benefit)	(2)	6	(11)	13
Consolidated Net Income	36	68	100	112
Net income (loss) attributable to noncontrolling interests	0	5	(33)	(26)
Net Income	36	63	133	138
SOUTHERN POWER CO | Wholesale electric revenues
Operating Revenues:
Operating revenues	373	343	728	629
SOUTHERN POWER CO | Wholesale revenues, affiliates
Operating Revenues:
Operating revenues	112	92	193	178
SOUTHERN POWER CO | Other
Operating Revenues:
Operating revenues	5	4	9	7
SOUTHERN POWER CO | Fuel
Operating Expenses:
Total cost of sales	140	102	281	209
SOUTHERN POWER CO | Purchased power
Operating Expenses:
Total cost of sales	25	18	46	32
SOUTHERN Co GAS
Operating Revenues:
Operating revenues	$ 677	$ 636	$ 2,371	$ 1,885
Operating Expenses:
Cost, Product and Service [Extensible Enumeration]	Natural gas	Natural gas	Natural gas	Natural gas
Other operations and maintenance	$ 233	$ 220	$ 532	$ 479
Depreciation and amortization	133	123	263	243
Taxes other than income taxes	49	47	130	118
Total operating expenses	646	534	1,739	1,423
Operating Income	31	102	632	462
Other Income and (Expense):
Earnings (loss) from equity method investments	(52)	30	(11)	72
Interest expense, net of amounts capitalized	(59)	(57)	(118)	(114)
Other income (expense), net	(14)	12	(78)	21
Total other income and (expense)	(125)	(15)	(207)	(21)
Earnings (Loss) Before Income Taxes	(94)	87	425	441
Income taxes (benefit)	(29)	16	92	95
Consolidated Net Income	(65)	71	333	346
SOUTHERN Co GAS | Natural gas
Operating Revenues:
Operating revenues	675	638	2,367	1,878
Operating Expenses:
Total cost of sales	231	144	814	583
SOUTHERN Co GAS | Alternative revenue programs
Operating Revenues:
Operating revenues	$ 2	$ (2)	$ 4	$ 7

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Condensed Consolidated Statements of Income (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Operating revenues	$ 5,198	$ 4,620	$ 11,108	$ 9,638
Alternative revenue programs
Operating revenues	2	(2)	4	7
SOUTHERN Co GAS
Operating revenues	677	636	2,371	1,885
Revenue taxes collected	23	22	77	69
SOUTHERN Co GAS | Alternative revenue programs
Operating revenues	$ 2	$ (2)	$ 4	$ 7

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Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Net income (loss)	$ 376	$ 621	$ 1,482	$ 1,461
Qualifying hedges:
Changes in fair value, net of tax	14	10	(16)	(75)
Reclassification adjustment for amounts included in net income, net of tax	(5)	(9)	50	29
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	3	3	6	3
Total other comprehensive income (loss)	12	4	40	(43)
Comprehensive Income (Loss)	388	625	1,522	1,418
Dividends on preferred stock of subsidiaries	4	4	7	7
Comprehensive income (loss) attributable to noncontrolling interests	0	5	(33)	(26)
Comprehensive Income (Loss) Attributable to Parent	384	616	1,548	1,437
ALABAMA POWER CO
Net income (loss)	335	302	697	585
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	1	1	2	2
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	1	1	2	2
Comprehensive Income (Loss)	336	303	699	587
Dividends on preferred stock of subsidiaries	4	4	7	7
GEORGIA POWER CO
Net income (loss)	143	308	494	638
Qualifying hedges:
Changes in fair value, net of tax	0	0	0	(2)
Reclassification adjustment for amounts included in net income, net of tax	1	2	3	3
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	1	2	3	1
Comprehensive Income (Loss)	144	310	497	639
MISSISSIPPI POWER CO
Net income (loss)	38	39	83	71
Qualifying hedges:
Changes in fair value, net of tax	0	0	0	(1)
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	0
Comprehensive Income (Loss)	38	39	84	71
SOUTHERN POWER CO
Net income (loss)	36	68	100	112
Qualifying hedges:
Changes in fair value, net of tax	6	11	(26)	(50)
Reclassification adjustment for amounts included in net income, net of tax	(9)	(15)	38	13
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	0	1	1	1
Total other comprehensive income (loss)	(3)	(3)	13	(36)
Comprehensive Income (Loss)	33	65	113	76
Comprehensive income (loss) attributable to noncontrolling interests	0	5	(33)	(26)
Comprehensive Income (Loss) Attributable to Parent	33	60	146	102
SOUTHERN Co GAS
Net income (loss)	(65)	71	333	346
Qualifying hedges:
Changes in fair value, net of tax	8	(1)	9	(21)
Reclassification adjustment for amounts included in net income, net of tax	0	1	3	6
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	8	0	12	(15)
Comprehensive Income (Loss)	$ (57)	$ 71	$ 345	$ 331

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Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Qualifying hedges:
Changes in fair value, tax	$ 5	$ 4	$ (5)	$ (26)
Reclassification adjustment for amounts included in net income, tax	(1)	(3)	17	10
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, tax	2	1	3	2
ALABAMA POWER CO
Qualifying hedges:
Reclassification adjustment for amounts included in net income, tax	0	0	1	1
GEORGIA POWER CO
Qualifying hedges:
Changes in fair value, tax	0	0	0	(1)
Reclassification adjustment for amounts included in net income, tax	1	1	1	1
MISSISSIPPI POWER CO
Qualifying hedges:
Changes in fair value, tax	0	0	0	0
Reclassification adjustment for amounts included in net income, tax	0	0	0	0
SOUTHERN POWER CO
Qualifying hedges:
Changes in fair value, tax	2	4	(8)	(17)
Reclassification adjustment for amounts included in net income, tax	(3)	(5)	13	5
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, tax	1	0	1	0
SOUTHERN Co GAS
Qualifying hedges:
Changes in fair value, tax	3	(1)	3	(8)
Reclassification adjustment for amounts included in net income, tax	$ 0	$ 0	$ 1	$ 2

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Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Operating Activities:
Net income	$ 1,482	$ 1,461
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	1,949	1,916
Deferred income taxes	(101)	(218)
Utilization of federal investment tax credits	224	0
Allowance for equity funds used during construction	(90)	(68)
Mark-to-market adjustments	136	36
Pension, postretirement, and other employee benefits	(115)	(119)
Settlement of asset retirement obligations	(228)	(193)
Stock based compensation expense	105	84
Estimated loss on Plant Vogtle Units 3 and 4	508	149
Storm damage accruals	112	117
Impairment charges	89	154
Natural gas cost under recovery – long-term	(119)	0
Other, net	(60)	(96)
Changes in certain current assets and liabilities —
-Receivables	29	292
-Prepayments	(79)	(102)
-Natural gas for sale, net of temporary LIFO liquidation	375	182
-Natural gas cost under recovery	(485)	0
-Other current assets	36	(253)
-Accounts payable	(177)	(467)
-Accrued taxes	(157)	258
-Accrued compensation	(238)	(347)
-Retail fuel cost over recovery	(146)	174
-Customer refunds	(59)	(223)
-Other current liabilities	(177)	42
Net cash provided from operating activities	2,904	2,847
Investing Activities:
Business acquisitions, net of cash acquired	(345)	(81)
Property additions	(3,384)	(3,202)
Nuclear decommissioning trust fund purchases	(930)	(524)
Nuclear decommissioning trust fund sales	926	519
Proceeds from dispositions	25	983
Cost of removal, net of salvage	(184)	(130)
Change in construction payables, net	(55)	(103)
Payments pursuant to LTSAs	(114)	(91)
Other investing activities	35	(26)
Net cash used for investing activities	(4,026)	(2,655)
Financing Activities:
Increase in notes payable	492
Decrease in notes payable		(1,170)
Proceeds —
Long-term debt	4,646	4,293
Common stock	24	59
Short-term borrowings	325	615
Redemptions and repurchases —
Long-term debt	(2,477)	(2,444)
Short-term borrowings	(25)	(190)
Capital contributions from noncontrolling interests	343	172
Distributions to noncontrolling interests	(113)	(118)
Payment of common stock dividends	(1,377)	(1,332)
Other financing activities	(167)	(170)
Net cash provided from (used for) financing activities	1,671	(285)
Net Change in Cash, Cash Equivalents, and Restricted Cash	549	(93)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	1,068	1,978
Cash, Cash Equivalents, and Restricted Cash at End of Period	1,617	1,885
Cash paid (received) during the period for —
Interest, net of amounts capitalized	884	852
Income taxes, net	88	(8)
Noncash transactions —
Accrued property additions at end of period	943	828
Contributions from noncontrolling interests	89	9
Contributions of wind turbine equipment	82	17
Right-of-use assets obtained under finance leases	90	94
Interest capitalized	43	41
ALABAMA POWER CO
Operating Activities:
Net income	697	585
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	496	484
Deferred income taxes	87	38
Allowance for equity funds used during construction	(24)	(22)
Pension, postretirement, and other employee benefits	(39)	(50)
Settlement of asset retirement obligations	(104)	(100)
Other, net	(35)	24
Changes in certain current assets and liabilities —
-Receivables	(85)	6
-Fossil fuel stock	21	(38)
-Prepayments	(53)	(62)
-Materials and supplies	(7)	(38)
-Other current assets	(37)	(34)
-Accounts payable	(236)	(232)
-Accrued taxes	20	197
-Accrued compensation	(60)	(75)
-Retail fuel cost over recovery	(18)	66
-Other current liabilities	(63)	(97)
Net cash provided from operating activities	584	674
Investing Activities:
Property additions	(844)	(686)
Nuclear decommissioning trust fund purchases	(473)	(160)
Nuclear decommissioning trust fund sales	473	160
Cost of removal, net of salvage	(56)	(29)
Change in construction payables, net	25	(53)
Other investing activities	(18)	(15)
Net cash used for investing activities	(893)	(783)
Proceeds —
Senior notes	600	0
Pollution control revenue bonds	0	87
Redemptions and repurchases —
Pollution control revenue bonds	0	(87)
Senior notes	(200)	0
Capital contributions from parent company	624	610
Payment of common stock dividends	(492)	(479)
Other financing activities	(26)	(15)
Net cash provided from (used for) financing activities	506	116
Net Change in Cash, Cash Equivalents, and Restricted Cash	197	7
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	530	894
Cash, Cash Equivalents, and Restricted Cash at End of Period	727	901
Cash paid (received) during the period for —
Interest, net of amounts capitalized	154	161
Income taxes, net	171	0
Noncash transactions —
Accrued property additions at end of period	191	147
Right-of-use assets obtained under leases	2	3
Interest capitalized	7	7
GEORGIA POWER CO
Operating Activities:
Net income	494	638
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	772	800
Deferred income taxes	(309)	(202)
Allowance for equity funds used during construction	(61)	(40)
Pension, postretirement, and other employee benefits	(59)	(55)
Settlement of asset retirement obligations	(100)	(78)
Estimated loss on Plant Vogtle Units 3 and 4	508	149
Storm damage accruals	107	107
Other, net	90	19
Changes in certain current assets and liabilities —
-Receivables	(73)	(73)
-Fossil fuel stock	55	(52)
-Materials and supplies	(46)	(61)
-Other current assets	15	(26)
-Accounts payable	83	0
-Accrued taxes	14	87
-Accrued compensation	(39)	(69)
-Retail fuel cost over recovery	(113)	109
-Customer refunds	(6)	(159)
-Other current liabilities	(19)	30
Net cash provided from operating activities	1,313	1,124
Investing Activities:
Property additions	(1,575)	(1,650)
Nuclear decommissioning trust fund purchases	(458)	(365)
Nuclear decommissioning trust fund sales	453	359
Proceeds from dispositions	3	143
Cost of removal, net of salvage	(73)	(62)
Change in construction payables, net	(72)	(48)
Other investing activities	(8)	(36)
Net cash used for investing activities	(1,730)	(1,659)
Financing Activities:
Increase in notes payable	250
Decrease in notes payable		(25)
Proceeds —
Senior notes	750	1,500
Pollution control revenue bonds	0	53
FFB loan	371	519
Short-term borrowings	0	250
Redemptions and repurchases —
Pollution control revenue bonds	(69)	(148)
Senior notes	(325)	(950)
FFB loan	(45)	(32)
Capital contributions from parent company	368	500
Payment of common stock dividends	(824)	(771)
Other financing activities	(19)	(27)
Net cash provided from (used for) financing activities	457	869
Net Change in Cash, Cash Equivalents, and Restricted Cash	40	334
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	9	52
Cash, Cash Equivalents, and Restricted Cash at End of Period	49	386
Cash paid (received) during the period for —
Interest, net of amounts capitalized	182	180
Income taxes, net	139	0
Noncash transactions —
Accrued property additions at end of period	476	478
Right-of-use assets obtained under operating leases	3	29
Interest capitalized	30	22
MISSISSIPPI POWER CO
Operating Activities:
Net income	83	71
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	106	92
Settlement of asset retirement obligations	(12)	(9)
Other, net	(16)	(4)
Changes in certain current assets and liabilities —
-Other current assets	(3)	(13)
-Accounts payable	(33)	(19)
-Accrued taxes	(51)	(21)
-Accrued compensation	(10)	(15)
-Retail fuel cost over recovery	(15)	(1)
-Other current liabilities	(8)	(10)
Net cash provided from operating activities	41	71
Investing Activities:
Property additions	(90)	(111)
Change in construction payables, net	(3)	(14)
Payments pursuant to LTSAs	(14)	(10)
Other investing activities	(10)	(10)
Net cash used for investing activities	(117)	(145)
Financing Activities:
Increase in notes payable		4
Decrease in notes payable	(25)
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)
Senior notes	0	(275)
Capital contributions from parent company	101	75
Return of capital to parent company	0	(74)
Payment of common stock dividends	(79)	0
Other financing activities	(7)	(1)
Net cash provided from (used for) financing activities	515	(178)
Net Change in Cash, Cash Equivalents, and Restricted Cash	439	(252)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	39	286
Cash, Cash Equivalents, and Restricted Cash at End of Period	478	34
Cash paid (received) during the period for —
Interest, net of amounts capitalized	31	33
Income taxes, net	7	0
Noncash transactions —
Accrued property additions at end of period	31	21
Interest capitalized	0	0
SOUTHERN POWER CO
Operating Activities:
Net income	100	112
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	264	251
Deferred income taxes	(20)	(34)
Utilization of federal investment tax credits	205	0
Amortization of investment tax credits	(29)	(30)
(Gain) loss on dispositions, net	(39)	(39)
Other, net	(18)	(31)
Changes in certain current assets and liabilities —
-Receivables	(91)	(67)
-Prepaid income taxes	28	73
-Other current assets	2	(8)
-Accounts payable	14	(29)
-Accrued taxes	8	16
-Other current liabilities	(13)	(19)
Net cash provided from operating activities	411	195
Investing Activities:
Business acquisitions, net of cash acquired	(345)	(81)
Property additions	(224)	(101)
Proceeds from dispositions	17	660
Change in construction payables, net	(14)	(4)
Payments pursuant to LTSAs	(47)	(31)
Other investing activities	12	47
Net cash used for investing activities	(601)	490
Financing Activities:
Decrease in notes payable	(56)	(357)
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	343	172
Distributions to noncontrolling interests	(113)	(118)
Payment of common stock dividends	(102)	(100)
Other financing activities	(5)	(5)
Net cash provided from (used for) financing activities	196	(808)
Net Change in Cash, Cash Equivalents, and Restricted Cash	6	(123)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	183	279
Cash, Cash Equivalents, and Restricted Cash at End of Period	189	156
Cash paid (received) during the period for —
Interest, net of amounts capitalized	91	96
Income taxes, net	(189)	(5)
Noncash transactions —
Accrued property additions at end of period	59	38
Contributions from noncontrolling interests	89	9
Contributions of wind turbine equipment	82	17
Right-of-use assets obtained under operating leases	65	30
Interest capitalized	2	7
SOUTHERN Co GAS
Operating Activities:
Net income	333	346
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	263	243
Deferred income taxes	110	40
Mark-to-market adjustments	137	34
Impairment of PennEast Pipeline investment	82	0
Natural gas cost under recovery – long-term	(119)	0
Other, net	15	11
Changes in certain current assets and liabilities —
-Receivables	262	344
-Prepaid income taxes	(129)	14
-Natural gas for sale, net of temporary LIFO liquidation	375	182
-Natural gas cost under recovery	(485)	0
-Other current assets	7	(8)
-Accounts payable	(42)	(176)
-Accrued compensation	17	(31)
-Other current liabilities	(104)	47
Net cash provided from operating activities	722	1,046
Investing Activities:
Property additions	(635)	(647)
Proceeds from dispositions	0	178
Cost of removal, net of salvage	(44)	(31)
Investment in unconsolidated subsidiaries	(3)	(78)
Other investing activities	14	8
Net cash used for investing activities	(668)	(570)
Financing Activities:
Increase in notes payable	210
Decrease in notes payable		(321)
Proceeds —
Short-term borrowings	300	0
Redemptions and repurchases —
Senior notes	(300)	0
Medium-term notes	(30)	0
Capital contributions from parent company	60	186
Payment of common stock dividends	(265)	(266)
Net cash provided from (used for) financing activities	(25)	(401)
Net Change in Cash, Cash Equivalents, and Restricted Cash	29	75
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	19	49
Cash, Cash Equivalents, and Restricted Cash at End of Period	48	124
Cash paid (received) during the period for —
Interest, net of amounts capitalized	127	119
Income taxes, net	100	(4)
Noncash transactions —
Accrued property additions at end of period	137	123
Interest capitalized	$ 3	$ 4

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) (Parenthetical) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Interest capitalized	$ 43	$ 41
ALABAMA POWER CO
Interest capitalized	7	7
GEORGIA POWER CO
Interest capitalized	30	22
MISSISSIPPI POWER CO
Interest capitalized	0	0
SOUTHERN POWER CO
Interest capitalized	2	7
SOUTHERN Co GAS
Interest capitalized	$ 3	$ 4

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Current Assets:
Cash and cash equivalents	$ 1,582	$ 1,065
Receivables —
Customer accounts	1,683	1,753
Energy marketing	0	516
Unbilled revenues	643	672
Other accounts and notes	488	512
Accumulated provision for uncollectible accounts	(88)	(118)
Materials and supplies	1,469	1,478
Fossil fuel for generation	475	550
Natural gas for sale	178	460
Prepaid expenses	538	276
Assets from risk management activities, net of collateral	175	147
Regulatory assets – asset retirement obligations	224	214
Natural gas cost under recovery	485	0
Assets held for sale	787	60
Other regulatory assets	728	810
Other current assets	184	222
Total current assets	9,551	8,617
Property, Plant, and Equipment:
In service	112,783	110,516
Less: Accumulated depreciation	33,240	32,397
Plant in service, net of depreciation	79,543	78,119
Nuclear fuel, at amortized cost	816	818
Construction work in progress	9,264	8,697
Total property, plant, and equipment	89,623	87,634
Other Property and Investments:
Goodwill	5,280	5,280
Nuclear decommissioning trusts, at fair value	2,457	2,303
Equity investments in unconsolidated subsidiaries	1,287	1,362
Other intangible assets, net of amortization	466	487
Leveraged leases	569	556
Miscellaneous property and investments	494	398
Total other property and investments	10,553	10,386
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,775	1,802
Deferred charges related to income taxes	806	796
Unamortized loss on reacquired debt	269	280
Regulatory assets – asset retirement obligations, deferred	4,931	4,934
Other regulatory assets, deferred	7,092	7,198
Other deferred charges and assets	1,307	1,288
Total deferred charges and other assets	16,180	16,298
Total Assets	125,907	122,935
Current Liabilities:
Securities due within one year	2,829	3,507
Notes payable	1,402	609
Energy marketing trade payables	0	494
Accounts payable —
Accounts payable	2,075	2,312
Customer deposits	467	487
Accrued taxes —
Accrued income taxes	40	130
Other accrued taxes	589	699
Accrued interest	510	513
Accrued compensation	770	1,025
Asset retirement obligations	684	585
Liabilities held for sale	677	0
Operating lease obligations	245	241
Other regulatory liabilities	416	509
Other current liabilities	956	968
Total current liabilities	11,660	12,079
Long-term Debt	47,828	45,073
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	8,710	8,175
Deferred credits related to income taxes	5,593	5,767
Accumulated deferred ITCs	2,247	2,235
Employee benefit obligations	2,004	2,213
Operating lease obligations, deferred	1,604	1,611
Asset retirement obligations, deferred	9,983	10,099
Accrued environmental remediation	208	216
Other cost of removal obligations	2,190	2,211
Other regulatory liabilities, deferred	256	251
Other deferred credits and liabilities	587	480
Total deferred credits and other liabilities	33,382	33,258
Total Liabilities	92,870	90,410
Redeemable Preferred Stock of Subsidiaries	291	291
Common Stockholder's Equity (See accompanying statements)	32,746	32,234
Total Liabilities and Stockholders' Equity	125,907	122,935
ALABAMA POWER CO
Current Assets:
Cash and cash equivalents	727	530
Receivables —
Customer accounts	402	429
Unbilled revenues	180	152
Affiliated	40	31
Other accounts and notes	80	66
Accumulated provision for uncollectible accounts	(25)	(43)
Materials and supplies	550	546
Fossil fuel for generation	214	235
Prepaid expenses	94	42
Other regulatory assets	221	226
Other current assets	88	33
Total current assets	2,571	2,247
Property, Plant, and Equipment:
In service	32,390	31,816
Less: Accumulated depreciation	10,229	10,009
Plant in service, net of depreciation	22,161	21,807
Nuclear fuel, at amortized cost	254	270
Construction work in progress	978	866
Total property, plant, and equipment	23,393	22,943
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,251	1,157
Equity investments in unconsolidated subsidiaries	64	63
Miscellaneous property and investments	127	131
Total other property and investments	1,442	1,351
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	130	151
Deferred charges related to income taxes	237	235
Regulatory assets – asset retirement obligations, deferred	1,437	1,441
Other regulatory assets, deferred	2,168	2,162
Other deferred charges and assets	313	273
Total deferred charges and other assets	4,285	4,262
Total Assets	31,691	30,803
Current Liabilities:
Securities due within one year	616	311
Accounts payable —
Affiliated	290	316
Other	378	545
Customer deposits	106	104
Accrued taxes —
Accrued taxes	173	152
Accrued interest	93	90
Accrued compensation	176	212
Asset retirement obligations	296	254
Other regulatory liabilities	37	108
Other current liabilities	119	107
Total current liabilities	2,284	2,199
Long-term Debt	8,649	8,558
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,390	3,273
Deferred credits related to income taxes	1,988	2,016
Accumulated deferred ITCs	91	94
Employee benefit obligations	173	214
Operating lease obligations, deferred	100	119
Asset retirement obligations, deferred	3,651	3,720
Other cost of removal obligations	291	335
Other regulatory liabilities, deferred	93	124
Other deferred credits and liabilities	53	50
Total deferred credits and other liabilities	9,830	9,945
Total Liabilities	20,763	20,702
Redeemable Preferred Stock	291	291
Common Stockholder's Equity (See accompanying statements)	10,637	9,810
Total Liabilities and Stockholders' Equity	31,691	30,803
GEORGIA POWER CO
Current Assets:
Cash and cash equivalents	49	9
Receivables —
Customer accounts	601	621
Unbilled revenues	334	233
Joint owner accounts	98	123
Affiliated	27	21
Other accounts and notes	40	67
Accumulated provision for uncollectible accounts	(3)	(26)
Materials and supplies	631	592
Fossil fuel for generation	223	278
Regulatory assets – storm damage	150	213
Regulatory assets – asset retirement obligations	183	166
Other regulatory assets	240	248
Other current assets	140	143
Total current assets	2,713	2,688
Property, Plant, and Equipment:
In service	40,408	39,682
Less: Accumulated depreciation	12,540	12,251
Plant in service, net of depreciation	27,868	27,431
Nuclear fuel, at amortized cost	562	548
Construction work in progress	7,062	6,857
Total property, plant, and equipment	35,492	34,836
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,207	1,145
Equity investments in unconsolidated subsidiaries	51	51
Miscellaneous property and investments	66	63
Total other property and investments	1,324	1,259
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,236	1,308
Deferred charges related to income taxes	535	527
Regulatory assets – asset retirement obligations, deferred	3,281	3,291
Other regulatory assets, deferred	2,550	2,692
Other deferred charges and assets	494	479
Total deferred charges and other assets	8,096	8,297
Total Assets	47,625	47,080
Current Liabilities:
Securities due within one year	627	542
Notes payable	310	60
Accounts payable —
Affiliated	587	597
Other	755	753
Customer deposits	268	276
Accrued taxes —
Accrued taxes	322	407
Accrued interest	138	130
Accrued compensation	164	233
Asset retirement obligations	321	287
Operating lease obligations	152	151
Other regulatory liabilities	277	228
Over recovered fuel clause revenues	0	113
Other current liabilities	230	254
Total current liabilities	4,151	4,031
Long-term Debt	13,023	12,428
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,138	3,272
Deferred credits related to income taxes	2,463	2,588
Accumulated deferred ITCs	322	273
Employee benefit obligations	518	586
Operating lease obligations, deferred	1,111	1,156
Asset retirement obligations, deferred	5,962	5,978
Other deferred credits and liabilities	391	267
Total deferred credits and other liabilities	13,905	14,120
Total Liabilities	31,079	30,579
Common Stockholder's Equity (See accompanying statements)	16,546	16,501
Total Liabilities and Stockholders' Equity	47,625	47,080
MISSISSIPPI POWER CO
Current Assets:
Cash and cash equivalents	478	39
Receivables —
Customer accounts	38	34
Unbilled revenues	42	38
Affiliated	26	32
Other accounts and notes	30	32
Materials and supplies	68	65
Fossil fuel for generation	25	24
Other regulatory assets	53	60
Other current assets	41	20
Total current assets	801	344
Property, Plant, and Equipment:
In service	5,053	5,011
Less: Accumulated depreciation	1,556	1,545
Plant in service, net of depreciation	3,497	3,466
Construction work in progress	126	146
Total property, plant, and equipment	3,623	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	213	201
Other regulatory assets, deferred	375	388
Accumulated deferred income taxes	123	129
Other deferred charges and assets	66	55
Total deferred charges and other assets	808	805
Total Assets	5,412	4,912
Current Liabilities:
Securities due within one year	421	406
Notes payable	0	25
Accounts payable —
Affiliated	71	63
Other	66	109
Accrued taxes —
Accrued taxes	63	114
Accrued interest	15	15
Accrued compensation	24	34
Asset retirement obligations	36	27
Other regulatory liabilities	62	49
Over recovered fuel clause revenues	12	34
Other current liabilities	51	40
Total current liabilities	821	916
Long-term Debt	1,512	1,013
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	460	447
Deferred credits related to income taxes	283	287
Employee benefit obligations	102	113
Asset retirement obligations, deferred	135	150
Other cost of removal obligations	193	194
Other regulatory liabilities, deferred	26	15
Other deferred credits and liabilities	31	35
Total deferred credits and other liabilities	1,230	1,241
Total Liabilities	3,563	3,170
Common Stockholder's Equity (See accompanying statements)	1,849	1,742
Total Liabilities and Stockholders' Equity	5,412	4,912
SOUTHERN POWER CO
Current Assets:
Cash and cash equivalents	165	182
Receivables —
Customer accounts	168	125
Affiliated	52	37
Other accounts and notes	48	27
Materials and supplies	101	157
Prepaid income taxes	153	11
Other current assets	56	36
Total current assets	743	575
Property, Plant, and Equipment:
In service	14,372	13,904
Less: Accumulated depreciation	2,991	2,842
Plant in service, net of depreciation	11,381	11,062
Construction work in progress	250	127
Total property, plant, and equipment	11,631	11,189
Other Property and Investments:
Intangible assets, net of amortization	292	302
Equity investments in unconsolidated subsidiaries	84	19
Miscellaneous property and investments	84	19
Total other property and investments	376	321
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	476	415
Prepaid LTSAs	179	155
Accumulated deferred income taxes	0	262
Income taxes receivable, non-current	31	25
Other deferred charges and assets	272	293
Total deferred charges and other assets	958	1,150
Total Assets	13,708	13,235
Current Liabilities:
Securities due within one year	1,012	299
Notes payable	119	175
Accounts payable —
Affiliated	75	65
Other	90	92
Accrued taxes —
Accrued income taxes	7	8
Other accrued taxes	20	22
Accrued interest	24	32
Other current liabilities	116	132
Total current liabilities	1,463	825
Long-term Debt	3,036	3,393
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	221	123
Accumulated deferred ITCs	1,643	1,672
Operating lease obligations, deferred	488	426
Other deferred credits and liabilities	167	165
Total deferred credits and other liabilities	2,519	2,386
Total Liabilities	7,018	6,604
Common Stockholder's Equity (See accompanying statements)	6,690	6,631
Total Liabilities and Stockholders' Equity	13,708	13,235
SOUTHERN Co GAS
Current Assets:
Cash and cash equivalents	37	17
Receivables —
Customer accounts	283	353
Energy marketing	0	516
Unbilled revenues	74	219
Affiliated	3	4
Other accounts and notes	31	51
Accumulated provision for uncollectible accounts	(45)	(40)
Natural gas for sale	178	460
Prepaid expenses	162	48
Assets from risk management activities, net of collateral	22	118
Natural gas cost under recovery	485	0
Assets held for sale	736	0
Other regulatory assets	97	102
Other current assets	40	38
Total current assets	2,103	1,886
Property, Plant, and Equipment:
In service	18,051	17,611
Less: Accumulated depreciation	4,942	4,821
Plant in service, net of depreciation	13,109	12,790
Construction work in progress	790	648
Total property, plant, and equipment	13,899	13,438
Other Property and Investments:
Goodwill	5,015	5,015
Equity investments in unconsolidated subsidiaries	1,189	1,290
Other intangible assets, net of amortization	44	51
Miscellaneous property and investments	19	19
Total other property and investments	6,267	6,375
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	72	81
Other regulatory assets, deferred	697	615
Other deferred charges and assets	197	235
Total deferred charges and other assets	966	931
Total Assets	23,235	22,630
Current Liabilities:
Securities due within one year	48	333
Notes payable	834	324
Energy marketing trade payables	0	494
Accounts payable —
Affiliated	50	56
Other	311	373
Customer deposits	75	90
Accrued taxes —
Accrued taxes	79	83
Accrued interest	55	58
Accrued compensation	105	106
Liabilities held for sale	677	0
Other regulatory liabilities	39	122
Temporary LIFO liquidation	182	0
Other current liabilities	125	150
Total current liabilities	2,580	2,189
Long-term Debt	6,234	6,293
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,413	1,265
Deferred credits related to income taxes	831	847
Employee benefit obligations	267	283
Operating lease obligations, deferred	59	67
Accrued environmental remediation	208	216
Other cost of removal obligations	1,673	1,649
Other deferred credits and liabilities	41	54
Total deferred credits and other liabilities	4,492	4,381
Total Liabilities	13,306	12,863
Common Stockholder's Equity (See accompanying statements)	9,929	9,767
Total Liabilities and Stockholders' Equity	$ 23,235	$ 22,630

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Other intangible assets, amortization	$ 286	$ 328
SOUTHERN POWER CO
Other intangible assets, amortization	99	89
SOUTHERN Co GAS
Other intangible assets, amortization	$ 138	$ 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)	1,461							585					638					71					112						346
Net income after dividends on preferred stock	1,480																												346
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)
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)	621							302					308			308		39			39		68	63		63		5	71		71
Net income after dividends on preferred stock	612							298			298																		71
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)
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)
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)	1,482							697					494					83					100						333
Net income after dividends on preferred stock	1,508																												333
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)
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)	376							335					143			143		38			38		36	36		36			(65)		(65)
Net income after dividends on preferred stock	372							331			331																		(65)
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)

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Consolidated Statements of Stockholders' Equity (Unaudited) (Parenthetical) - $ / shares	3 Months Ended
	Jun. 30, 2021	Mar. 31, 2021	Jun. 30, 2020	Mar. 31, 2020
Statement of Stockholders' Equity [Abstract]
Cash dividends (in dollars per share)	$ 0.66	$ 0.64	$ 0.64	$ 0.62

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Introduction

6 Months Ended

Jun. 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 June 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 June 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 June 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	$	(142)	$	70	$	212	$	(135)	$	77
Trade names	64		(35)		29		64		(31)		33
Storage and transportation contracts(*)	—		—		—		64		(64)		—
PPA fair value adjustments	390		(99)		291		390		(89)		301
Other	11		(10)		1		10		(9)		1
Total other intangible assets subject to amortization	$	677	$	(286)	$	391	$	740	$	(328)	$	412
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—		75		75		—		75
Total other intangible assets	$	752	$	(286)	$	466	$	815	$	(328)	$	487
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	390	$	(99)	$	291	$	390	$	(89)	$	301
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	156	$	(124)	$	32	$	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	$	(138)	$	44	$	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		Six Months Ended
	June 30, 2021
	(in millions)
Southern Company(a)	$	10	$	21
Southern Power(b)	5		10
Southern Company Gas(c)	3		7

(a)Includes $5 million and $10 million for the three and six months ended June 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
	June 30, 2021		December 31, 2020		June 30, 2021		June 30, 2021		December 31, 2020
	(in millions)				(in millions)		(in millions)
Cash and cash equivalents	$	1,582	$	1,065	$	165	$	37	$	17
Cash and cash equivalents classified as held for sale	8		—		—		8		—
Restricted cash(a):
Other current assets	2		2		—		2		2
Other deferred charges and assets	24		—		24		—		—
Total cash, cash equivalents, and restricted cash(b)	$	1,617	$	1,068	$	189	$	48	$	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' natural gas distribution utilities record natural gas inventories on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated.

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

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Regulatory Matters

6 Months Ended

Jun. 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 June 30, 2021 and December 31, 2020 were as follows:

Regulatory Clause	Balance Sheet Line Item	June 30, 2021		December 31, 2020
		(in millions)
Alabama Power
Rate CNP Compliance	Other regulatory liabilities, current	$	1	$	28
Rate CNP PPA	Other regulatory assets, deferred	64		58
Retail Energy Cost Recovery	Other regulatory liabilities, current	—		18
	Other regulatory assets, deferred	54		—
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	21		—
Mississippi Power
Fuel Cost Recovery	Over recovered regulatory clause liabilities	$	9	$	24
Ad Valorem Tax	Other regulatory assets, current	12		11
	Other regulatory assets, deferred	45		41
Property Damage Reserve	Other regulatory liabilities, deferred	—		4
	Other regulatory assets, deferred	5		—
Southern Company Gas
Natural Gas Cost Recovery(*)	Other regulatory liabilities	$	5	$	88
	Natural gas cost under recovery	485		—
	Other regulatory assets, deferred	119		—

(*)The significant change during the six months ended June 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. At June 30, 2021, expenditures associated with the construction of Plant Barry Unit 8 included in CWIP totaled approximately $188 million. The ultimate outcome of this matter cannot be determined at this time.

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 April 15, 2021, Mississippi Power filed its 2021 IRP with the Mississippi PSC, which includes a schedule to retire its 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. Mississippi Power's IRP is subject to a review period during which the Mississippi PSC may note any deficiencies which could require re-evaluation or resubmission of the IRP. If no deficiencies are noted, the Mississippi PSC's review will conclude on August 13, 2021.

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 Mississippi Power's IRP and associated regulatory processes, as well as 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 June 30, 2021, Alabama Power's NDR balance was $36 million. As a result, effective with October 2021 billings, the reserve maintenance charge component of Rate NDR will be suspended and the reserve establishment charge will be 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.

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 January 5, 2021, the Sierra Club filed a notice of appeal with the Georgia Court of Appeals. 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 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.

The request includes an annual rate increase totaling approximately $370 million to be effective the month after Unit 3 is placed in service. Unit 3 is projected to be placed in service in the second quarter 2022. This increase will be partially offset by a decrease in the NCCR tariff of approximately $116 million expected to be effective January 1, 2022. In addition, an estimated $45 million of fuel cost savings related to Unit 3 is already incorporated in Georgia Power's current fuel cost recovery rates.

Georgia Power also is requesting to defer some of its 2022 financing costs (approximately $42 million) relating to the remaining portion of the total Unit 3 and Common Facilities construction costs not being recovered through the NCCR tariff until Unit 4 costs are placed in retail base rates.

The Georgia PSC is scheduled to issue a final order in this proceeding on November 2, 2021. The ultimate outcome of this matter cannot be determined at this time. See "Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

Deferral of Incremental COVID-19 Costs

In June 2021, Georgia Power performed 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 of the review, Georgia Power reduced the balance of deferred incremental costs by approximately $20 million. At June 30, 2021, the incremental costs deferred totaled approximately $20 million, including approximately $2 million of incremental bad debt costs and $18 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.

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 June 2022 and March 2023, respectively, is as follows:

	(in millions)
Base project capital cost forecast(a)(b)	$	9,096
Construction contingency estimate	119
Total project capital cost forecast(a)(b)	9,215
Net investment at June 30, 2021(b)	(7,856)
Remaining estimate to complete	$	1,359

(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 $290 million, of which $143 million had been accrued through June 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 $2.7 billion had been incurred through June 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. The site has experienced an overall decline in the number of active cases since a peak in January 2021. 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 and fuel load for Unit 3. Hot functional testing for Unit 3 was completed in July 2021. 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. The site work plan currently targets fuel load for Unit 3 in the fourth quarter 2021 and an in-service date of March 2022. As the site work plan includes minimal margin to these milestone dates, an in-service date in the second 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. The site work plan targets an in-service date of November 2022 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 first 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. Considering the factors above, during the second quarter 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 described above, 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.

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 and the second quarter 2021 of $48 million ($36 million after tax) and $460 million ($343 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. 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.

In September 2020, Southern Nuclear notified the NRC of its intent to load fuel for Unit 3 in 2021. 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 second quarter 2022 for Unit 3 or the first 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. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

Joint Owner Contracts

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

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

Amendments to the Vogtle Joint Ownership Agreements

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

As previously disclosed, pursuant to the Global Amendments: (i) each Vogtle Owner must pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which formed the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM

(resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests. If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option at the time the project budget forecast is so revised to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion.

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

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

Regulatory Matters

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At June 30, 2021, Georgia Power had recovered approximately $2.6 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. In November 2020, the Georgia PSC approved Georgia Power's request to decrease the NCCR tariff by $142 million annually, effective January 1, 2021.

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 upon Unit 3 reaching 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, $270 million, and $90 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 23 VCM reports covering periods through June 30, 2020 and is scheduled to vote on the twenty-fourth VCM report in August 2021, including total construction capital costs incurred through December 31, 2020 of $8.7 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). On July 28, 2021, Georgia Power and the staff of the Georgia PSC reached a stipulated agreement providing for approval of the twenty-fourth VCM report as well as a change to future VCM proceedings. Beginning with its twenty-fifth VCM report, which Georgia Power expects to file with the Georgia PSC by August 31, 2021, Georgia Power will continue to report to the Georgia PSC all costs incurred during the period for review and will include a request for approval of costs up to the $7.3 billion determined to be reasonable in the Georgia PSC's seventeenth VCM order. Under the stipulation, Georgia Power will not seek verification or approval of costs above $7.3 billion prior to the Georgia PSC's prudence review contemplated by the seventeenth VCM order. The twenty-fifth VCM report will reflect the revised capital cost forecast discussed above. 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 April 15, 2021, Mississippi Power filed its 2021 IRP with the Mississippi PSC. The filing 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 $522 million at June 30, 2021. Mississippi Power expects to reclassify the net book value remaining at retirement 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 2021 IRP is subject to a review period during which the Mississippi PSC may note any deficiencies which could require re-evaluation or resubmission of the IRP. If no deficiencies are noted, the Mississippi PSC's review will conclude on August 13, 2021.

The ultimate outcome of this matter 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.

Southern Company Gas

Infrastructure Replacement Programs and Capital Projects

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

Utility	Program	Six Months Ended June 30, 2021
		(in millions)
Nicor Gas	Investing in Illinois	$	179
Virginia Natural Gas	Steps to Advance Virginia's Energy	22
Total		$	201

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. The Georgia PSC is scheduled to vote on this matter in November 2021. The ultimate outcome of this matter cannot be determined at this time.

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 May 10, 2021, Virginia Natural Gas, the Virginia Commission staff, and other intervenors entered into 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%. On July 8, 2021, the hearing examiner issued a report recommending adoption of the stipulation agreement. The Virginia Commission is expected to rule on this matter by September 2021. 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. The ultimate outcome of this matter cannot be determined at this time.

Atlanta Gas Light

On July 21, 2021, Atlanta Gas Light filed its annual GRAM filing with the Georgia PSC. The filing requests an annual base rate increase of $49 million based on the projected 12-month period beginning January 1, 2022. The proposed rate increase may be updated pending the resolution of Atlanta Gas Light's i-CDP filing. 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 "Infrastructure Replacement Programs and Capital Projects – Atlanta Gas Light" herein for additional information.

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. Nicor Gas will continue certain flexible credit and collection procedures through the third quarter 2021.

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Contingencies

6 Months Ended

Jun. 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. The parties in each case did not reach settlement but continue to explore possible resolution. Each case is stayed while the parties discuss potential resolution.

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. The amount of any possible losses 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 $15 million at both June 30, 2021 and December 31, 2020. 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 $247 million and $245 million at June 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

Work continues with state and federal agencies to obtain the required permits to begin construction of the PennEast Pipeline. 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). The ultimate outcome of the PennEast Pipeline construction project cannot be determined at this time. 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

6 Months Ended

Jun. 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 six months ended June 30, 2021 and 2020:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended June 30, 2021
Operating revenues
Retail electric revenues
Residential	$	1,469	$	553	$	852	$	64	$	—	$	—
Commercial	1,176		386		724		66		—		—
Industrial	728		334		321		73		—		—
Other	23		4		17		2		—		—
Total retail electric revenues	3,396		1,277		1,914		205		—		—
Natural gas distribution revenues
Residential	311		—		—		—		—		311
Commercial	73		—		—		—		—		73
Transportation	247		—		—		—		—		247
Industrial	8		—		—		—		—		8
Other	59		—		—		—		—		59
Total natural gas distribution revenues	698		—		—		—		—		698
Wholesale electric revenues
PPA energy revenues	209		38		16		2		158		—
PPA capacity revenues	118		29		14		1		75		—
Non-PPA revenues	55		25		3		75		78		—
Total wholesale electric revenues	382		92		33		78		311		—
Other natural gas revenues
Wholesale gas services	578		—		—		—		—		578
Gas marketing services	63		—		—		—		—		63
Other natural gas revenues	10		—		—		—		—		10
Total natural gas revenues	651		—		—		—		—		651
Other revenues	295		52		137		7		5		—
Total revenue from contracts with customers	5,422		1,421		2,084		290		316		1,349
Other revenue sources(a)	1,179		135		141		13		174		731
Other adjustments(b)	(1,403)		—		—		—		—		(1,403)
Total operating revenues	$	5,198	$	1,556	$	2,225	$	303	$	490	$	677

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Six Months Ended June 30, 2021
Operating revenues
Retail electric revenues
Residential	$	2,936	$	1,181	$	1,627	$	128	$	—	$	—
Commercial	2,294		758		1,410		126		—		—
Industrial	1,397		654		606		137		—		—
Other	47		9		34		4		—		—
Total retail electric revenues	6,674		2,602		3,677		395		—		—
Natural gas distribution revenues
Residential	925		—		—		—		—		925
Commercial	243		—		—		—		—		243
Transportation	536		—		—		—		—		536
Industrial	24		—		—		—		—		24
Other	155		—		—		—		—		155
Total natural gas distribution revenues	1,883		—		—		—		—		1,883
Wholesale electric revenues
PPA energy revenues	422		81		30		7		313		—
PPA capacity revenues	237		58		27		4		150		—
Non-PPA revenues	119		57		12		162		139		—
Total wholesale electric revenues	778		196		69		173		602		—
Other natural gas revenues
Wholesale gas services	2,168		—		—		—		—		2,168
Gas marketing services	257		—		—		—		—		257
Other natural gas revenues	17		—		—		—		—		17
Total natural gas revenues	2,442		—		—		—		—		2,442
Other revenues	542		97		249		14		9		—
Total revenue from contracts with customers	12,319		2,895		3,995		582		611		4,325
Other revenue sources(a)	2,488		220		200		28		319		1,745
Other adjustments(b)	(3,699)		—		—		—		—		(3,699)
Total operating revenues	$	11,108	$	3,115	$	4,195	$	610	$	930	$	2,371

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended June 30, 2020
Operating revenues
Retail electric revenues
Residential	$	1,430	$	549	$	817	$	64	$	—	$	—
Commercial	1,103		353		689		61		—		—
Industrial	642		302		273		67		—		—
Other	23		6		15		2		—		—
Total retail electric revenues	3,198		1,210		1,794		194		—		—
Natural gas distribution revenues
Residential	239		—		—		—		—		239
Commercial	58		—		—		—		—		58
Transportation	234		—		—		—		—		234
Industrial	5		—		—		—		—		5
Other	49		—		—		—		—		49
Total natural gas distribution revenues	585		—		—		—		—		585
Wholesale electric revenues
PPA energy revenues	167		28		7		2		134		—
PPA capacity revenues	108		25		13		1		71		—
Non-PPA revenues	50		5		2		73		59		—
Total wholesale electric revenues	325		58		22		76		264		—
Other natural gas revenues
Wholesale gas services	341		—		—		—		—		341
Gas marketing services	57		—		—		—		—		57
Other natural gas revenues	8		—		—		—		—		8
Total natural gas revenues	406		—		—		—		—		406
Other revenues	251		44		119		6		4		—
Total revenue from contracts with customers	4,765		1,312		1,935		276		268		991
Other revenue sources(a)	728		53		(7)		7		171		518
Other adjustments(b)	(873)		—		—		—		—		(873)
Total operating revenues	$	4,620	$	1,365	$	1,928	$	283	$	439	$	636

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Six Months Ended June 30, 2020
Operating revenues
Retail electric revenues
Residential	$	2,801	$	1,103	$	1,577	$	121	$	—	$	—
Commercial	2,247		717		1,409		121		—		—
Industrial	1,323		623		555		145		—		—
Other	46		11		31		4		—		—
Total retail electric revenues	6,417		2,454		3,572		391		—		—
Natural gas distribution revenues
Residential	736		—		—		—		—		736
Commercial	188		—		—		—		—		188
Transportation	499		—		—		—		—		499
Industrial	17		—		—		—		—		17
Other	144		—		—		—		—		144
Total natural gas distribution revenues	1,584		—		—		—		—		1,584
Wholesale electric revenues
PPA energy revenues	326		55		15		4		259		—
PPA capacity revenues	213		52		25		2		136		—
Non-PPA revenues	100		24		4		142		117		—
Total wholesale electric revenues	639		131		44		148		512		—
Other natural gas revenues
Wholesale gas services	737		—		—		—		—		737
Gas marketing services	220		—		—		—		—		220
Other natural gas revenues	15		—		—		—		—		15
Total natural gas revenues	972		—		—		—		—		972
Other revenues	441		78		214		13		7		—
Total revenue from contracts with customers	10,053		2,663		3,830		552		519		2,556
Other revenue sources(a)	1,599		53		(76)		7		295		1,343
Other adjustments(b)	(2,014)		—		—		—		—		(2,014)
Total operating revenues	$	9,638	$	2,716	$	3,754	$	559	$	814	$	1,885

(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 June 30, 2021 and December 31, 2020:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Accounts Receivable
At June 30, 2021	$	2,271	$	633	$	887	$	85	$	129	$	368
At December 31, 2020	2,614		632		806		77		112		788
Contract Assets
At June 30, 2021	$	98	$	—	$	36	$	—	$	1	$	—
At December 31, 2020	158		2		71		—		—		—
Contract Liabilities
At June 30, 2021	$	67	$	5	$	37	$	1	$	1	$	—
At December 31, 2020	61		6		27		1		1		1

At June 30, 2021 and December 31, 2020, Georgia Power had contract assets primarily related to unregulated service agreements, where payment is contingent on project completion, as well as, at December 31, 2020, contract assets 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. 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 $60 million and $81 million of contract assets and $24 million and $27 million of contract liabilities at June 30, 2021 and December 31, 2020, respectively, for outstanding performance obligations.

Revenues recognized by Southern Company in the three and six months ended June 30, 2021, which were included in contract liabilities at December 31, 2020, were $12 million and $21 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 June 30, 2021 are expected to be recognized as follows:

	2021 (remaining)		2022		2023		2024		2025		Thereafter
	(in millions)
Southern Company	$	354	$	464	$	343	$	327	$	307	$	2,667
Alabama Power	23		31		24		7		5		—
Georgia Power	41		58		39		23		21		41
Southern Power	165		323		281		297		281		2,644

Revenue expected to be recognized for performance obligations remaining at June 30, 2021 was immaterial for Mississippi Power and Southern Company Gas.

Lease Income

Lease income for the three and six months ended June 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 June 30, 2021
Lease income - interest income on sales-type leases	$	4	$	—	$	—	$	4	$	—	$	—
Lease income - operating leases	56		21		10		—		21		9
Variable lease income	128		(1)		—		—		138		—
Total lease income	$	188	$	20	$	10	$	4	$	159	$	9
For the Six Months Ended June 30, 2021
Lease income - interest income on sales-type leases	$	7	$	—	$	—	$	7	$	—	$	—
Lease income - operating leases	112		41		21		1		42		17
Variable lease income	212		—		—		—		228		—
Total lease income	$	331	$	41	$	21	$	8	$	270	$	17
For the Three Months Ended June 30, 2020
Lease income - interest income on sales-type leases	$	3	$	—	$	—	$	3	$	—	$	—
Lease income - operating leases	47		6		15		—		21		9
Variable lease income	126		—		—		—		136		—
Total lease income	$	176	$	6	$	15	$	3	$	157	$	9
For the Six Months Ended June 30, 2020
Lease income - interest income on sales-type leases	$	6	$	—	$	—	$	5	$	—	$	—
Lease income - operating leases	97		13		30		—		45		17
Variable lease income	200		—		—		—		215		—
Total lease income	$	303	$	13	$	30	$	5	$	260	$	17

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.

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Consolidated Entities and Equity Method Investments

6 Months Ended

Jun. 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 June 30, 2021 and December 31, 2020, SP Solar had total assets of $6.2 billion and $6.1 billion, respectively, total liabilities of $382 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 June 30, 2021 and December 31, 2020, SP Wind had total assets of $2.3 billion and $2.4 billion, respectively, total liabilities of $140 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 June 30, 2021 and December 31, 2020, the other VIEs had total assets of $1.9 billion and $1.1 billion, respectively, total liabilities of $249 million and $110 million, respectively, and noncontrolling interests of $913 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 June 30, 2021 and December 31, 2020, Southern Power had equity method investments in wind and battery storage projects totaling $84 million and $19 million, respectively.

Southern Company Gas

Equity Method Investments

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

Investment Balance	June 30, 2021		December 31, 2020
	(in millions)
SNG	$	1,143	$	1,167
PennEast Pipeline(*)	13		91
Other	33		32
Total	$	1,189	$	1,290

(*)Investment balance at June 30, 2021 reflects a pre-tax impairment charge of $82 million ($58 million after tax) recorded in the second quarter 2021. See Note (C) under "Other Matters – Southern Company Gas" for additional information.

	Three Months Ended June 30,				Six Months Ended June 30,
Earnings (Loss) from Equity Method Investments	2021		2020		2021		2020
	(in millions)
SNG	$	28	$	28	$	66	$	65
PennEast Pipeline(a)(b)	(81)		1		(79)		3
Other(a)(c)	1		1		2		4
Total	$	(52)	$	30	$	(11)	$	72

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

(b)Includes a pre-tax impairment charge of $82 million ($58 million after tax) for the three and six months ended June 30, 2021. See Note (C) under "Other Matters – Southern Company Gas" for additional information.

(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

6 Months Ended

Jun. 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 June 30, 2021, committed credit arrangements with banks were as follows:

	Expires
Company	2021		2022		2023		2024		2026		Total		Unused		Due within One Year
	(in millions)
Southern Company parent	$	—	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—
Alabama Power	3		525		—		—		700		1,228		1,228		3
Georgia Power	—		—		—		—		1,750		1,750		1,728		—
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	$	3	$	805	$	125	$	150	$	6,550	$	7,633	$	7,550	$	283

(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 June 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.

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 June 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 June 30, 2021 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, and $34 million at Mississippi Power). In addition, at June 30, 2021, Georgia Power and Mississippi Power had approximately $105 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 June 30,		Six Months Ended June 30,
	2021	2020	2021	2020
	(in millions)
As reported shares	1,061	1,058	1,060	1,057
Effect of stock-based compensation	6	5	6	7
Effect of equity units	—	—	—	1
Diluted shares	1,067	1,063	1,066	1,065

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

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Income Taxes

6 Months Ended

Jun. 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 $1.3 billion at June 30, 2021 compared to $1.4 billion at December 31, 2020.

The federal ITC and PTC carryforwards begin expiring in 2034 and 2032, respectively, but are expected to be fully utilized by 2024. The utilization of each 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.

Effective Tax Rate

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

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

Georgia Power

Georgia Power's effective tax benefit rate was (6.9)% for the six months ended June 30, 2021 compared to an effective tax rate of 4.0% 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. See Note (B) under "Georgia Power – Nuclear Construction" for additional information.

Southern Power

Southern Power's effective tax benefit rate was (12.8)% for the six months ended June 30, 2021 compared to an effective tax rate of 10.5% 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

6 Months Ended

Jun. 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 six months ended June 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 June 30, 2021
Pension Plans
Service cost	$	108	$	25	$	28	$	5	$	3	$	9
Interest cost	86		21		26		4		1		6
Expected return on plan assets	(297)		(71)		(94)		(13)		(4)		(22)
Amortization:
Prior service costs	—		—		1		—		—		—
Regulatory asset	—		—		—		—		—		4
Net (gain)/loss	79		20		25		3		1		3
Net periodic pension cost (income)	$	(24)	$	(5)	$	(14)	$	(1)	$	1	$	—
Postretirement Benefits
Service cost	$	6	$	2	$	1	$	—	$	—	$	1
Interest cost	9		2		3		1		—		1
Expected return on plan assets	(19)		(7)		(6)		(1)		—		(2)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		1
Net (gain)/loss	1		—		—		—		—		—
Net periodic postretirement benefit cost (income)	$	(4)	$	(3)	$	(2)	$	—	$	—	$	1
Six Months Ended June 30, 2021
Pension Plans
Service cost	$	217	$	51	$	56	$	9	$	5	$	18
Interest cost	173		41		52		8		2		12
Expected return on plan assets	(595)		(143)		(188)		(27)		(7)		(43)
Amortization:
Prior service costs	—		—		1		—		—		(1)
Regulatory asset	—		—		—		—		—		8
Net (gain)/loss	157		41		50		7		2		6
Net periodic pension cost (income)	$	(48)	$	(10)	$	(29)	$	(3)	$	2	$	—
Postretirement Benefits
Service cost	$	12	$	3	$	3	$	—	$	—	$	1
Interest cost	17		4		6		1		—		2
Expected return on plan assets	(38)		(14)		(13)		(1)		—		(4)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		3
Net (gain)/loss	2		—		1		—		—		(1)
Net periodic postretirement benefit cost (income)	$	(8)	$	(7)	$	(3)	$	—	$	—	$	1

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended June 30, 2020
Pension Plans
Service cost	$	94	$	22	$	24	$	4	$	2	$	8
Interest cost	108		25		34		5		2		7
Expected return on plan assets	(275)		(66)		(87)		(12)		(3)		(20)
Amortization:
Prior service costs	—		—		1		—		—		—
Regulatory asset	—		—		—		—		—		4
Net (gain)/loss	67		18		21		3		—		3
Net periodic pension cost (income)	$	(6)	$	(1)	$	(7)	$	—	$	1	$	2
Postretirement Benefits
Service cost	$	6	$	1	$	2	$	1	$	—	$	1
Interest cost	14		3		5		1		—		4
Expected return on plan assets	(18)		(7)		(6)		(1)		—		(2)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		1
Net (gain)/loss	—		—		—		—		—		(1)
Net periodic postretirement benefit cost (income)	$	1	$	(3)	$	1	$	1	$	—	$	3
Six Months Ended June 30, 2020
Pension Plans
Service cost	$	188	$	44	$	48	$	8	$	4	$	16
Interest cost	216		50		67		10		3		15
Expected return on plan assets	(550)		(132)		(174)		(25)		(6)		(39)
Amortization:
Prior service costs	1		—		1		—		—		(1)
Regulatory asset	—		—		—		—		—		8
Net (gain)/loss	134		36		43		6		1		5
Net periodic pension cost (income)	$	(11)	$	(2)	$	(15)	$	(1)	$	2	$	4
Postretirement Benefits
Service cost	$	11	$	3	$	3	$	1	$	—	$	1
Interest cost	27		6		10		1		—		6
Expected return on plan assets	(36)		(14)		(13)		(1)		—		(4)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		3
Net (gain)/loss	1		—		1		—		—		(2)
Net periodic postretirement benefit cost (income)	$	2	$	(5)	$	1	$	1	$	—	$	4

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Fair Value Measurements

6 Months Ended

Jun. 30, 2021

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

At June 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 June 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)	$	656	$	436	$	28	$	—	$	1,120
Interest rate derivatives	—		17		—		—		17
Foreign currency derivatives	—		55		—		—		55
Investments in trusts:(b)(c)
Domestic equity	812		236		—		—		1,048
Foreign equity	171		191		—		—		362
U.S. Treasury and government agency securities	—		311		—		—		311
Municipal bonds	—		45		—		—		45
Pooled funds – fixed income	—		18		—		—		18
Corporate bonds	4		453		—		—		457
Mortgage and asset backed securities	—		92		—		—		92
Private equity	—		—		—		102		102
Other	29		23		—		—		52
Cash equivalents	1,039		13		—		—		1,052
Other investments	9		30		—		—		39
Total	$	2,720	$	1,920	$	28	$	102	$	4,770
Liabilities:
Energy-related derivatives(a)	$	664	$	333	$	10	$	—	$	1,007
Interest rate derivatives	—		9		—		—		9
Foreign currency derivatives	—		10		—		—		10
Contingent consideration	—		—		16		—		16
Total	$	664	$	352	$	26	$	—	$	1,042

	Fair Value Measurements Using:
At June 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	$	—	$	46	$	—	$	—	$	46
Nuclear decommissioning trusts:(b)
Domestic equity	453		226		—		—		679
Foreign equity	171		—		—		—		171
U.S. Treasury and government agency securities	—		22		—		—		22
Municipal bonds	—		1		—		—		1
Corporate bonds	4		241		—		—		245
Mortgage and asset backed securities	—		24		—		—		24
Private equity	—		—		—		102		102
Other	6		—		—		—		6
Cash equivalents	507		13		—		—		520
Other investments	—		30		—		—		30
Total	$	1,141	$	603	$	—	$	102	$	1,846
Liabilities:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Georgia Power
Assets:
Energy-related derivatives	$	—	$	73	$	—	$	—	$	73
Nuclear decommissioning trusts:(b)(c)
Domestic equity	359		1		—		—		360
Foreign equity	—		188		—		—		188
U.S. Treasury and government agency securities	—		289		—		—		289
Municipal bonds	—		44		—		—		44
Corporate bonds	—		212		—		—		212
Mortgage and asset backed securities	—		68		—		—		68
Other	23		23		—		—		46
Total	$	382	$	898	$	—	$	—	$	1,280
Liabilities:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4

	Fair Value Measurements Using:
At June 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	$	—	$	44	$	—	$	—	$	44
Cash equivalents	455		—		—		—		455
Total	$	455	$	44	$	—	$	—	$	499
Liabilities:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Southern Power
Assets:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4
Foreign currency derivatives	—		55		—		—		55
Total	$	—	$	59	$	—	$	—	$	59
Liabilities:
Foreign currency derivatives	$	—	$	10	$	—	$	—	$	10
Contingent consideration	—		—		16		—		16
Total	$	—	$	10	$	16	$	—	$	26
Southern Company Gas
Assets:
Energy-related derivatives(a)	$	656	$	269	$	28	$	—	$	953
Interest rate derivatives	—		4		—		—		4
Non-qualified deferred compensation trusts:
Domestic equity	—		9		—		—		9
Foreign equity	—		3		—		—		3
Pooled funds – fixed income	—		18		—		—		18
Total	$	656	$	303	$	28	$	—	$	987
Liabilities:
Energy-related derivatives(a)	$	664	$	323	$	10	$	—	$	997

(a)Includes assets ($626 million, $260 million, and $28 million categorized as Level 1, 2, and 3, respectively) and liabilities ($657 million, $323 million, and $10 million categorized as Level 1, 2, and 3, respectively) related to Sequent, which were classified as held for sale at June 30, 2021. See Note (K) under "Southern Company Gas" and "Assets and Liabilities Held for Sale" for additional information. Excludes cash collateral of $41 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 June 30, 2021, approximately $48 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 and Liabilities 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 six months ended June 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 June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
	(in millions)
Southern Company	$	125	$	223	$	164	$	(23)
Alabama Power	77		124		118		(42)
Georgia Power	48		99		46		19

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.

"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 June 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 $102 million and unfunded commitments related to the private equity investments totaled $67 million. Private equity investments include high-quality private equity funds across several market sectors and funds that invest in real estate assets. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.

At June 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	$	50.4	$	9.3	$	13.5	$	1.9	$	4.0	$	6.3
Fair value	56.2		10.6		15.2		2.1		4.5		7.3

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

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

Commodity Contracts with Level 3 Valuation Inputs

At June 30, 2021, Southern Company Gas had Level 3 physical natural gas forward contracts totaling $18 million related to Sequent, which were classified as held for sale. See Note (K) under "Southern Company Gas" and "Assets and Liabilities Held for Sale" for additional information. Since commodity contracts classified as Level 3 typically include a combination of observable and unobservable components, the changes in fair value may include amounts due in part to observable market factors, or changes to assumptions on the unobservable components. The following table includes transfers to Level 3, which represent the fair value of Southern Company Gas' commodity derivative contracts that include a significant unobservable component for the first time during the period.

	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021
	(in millions)
Beginning balance	$	28	$	28
Instruments realized or otherwise settled during period	(4)		(6)
Changes in fair value	(6)		(4)
Ending balance	$	18	$	18

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

The valuation of certain commodity contracts requires the use of certain unobservable inputs. All forward pricing used in the valuation of such contracts is directly based on third-party market data, such as broker quotes and exchange settlements, when that data is available. If third-party market data is not available, then industry standard methodologies are used to develop inputs that maximize the use of relevant observable inputs and minimize the use of unobservable inputs. Observable inputs, including some forward prices used for determining fair value, reflect the best available market information. Unobservable inputs are updated using industry standard techniques such as extrapolation, combining observable forward inputs supplemented by historical market and other relevant data. Level 3 physical natural gas forward contracts include unobservable forward price inputs (ranging from $(0.06) to $0.38 per mmBtu). Forward price increases (decreases) at June 30, 2021 would have resulted in higher (lower) values on a net basis.

XML

Derivatives

6 Months Ended

Jun. 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 meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with 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 June 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(*)	978	2030	2031
Alabama Power	73	2024	—
Georgia Power	125	2024	—
Mississippi Power	85	2025	—
Southern Power	9	2030	2022
Southern Company Gas(*)	686	2024	2031

(*)Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 4.6 billion mmBtu and short natural gas positions of 3.9 billion mmBtu at June 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 44 million mmBtu for Southern Company, which includes 11 million mmBtu for Alabama Power, 13 million mmBtu for Georgia Power, 6 million mmBtu for Mississippi Power, and 14 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 June 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. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

At June 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 June 30, 2021
	(in millions)					(in millions)
Cash Flow Hedges of Existing Debt
Mississippi Power	$	60	1-month LIBOR	0.58%	December 2021	$	—
Fair Value Hedges of Existing Debt
Southern Company parent	400		1.75%	1-month LIBOR + 0.68%	March 2028	—
Southern Company parent	1,000		3.70%	1-month LIBOR + 2.36%	April 2030	4
Southern Company Gas	500		1.75%	1-month LIBOR + 0.38%	January 2031	3
Southern Company	$	1,960				$	7

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 June 30, 2022 total $(23) 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. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

At June 30, 2021, Southern Power had the following outstanding foreign currency derivatives designated as cash flow hedges of existing debt:

Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at June 30, 2021
(in millions)			(in millions)				(in millions)
$	677	2.95%	€	600	1.00%	June 2022	$	27
564		3.78%	500		1.85%	June 2026	18
$	1,241		€	1,100			$	45

The estimated pre-tax gains (losses) related to Southern Power's foreign currency derivatives expected to be reclassified from accumulated OCI to earnings for the 12-month period ending June 30, 2022 are $17 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 June 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	$	130	$	2	$	24	$	11
Other deferred charges and assets/Other deferred credits and liabilities	54		8		18		19
Total derivatives designated as hedging instruments for regulatory purposes	$	184	$	10	$	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	$	13	$	—	$	3	$	5
Other deferred charges and assets/Other deferred credits and liabilities	1		—		—		—
Interest rate derivatives:
Assets from risk management activities/Other current liabilities	17		—		20		—
Other deferred charges and assets/Other deferred credits and liabilities	—		9		—		—
Foreign currency derivatives:
Assets from risk management activities/Other current liabilities	27		10		—		23
Other deferred charges and assets/Other deferred credits and liabilities	28		—		87		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	86	$	19	$	110	$	28
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Other current liabilities	$	8	$	7	$	388	$	331
Other deferred charges and assets/Other deferred credits and liabilities	—		—		270		232
Assets held for sale, current/Liabilities held for sale, current	914		990		—		—
Total derivatives not designated as hedging instruments	$	922	$	997	$	658	$	563
Gross amounts recognized	$	1,192	$	1,026	$	810	$	621
Gross amounts offset(a)	(851)		(892)		(529)		(557)
Net amounts recognized in the Balance Sheets(b)	$	341	$	134	$	281	$	64

	At June 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	$	31	$	1	$	7	$	2
Other deferred charges and assets/Other deferred credits and liabilities	15		2		5		5
Total derivatives designated as hedging instruments for regulatory purposes	$	46	$	3	$	12	$	7
Gross amounts recognized	$	46	$	3	$	12	$	7
Gross amounts offset	(3)		(3)		(7)		(7)
Net amounts recognized in the Balance Sheets	$	43	$	—	$	5	$	—
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	52	$	1	$	7	$	5
Other deferred charges and assets/Other deferred credits and liabilities	21		3		8		8
Total derivatives designated as hedging instruments for regulatory purposes	$	73	$	4	$	15	$	13
Gross amounts recognized	$	73	$	4	$	15	$	13
Gross amounts offset	(4)		(4)		(12)		(12)
Net amounts recognized in the Balance Sheets	$	69	$	—	$	3	$	1
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	28	$	—	$	4	$	3
Other deferred charges and assets/Other deferred credits and liabilities	16		3		5		6
Total derivatives designated as hedging instruments for regulatory purposes	$	44	$	3	$	9	$	9
Gross amounts recognized	$	44	$	3	$	9	$	9
Gross amounts offset	(3)		(3)		(7)		(7)
Net amounts recognized in the Balance Sheets	$	41	$	—	$	2	$	2

	At June 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	$	4	$	—	$	2	$	2
Foreign currency derivatives:
Other current assets/Other current liabilities	27		10		—		23
Other deferred charges and assets/Other deferred credits and liabilities	28		—		87		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	59	$	10	$	89	$	25
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	—	$	—	$	—	$	1
Total derivatives not designated as hedging instruments	$	—	$	—	$	—	$	1
Net amounts recognized in the Balance Sheets	$	59	$	10	$	89	$	26

	At June 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	$	19	$	—	$	6	$	1
Other deferred charges and assets/Other deferred credits and liabilities	2		—		—		—
Total derivatives designated as hedging instruments for regulatory purposes	$	21	$	—	$	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	$	9	$	—	$	1	$	3
Other deferred charges and assets/Other deferred credits and liabilities	1		—		—		—
Interest rate derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	4		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	14	$	—	$	1	$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Other current liabilities	$	8	$	7	$	388	$	330
Other deferred charges and assets/Other deferred credits and liabilities	—		—		270		232
Assets held for sale, current/Liabilities held for sale, current	914		990		—		—
Total derivatives not designated as hedging instruments	$	922	$	997	$	658	$	562
Gross amounts of recognized	$	957	$	997	$	665	$	566
Gross amounts offset(a)	(841)		(882)		(503)		(531)
Net amounts recognized in the Balance Sheets(b)	$	116	$	115	$	162	$	35

(a)Gross amounts offset include cash collateral held on deposit in broker margin accounts of $41 million and $28 million at June 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 immaterial energy-related derivatives not designated as hedging instruments at June 30, 2021 and no such instruments at December 31, 2020.

At June 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 June 30, 2021:
Energy-related derivatives:
Other regulatory liabilities, current	$	120	$	31	$	51	$	28	$	10
Other regulatory liabilities, deferred	46		13		18		14		1
Total energy-related derivative gains (losses)	$	166	$	44	$	69	$	42	$	11
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 six months ended June 30, 2021 and 2020, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows:

Gain (Loss) Recognized in OCI on Derivative	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Southern Company
Energy-related derivatives	$	16	$	(2)	$	20	$	(6)
Interest rate derivatives	(1)		(1)		2		(28)
Foreign currency derivatives	4		17		(43)		(65)
Total	$	19	$	14	$	(21)	$	(99)
Southern Power
Energy-related derivatives	$	5	$	(2)	$	8	$	(2)
Foreign currency derivatives	4		17		(43)		(65)
Total	$	9	$	15	$	(35)	$	(67)
Southern Company Gas
Energy-related derivatives	$	11	$	—	$	12	$	(4)
Interest rate derivatives	—		(1)		—		(25)
Total	$	11	$	(1)	$	12	$	(29)

For the three and six months ended June 30, 2021 and 2020, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for the other Registrants.

For the three and six months ended June 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 June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Southern Company
Total cost of natural gas	$	231	$	144	$	814	$	583
Gain (loss) on energy-related cash flow hedges(a)	1		(1)		(2)		(8)
Total depreciation and amortization	891		873		1,762		1,730
Gain (loss) on energy-related cash flow hedges(a)	1		(1)		4		(2)
Total interest expense, net of amounts capitalized	(450)		(444)		(901)		(900)
Gain (loss) on interest rate cash flow hedges(a)	(7)		(6)		(14)		(13)
Gain (loss) on foreign currency cash flow hedges(a)	(6)		(6)		(12)		(12)
Gain (loss) on interest rate fair value hedges(b)	(3)		1		(12)		30
Total other income (expense), net	108		101		167		204
Gain (loss) on foreign currency cash flow hedges(a)(c)	17		27		(43)		(4)
Southern Power
Total depreciation and amortization	$	132	$	121	$	251	$	239
Gain (loss) on energy-related cash flow hedges(a)	1		(1)		4		(2)
Total interest expense, net of amounts capitalized	(37)		(38)		(75)		(77)
Gain (loss) on foreign currency cash flow hedges(a)	(6)		(6)		(12)		(12)
Total other income (expense), net	1		1		8		4
Gain (loss) on foreign currency cash flow hedges(a)(c)	17		27		(43)		(4)

(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 six months ended June 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 June 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 June 30, 2021		At December 31, 2020		At June 30, 2021		At December 31, 2020
	(in millions)				(in millions)
Southern Company
Securities due within one year	$	—	$	(1,509)	$	—	$	(10)
Long-term debt	(1,883)		—		—		—
Southern Company Gas
Long-term debt	$	(492)	$	—	$	3	$	—

For the three and six months ended June 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 June 30,				Six Months Ended June 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(*)	$	(103)	$	14	$	(120)	$	84
	Cost of natural gas	9		5		16		13
Total derivatives in non-designated hedging relationships		$	(94)	$	19	$	(104)	$	97

(*)Excludes immaterial gains (losses) recorded in natural gas revenues associated with weather derivatives for all periods presented.

For the three and six months ended June 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 June 30, 2021, the Registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

At June 30, 2021, the Registrants had no interest rate derivative liabilities with contingent features. At June 30, 2021, the fair value of Southern Company Gas' energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial. At June 30, 2021, the other Registrants had no energy-related derivative liabilities with contingent features. 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 June 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 June 30, 2021, cash collateral held on deposit in broker margin accounts was $41 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

6 Months Ended

Jun. 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 Power

Asset Acquisition

During the six months ended June 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 facility and consolidates the project's operating results in its financial statements. On March 30, 2021, Southern Power completed a tax equity transaction whereby it received $220 million. The tax equity partner, which is the Class A member, and Invenergy Renewables, LLC each own a noncontrolling interest.

Construction Projects

During the six months ended June 30, 2021, Southern Power continued construction of the Garland and Tranquillity battery energy storage facilities and the Glass Sands wind facility. Total aggregate construction costs, excluding acquisition costs, are expected to be between $390 million and $460 million for the facilities under construction. At June 30, 2021, total costs of construction incurred for these projects were $208 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time.

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
Projects Under Construction at June 30, 2021
Garland Solar Storage(a)	Battery energy storage system	88	Kern County, CA	August 2021	20 years
Tranquillity Solar Storage(a)	Battery energy storage system	72	Fresno County, CA	Fourth quarter 2021	20 years
Glass Sands(b)	Wind	118	Murray County, OK	Fourth quarter 2021	12 years

(a)Subsequent to June 30, 2021, Southern Power further restructured its ownership in the Garland battery energy storage project and completed a tax equity transaction whereby it received initial proceeds of $11 million, while retaining the controlling interest. Prior to commercial operation, Southern Power expects to further restructure its ownership in the Tranquillity battery energy storage project and complete a tax equity transaction, but expects to retain the controlling interest. The ultimate outcome of this matter cannot be determined at this time.

(b)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 to development and construction projects. During the six months ended June 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 $150 million, including estimated working capital adjustments. The preliminary gain associated with the transaction is approximately $90 million, which will be recorded in the third quarter 2021.

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 June 30, 2021, the obligations subject to the payment performance guarantee totaled $268 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.

The assets and liabilities of Sequent were classified as held for sale on the balance sheets of Southern Company and Southern Company Gas at June 30, 2021. See "Assets and Liabilities Held for Sale" herein for additional information.

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 and Liabilities Held for Sale

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

	Southern Company				Southern Company Gas
	At June 30,		At December 31,		At June 30,
	2021		2020		2021
	(in millions)
Assets Held for Sale:
Receivables – energy marketing	$	486	$	—	$	486
Natural gas for sale	90		—		90
Other current assets	76		—		76
Total property, plant, and equipment	11		8		5
Leveraged leases	45		52		—
Accumulated deferred income taxes	30		—		30
Other non-current assets	49		—		49
Total Assets Held for Sale	$	787	$	60	$	736
Liabilities Held for Sale:
Energy marketing trade payables	$	491	$	—	$	491
Other current liabilities	148		—		148
Other non-current liabilities	38		—		38
Total Liabilities Held for Sale	$	677	$	—	$	677

Southern Company Gas' assets and liabilities held for sale at June 30, 2021 were recorded based on their carrying value as the net carrying value of Sequent was lower than the agreed upon price in the sale agreement. See Note (I) for information regarding Sequent's energy-related derivatives held for sale that are recorded at fair value on a recurring basis. Southern Company's other assets held for sale at June 30, 2021 and December 31, 2020 were recorded at fair value on a nonrecurring basis, based primarily on unobservable inputs (Level 3).

See Note 3 to the financial statements under "Other Matters – Southern Company" in Item 8 of the Form 10-K for additional information regarding the leveraged lease investment held for sale.

Southern Company's and Southern Company Gas' asset sales, both individually and combined, do not represent a strategic shift in operations that has, or is expected to have, a major effect on operations and financial results; therefore, none of the assets have been classified as discontinued operations for any of the periods presented.

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Segment and Related Information

6 Months Ended

Jun. 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 $112 million and $193 million for the three and six months ended June 30, 2021, respectively, and $92 million and $178 million for the three and six months ended June 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 $6 million and $18 million for the three and six months ended June 30, 2021, respectively, and $3 million and $13 million for the three and six months ended June 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 six months ended June 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 June 30, 2021
Operating revenues	$	4,031	$	490	$	(114)	$	4,407	$	677	$	154	$	(40)	$	5,198
Segment net income (loss)(a)(b)(c)(d)	511		36		—		547		(65)		(108)		(2)		372
Six Months Ended June 30, 2021
Operating revenues	$	7,795	$	930	$	(201)	$	8,524	$	2,371	$	288	$	(75)	$	11,108
Segment net income (loss)(a)(b)(c)(d)(e)	1,267		133		—		1,400		333		(216)		(9)		1,508
At June 30, 2021
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	263	$	—	$	5,280
Assets held for sale	2		—		—		2		736		49		—		787
Total assets	87,330		13,708		(693)		100,345		23,235		3,063		(736)		125,907
Three Months Ended June 30, 2020
Operating revenues	$	3,539	$	439	$	(94)	$	3,884	$	636	$	135	$	(35)	$	4,620
Segment net income (loss)(a)(b)(d)	645		63		—		708		71		(177)		10		612
Six Months Ended June 30, 2020
Operating revenues	$	6,946	$	814	$	(181)	$	7,579	$	1,885	$	248	$	(74)	$	9,638
Segment net income (loss)(a)(b)(d)(f)	1,287		138		—		1,425		346		(299)		8		1,480
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 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 $460 million ($343 million after tax) and $508 million ($379 million after tax) for the three and six months ended June 30, 2021, respectively, and $149 million ($111 million after tax) for the three and six months ended June 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.

(c)For Southern Company Gas, includes a pre-tax impairment charge of $82 million ($58 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.

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

(e)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.

(f)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 June 30, 2021	$	3,599	$	546	$	262	$	4,407
Three Months Ended June 30, 2020	3,182		472		230		3,884
Six Months Ended June 30, 2021	$	6,941	$	1,091	$	492	$	8,524
Six Months Ended June 30, 2020	6,260		889		430		7,579

	Southern Company Gas' Revenues
	Gas Distribution Operations		Wholesale Gas Services(*)		Gas Marketing Services		Other		Total
	(in millions)
Three Months Ended June 30, 2021	$	706	$	(110)	$	64	$	17	$	677
Three Months Ended June 30, 2020	583		(19)		56		16		636
Six Months Ended June 30, 2021	$	1,898	$	188	$	259	$	26	$	2,371
Six Months Ended June 30, 2020	1,596		32		233		24		1,885

(*)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.

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 six months ended June 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 June 30, 2021
Operating revenues	$	710	$	8	$	(110)	$	64	$	672	$	11	$	(6)	$	677
Segment net income (loss)(b)	80		(36)		(112)		6		(62)		(3)		—		(65)
Six Months Ended June 30, 2021
Operating revenues	$	1,910	$	16	$	188	$	259	$	2,373	$	18	$	(20)	$	2,371
Segment net income (loss)(b)	263		(7)		14		62		332		1		—		333
Total assets at June 30, 2021	20,245		1,492		807		1,486		24,030		11,300		(12,095)		23,235
Three Months Ended June 30, 2020
Operating revenues	$	587	$	8	$	(19)	$	56	$	632	$	8	$	(4)	$	636
Segment net income (loss)	74		21		(23)		5		77		(6)		—		71
Six Months Ended June 30, 2020
Operating revenues	$	1,607	$	16	$	32	$	233	$	1,888	$	16	$	(19)	$	1,885
Segment net income (loss)	238		51		—		62		351		(5)		—		346
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 June 30, 2021	$	1,292	$	27	$	1,319	$	1,429	$	(110)
Three Months Ended June 30, 2020	854		18		872		891		(19)
Six Months Ended June 30, 2021	$	3,881	$	90	$	3,971	$	3,783	$	188
Six Months Ended June 30, 2020	2,039		47		2,086		2,054		32

(b)For gas pipeline investments, includes a pre-tax impairment charge of $82 million ($58 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)

6 Months Ended

Jun. 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 June 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' natural gas distribution utilities record 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.

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 meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with 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. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Foreign Currency Derivatives

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

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Introduction (Tables)

6 Months Ended

Jun. 30, 2021

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Goodwill

Goodwill at June 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 June 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	$	(142)	$	70	$	212	$	(135)	$	77
Trade names	64		(35)		29		64		(31)		33
Storage and transportation contracts(*)	—		—		—		64		(64)		—
PPA fair value adjustments	390		(99)		291		390		(89)		301
Other	11		(10)		1		10		(9)		1
Total other intangible assets subject to amortization	$	677	$	(286)	$	391	$	740	$	(328)	$	412
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—		75		75		—		75
Total other intangible assets	$	752	$	(286)	$	466	$	815	$	(328)	$	487
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	390	$	(99)	$	291	$	390	$	(89)	$	301
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	156	$	(124)	$	32	$	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	$	(138)	$	44	$	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 June 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	$	(142)	$	70	$	212	$	(135)	$	77
Trade names	64		(35)		29		64		(31)		33
Storage and transportation contracts(*)	—		—		—		64		(64)		—
PPA fair value adjustments	390		(99)		291		390		(89)		301
Other	11		(10)		1		10		(9)		1
Total other intangible assets subject to amortization	$	677	$	(286)	$	391	$	740	$	(328)	$	412
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—		75		75		—		75
Total other intangible assets	$	752	$	(286)	$	466	$	815	$	(328)	$	487
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	390	$	(99)	$	291	$	390	$	(89)	$	301
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	156	$	(124)	$	32	$	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	$	(138)	$	44	$	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		Six Months Ended
	June 30, 2021
	(in millions)
Southern Company(a)	$	10	$	21
Southern Power(b)	5		10
Southern Company Gas(c)	3		7

(a)Includes $5 million and $10 million for the three and six months ended June 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
	June 30, 2021		December 31, 2020		June 30, 2021		June 30, 2021		December 31, 2020
	(in millions)				(in millions)		(in millions)
Cash and cash equivalents	$	1,582	$	1,065	$	165	$	37	$	17
Cash and cash equivalents classified as held for sale	8		—		—		8		—
Restricted cash(a):
Other current assets	2		2		—		2		2
Other deferred charges and assets	24		—		24		—		—
Total cash, cash equivalents, and restricted cash(b)	$	1,617	$	1,068	$	189	$	48	$	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
	June 30, 2021		December 31, 2020		June 30, 2021		June 30, 2021		December 31, 2020
	(in millions)				(in millions)		(in millions)
Cash and cash equivalents	$	1,582	$	1,065	$	165	$	37	$	17
Cash and cash equivalents classified as held for sale	8		—		—		8		—
Restricted cash(a):
Other current assets	2		2		—		2		2
Other deferred charges and assets	24		—		24		—		—
Total cash, cash equivalents, and restricted cash(b)	$	1,617	$	1,068	$	189	$	48	$	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.

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Regulatory Matters (Tables)

6 Months Ended

Jun. 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 June 30, 2021 and December 31, 2020 were as follows:

Regulatory Clause	Balance Sheet Line Item	June 30, 2021		December 31, 2020
		(in millions)
Alabama Power
Rate CNP Compliance	Other regulatory liabilities, current	$	1	$	28
Rate CNP PPA	Other regulatory assets, deferred	64		58
Retail Energy Cost Recovery	Other regulatory liabilities, current	—		18
	Other regulatory assets, deferred	54		—
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	21		—
Mississippi Power
Fuel Cost Recovery	Over recovered regulatory clause liabilities	$	9	$	24
Ad Valorem Tax	Other regulatory assets, current	12		11
	Other regulatory assets, deferred	45		41
Property Damage Reserve	Other regulatory liabilities, deferred	—		4
	Other regulatory assets, deferred	5		—
Southern Company Gas
Natural Gas Cost Recovery(*)	Other regulatory liabilities	$	5	$	88
	Natural gas cost under recovery	485		—
	Other regulatory assets, deferred	119		—

(*)The significant change during the six months ended June 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 June 2022 and March 2023, respectively, is as follows:

	(in millions)
Base project capital cost forecast(a)(b)	$	9,096
Construction contingency estimate	119
Total project capital cost forecast(a)(b)	9,215
Net investment at June 30, 2021(b)	(7,856)
Remaining estimate to complete	$	1,359

(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 $290 million, of which $143 million had been accrued through June 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 six months of 2021 were as follows:

Utility	Program	Six Months Ended June 30, 2021
		(in millions)
Nicor Gas	Investing in Illinois	$	179
Virginia Natural Gas	Steps to Advance Virginia's Energy	22
Total		$	201

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Revenue from Contracts with Customers and Lease Income (Tables)

6 Months Ended

Jun. 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 six months ended June 30, 2021 and 2020:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended June 30, 2021
Operating revenues
Retail electric revenues
Residential	$	1,469	$	553	$	852	$	64	$	—	$	—
Commercial	1,176		386		724		66		—		—
Industrial	728		334		321		73		—		—
Other	23		4		17		2		—		—
Total retail electric revenues	3,396		1,277		1,914		205		—		—
Natural gas distribution revenues
Residential	311		—		—		—		—		311
Commercial	73		—		—		—		—		73
Transportation	247		—		—		—		—		247
Industrial	8		—		—		—		—		8
Other	59		—		—		—		—		59
Total natural gas distribution revenues	698		—		—		—		—		698
Wholesale electric revenues
PPA energy revenues	209		38		16		2		158		—
PPA capacity revenues	118		29		14		1		75		—
Non-PPA revenues	55		25		3		75		78		—
Total wholesale electric revenues	382		92		33		78		311		—
Other natural gas revenues
Wholesale gas services	578		—		—		—		—		578
Gas marketing services	63		—		—		—		—		63
Other natural gas revenues	10		—		—		—		—		10
Total natural gas revenues	651		—		—		—		—		651
Other revenues	295		52		137		7		5		—
Total revenue from contracts with customers	5,422		1,421		2,084		290		316		1,349
Other revenue sources(a)	1,179		135		141		13		174		731
Other adjustments(b)	(1,403)		—		—		—		—		(1,403)
Total operating revenues	$	5,198	$	1,556	$	2,225	$	303	$	490	$	677

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Six Months Ended June 30, 2021
Operating revenues
Retail electric revenues
Residential	$	2,936	$	1,181	$	1,627	$	128	$	—	$	—
Commercial	2,294		758		1,410		126		—		—
Industrial	1,397		654		606		137		—		—
Other	47		9		34		4		—		—
Total retail electric revenues	6,674		2,602		3,677		395		—		—
Natural gas distribution revenues
Residential	925		—		—		—		—		925
Commercial	243		—		—		—		—		243
Transportation	536		—		—		—		—		536
Industrial	24		—		—		—		—		24
Other	155		—		—		—		—		155
Total natural gas distribution revenues	1,883		—		—		—		—		1,883
Wholesale electric revenues
PPA energy revenues	422		81		30		7		313		—
PPA capacity revenues	237		58		27		4		150		—
Non-PPA revenues	119		57		12		162		139		—
Total wholesale electric revenues	778		196		69		173		602		—
Other natural gas revenues
Wholesale gas services	2,168		—		—		—		—		2,168
Gas marketing services	257		—		—		—		—		257
Other natural gas revenues	17		—		—		—		—		17
Total natural gas revenues	2,442		—		—		—		—		2,442
Other revenues	542		97		249		14		9		—
Total revenue from contracts with customers	12,319		2,895		3,995		582		611		4,325
Other revenue sources(a)	2,488		220		200		28		319		1,745
Other adjustments(b)	(3,699)		—		—		—		—		(3,699)
Total operating revenues	$	11,108	$	3,115	$	4,195	$	610	$	930	$	2,371

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended June 30, 2020
Operating revenues
Retail electric revenues
Residential	$	1,430	$	549	$	817	$	64	$	—	$	—
Commercial	1,103		353		689		61		—		—
Industrial	642		302		273		67		—		—
Other	23		6		15		2		—		—
Total retail electric revenues	3,198		1,210		1,794		194		—		—
Natural gas distribution revenues
Residential	239		—		—		—		—		239
Commercial	58		—		—		—		—		58
Transportation	234		—		—		—		—		234
Industrial	5		—		—		—		—		5
Other	49		—		—		—		—		49
Total natural gas distribution revenues	585		—		—		—		—		585
Wholesale electric revenues
PPA energy revenues	167		28		7		2		134		—
PPA capacity revenues	108		25		13		1		71		—
Non-PPA revenues	50		5		2		73		59		—
Total wholesale electric revenues	325		58		22		76		264		—
Other natural gas revenues
Wholesale gas services	341		—		—		—		—		341
Gas marketing services	57		—		—		—		—		57
Other natural gas revenues	8		—		—		—		—		8
Total natural gas revenues	406		—		—		—		—		406
Other revenues	251		44		119		6		4		—
Total revenue from contracts with customers	4,765		1,312		1,935		276		268		991
Other revenue sources(a)	728		53		(7)		7		171		518
Other adjustments(b)	(873)		—		—		—		—		(873)
Total operating revenues	$	4,620	$	1,365	$	1,928	$	283	$	439	$	636

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Six Months Ended June 30, 2020
Operating revenues
Retail electric revenues
Residential	$	2,801	$	1,103	$	1,577	$	121	$	—	$	—
Commercial	2,247		717		1,409		121		—		—
Industrial	1,323		623		555		145		—		—
Other	46		11		31		4		—		—
Total retail electric revenues	6,417		2,454		3,572		391		—		—
Natural gas distribution revenues
Residential	736		—		—		—		—		736
Commercial	188		—		—		—		—		188
Transportation	499		—		—		—		—		499
Industrial	17		—		—		—		—		17
Other	144		—		—		—		—		144
Total natural gas distribution revenues	1,584		—		—		—		—		1,584
Wholesale electric revenues
PPA energy revenues	326		55		15		4		259		—
PPA capacity revenues	213		52		25		2		136		—
Non-PPA revenues	100		24		4		142		117		—
Total wholesale electric revenues	639		131		44		148		512		—
Other natural gas revenues
Wholesale gas services	737		—		—		—		—		737
Gas marketing services	220		—		—		—		—		220
Other natural gas revenues	15		—		—		—		—		15
Total natural gas revenues	972		—		—		—		—		972
Other revenues	441		78		214		13		7		—
Total revenue from contracts with customers	10,053		2,663		3,830		552		519		2,556
Other revenue sources(a)	1,599		53		(76)		7		295		1,343
Other adjustments(b)	(2,014)		—		—		—		—		(2,014)
Total operating revenues	$	9,638	$	2,716	$	3,754	$	559	$	814	$	1,885

(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 June 30, 2021 and December 31, 2020:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Accounts Receivable
At June 30, 2021	$	2,271	$	633	$	887	$	85	$	129	$	368
At December 31, 2020	2,614		632		806		77		112		788
Contract Assets
At June 30, 2021	$	98	$	—	$	36	$	—	$	1	$	—
At December 31, 2020	158		2		71		—		—		—
Contract Liabilities
At June 30, 2021	$	67	$	5	$	37	$	1	$	1	$	—
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 June 30, 2021 are expected to be recognized as follows:

	2021 (remaining)		2022		2023		2024		2025		Thereafter
	(in millions)
Southern Company	$	354	$	464	$	343	$	327	$	307	$	2,667
Alabama Power	23		31		24		7		5		—
Georgia Power	41		58		39		23		21		41
Southern Power	165		323		281		297		281		2,644

Schedule of Lease Income

Lease income for the three and six months ended June 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 June 30, 2021
Lease income - interest income on sales-type leases	$	4	$	—	$	—	$	4	$	—	$	—
Lease income - operating leases	56		21		10		—		21		9
Variable lease income	128		(1)		—		—		138		—
Total lease income	$	188	$	20	$	10	$	4	$	159	$	9
For the Six Months Ended June 30, 2021
Lease income - interest income on sales-type leases	$	7	$	—	$	—	$	7	$	—	$	—
Lease income - operating leases	112		41		21		1		42		17
Variable lease income	212		—		—		—		228		—
Total lease income	$	331	$	41	$	21	$	8	$	270	$	17
For the Three Months Ended June 30, 2020
Lease income - interest income on sales-type leases	$	3	$	—	$	—	$	3	$	—	$	—
Lease income - operating leases	47		6		15		—		21		9
Variable lease income	126		—		—		—		136		—
Total lease income	$	176	$	6	$	15	$	3	$	157	$	9
For the Six Months Ended June 30, 2020
Lease income - interest income on sales-type leases	$	6	$	—	$	—	$	5	$	—	$	—
Lease income - operating leases	97		13		30		—		45		17
Variable lease income	200		—		—		—		215		—
Total lease income	$	303	$	13	$	30	$	5	$	260	$	17

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Consolidated Entities and Equity Method Investments (Tables)

6 Months Ended

Jun. 30, 2021

Regulated Operations [Abstract]

Schedule of Equity Method Investments

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

Investment Balance	June 30, 2021		December 31, 2020
	(in millions)
SNG	$	1,143	$	1,167
PennEast Pipeline(*)	13		91
Other	33		32
Total	$	1,189	$	1,290

(*)Investment balance at June 30, 2021 reflects a pre-tax impairment charge of $82 million ($58 million after tax) recorded in the second quarter 2021. See Note (C) under "Other Matters – Southern Company Gas" for additional information.

Schedule of Earnings from Equity Method Investments

	Three Months Ended June 30,				Six Months Ended June 30,
Earnings (Loss) from Equity Method Investments	2021		2020		2021		2020
	(in millions)
SNG	$	28	$	28	$	66	$	65
PennEast Pipeline(a)(b)	(81)		1		(79)		3
Other(a)(c)	1		1		2		4
Total	$	(52)	$	30	$	(11)	$	72

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

(b)Includes a pre-tax impairment charge of $82 million ($58 million after tax) for the three and six months ended June 30, 2021. See Note (C) under "Other Matters – Southern Company Gas" for additional information.

(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)

6 Months Ended

Jun. 30, 2021

Debt Disclosure [Abstract]

Schedule of Credit Arrangements

At June 30, 2021, committed credit arrangements with banks were as follows:

	Expires
Company	2021		2022		2023		2024		2026		Total		Unused		Due within One Year
	(in millions)
Southern Company parent	$	—	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—
Alabama Power	3		525		—		—		700		1,228		1,228		3
Georgia Power	—		—		—		—		1,750		1,750		1,728		—
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	$	3	$	805	$	125	$	150	$	6,550	$	7,633	$	7,550	$	283

(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 June 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 June 30,		Six Months Ended June 30,
	2021	2020	2021	2020
	(in millions)
As reported shares	1,061	1,058	1,060	1,057
Effect of stock-based compensation	6	5	6	7
Effect of equity units	—	—	—	1
Diluted shares	1,067	1,063	1,066	1,065

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Retirement Benefits (Tables)

6 Months Ended

Jun. 30, 2021

Retirement Benefits [Abstract]

Schedule of Pension Plans and Postretirement Plans

Components of the net periodic benefit costs for the three and six months ended June 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 June 30, 2021
Pension Plans
Service cost	$	108	$	25	$	28	$	5	$	3	$	9
Interest cost	86		21		26		4		1		6
Expected return on plan assets	(297)		(71)		(94)		(13)		(4)		(22)
Amortization:
Prior service costs	—		—		1		—		—		—
Regulatory asset	—		—		—		—		—		4
Net (gain)/loss	79		20		25		3		1		3
Net periodic pension cost (income)	$	(24)	$	(5)	$	(14)	$	(1)	$	1	$	—
Postretirement Benefits
Service cost	$	6	$	2	$	1	$	—	$	—	$	1
Interest cost	9		2		3		1		—		1
Expected return on plan assets	(19)		(7)		(6)		(1)		—		(2)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		1
Net (gain)/loss	1		—		—		—		—		—
Net periodic postretirement benefit cost (income)	$	(4)	$	(3)	$	(2)	$	—	$	—	$	1
Six Months Ended June 30, 2021
Pension Plans
Service cost	$	217	$	51	$	56	$	9	$	5	$	18
Interest cost	173		41		52		8		2		12
Expected return on plan assets	(595)		(143)		(188)		(27)		(7)		(43)
Amortization:
Prior service costs	—		—		1		—		—		(1)
Regulatory asset	—		—		—		—		—		8
Net (gain)/loss	157		41		50		7		2		6
Net periodic pension cost (income)	$	(48)	$	(10)	$	(29)	$	(3)	$	2	$	—
Postretirement Benefits
Service cost	$	12	$	3	$	3	$	—	$	—	$	1
Interest cost	17		4		6		1		—		2
Expected return on plan assets	(38)		(14)		(13)		(1)		—		(4)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		3
Net (gain)/loss	2		—		1		—		—		(1)
Net periodic postretirement benefit cost (income)	$	(8)	$	(7)	$	(3)	$	—	$	—	$	1

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended June 30, 2020
Pension Plans
Service cost	$	94	$	22	$	24	$	4	$	2	$	8
Interest cost	108		25		34		5		2		7
Expected return on plan assets	(275)		(66)		(87)		(12)		(3)		(20)
Amortization:
Prior service costs	—		—		1		—		—		—
Regulatory asset	—		—		—		—		—		4
Net (gain)/loss	67		18		21		3		—		3
Net periodic pension cost (income)	$	(6)	$	(1)	$	(7)	$	—	$	1	$	2
Postretirement Benefits
Service cost	$	6	$	1	$	2	$	1	$	—	$	1
Interest cost	14		3		5		1		—		4
Expected return on plan assets	(18)		(7)		(6)		(1)		—		(2)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		1
Net (gain)/loss	—		—		—		—		—		(1)
Net periodic postretirement benefit cost (income)	$	1	$	(3)	$	1	$	1	$	—	$	3
Six Months Ended June 30, 2020
Pension Plans
Service cost	$	188	$	44	$	48	$	8	$	4	$	16
Interest cost	216		50		67		10		3		15
Expected return on plan assets	(550)		(132)		(174)		(25)		(6)		(39)
Amortization:
Prior service costs	1		—		1		—		—		(1)
Regulatory asset	—		—		—		—		—		8
Net (gain)/loss	134		36		43		6		1		5
Net periodic pension cost (income)	$	(11)	$	(2)	$	(15)	$	(1)	$	2	$	4
Postretirement Benefits
Service cost	$	11	$	3	$	3	$	1	$	—	$	1
Interest cost	27		6		10		1		—		6
Expected return on plan assets	(36)		(14)		(13)		(1)		—		(4)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		3
Net (gain)/loss	1		—		1		—		—		(2)
Net periodic postretirement benefit cost (income)	$	2	$	(5)	$	1	$	1	$	—	$	4

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2021

Fair Value Disclosures [Abstract]

Schedule of Assets and Liabilities Measured at Fair Value

At June 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 June 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)	$	656	$	436	$	28	$	—	$	1,120
Interest rate derivatives	—		17		—		—		17
Foreign currency derivatives	—		55		—		—		55
Investments in trusts:(b)(c)
Domestic equity	812		236		—		—		1,048
Foreign equity	171		191		—		—		362
U.S. Treasury and government agency securities	—		311		—		—		311
Municipal bonds	—		45		—		—		45
Pooled funds – fixed income	—		18		—		—		18
Corporate bonds	4		453		—		—		457
Mortgage and asset backed securities	—		92		—		—		92
Private equity	—		—		—		102		102
Other	29		23		—		—		52
Cash equivalents	1,039		13		—		—		1,052
Other investments	9		30		—		—		39
Total	$	2,720	$	1,920	$	28	$	102	$	4,770
Liabilities:
Energy-related derivatives(a)	$	664	$	333	$	10	$	—	$	1,007
Interest rate derivatives	—		9		—		—		9
Foreign currency derivatives	—		10		—		—		10
Contingent consideration	—		—		16		—		16
Total	$	664	$	352	$	26	$	—	$	1,042

	Fair Value Measurements Using:
At June 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	$	—	$	46	$	—	$	—	$	46
Nuclear decommissioning trusts:(b)
Domestic equity	453		226		—		—		679
Foreign equity	171		—		—		—		171
U.S. Treasury and government agency securities	—		22		—		—		22
Municipal bonds	—		1		—		—		1
Corporate bonds	4		241		—		—		245
Mortgage and asset backed securities	—		24		—		—		24
Private equity	—		—		—		102		102
Other	6		—		—		—		6
Cash equivalents	507		13		—		—		520
Other investments	—		30		—		—		30
Total	$	1,141	$	603	$	—	$	102	$	1,846
Liabilities:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Georgia Power
Assets:
Energy-related derivatives	$	—	$	73	$	—	$	—	$	73
Nuclear decommissioning trusts:(b)(c)
Domestic equity	359		1		—		—		360
Foreign equity	—		188		—		—		188
U.S. Treasury and government agency securities	—		289		—		—		289
Municipal bonds	—		44		—		—		44
Corporate bonds	—		212		—		—		212
Mortgage and asset backed securities	—		68		—		—		68
Other	23		23		—		—		46
Total	$	382	$	898	$	—	$	—	$	1,280
Liabilities:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4

	Fair Value Measurements Using:
At June 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	$	—	$	44	$	—	$	—	$	44
Cash equivalents	455		—		—		—		455
Total	$	455	$	44	$	—	$	—	$	499
Liabilities:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Southern Power
Assets:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4
Foreign currency derivatives	—		55		—		—		55
Total	$	—	$	59	$	—	$	—	$	59
Liabilities:
Foreign currency derivatives	$	—	$	10	$	—	$	—	$	10
Contingent consideration	—		—		16		—		16
Total	$	—	$	10	$	16	$	—	$	26
Southern Company Gas
Assets:
Energy-related derivatives(a)	$	656	$	269	$	28	$	—	$	953
Interest rate derivatives	—		4		—		—		4
Non-qualified deferred compensation trusts:
Domestic equity	—		9		—		—		9
Foreign equity	—		3		—		—		3
Pooled funds – fixed income	—		18		—		—		18
Total	$	656	$	303	$	28	$	—	$	987
Liabilities:
Energy-related derivatives(a)	$	664	$	323	$	10	$	—	$	997

(a)Includes assets ($626 million, $260 million, and $28 million categorized as Level 1, 2, and 3, respectively) and liabilities ($657 million, $323 million, and $10 million categorized as Level 1, 2, and 3, respectively) related to Sequent, which were classified as held for sale at June 30, 2021. See Note (K) under "Southern Company Gas" and "Assets and Liabilities Held for Sale" for additional information. Excludes cash collateral of $41 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 June 30, 2021, approximately $48 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 six months ended June 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 June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
	(in millions)
Southern Company	$	125	$	223	$	164	$	(23)
Alabama Power	77		124		118		(42)
Georgia Power	48		99		46		19

Schedule of Financial Instruments for which Carrying Amount Did Not Equal Fair Value

At June 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	$	50.4	$	9.3	$	13.5	$	1.9	$	4.0	$	6.3
Fair value	56.2		10.6		15.2		2.1		4.5		7.3

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

Schedule of Fair Value of Commodity Derivative Contracts that Include a Significant Unobservable Component

The following table includes transfers to Level 3, which represent the fair value of Southern Company Gas' commodity derivative contracts that include a significant unobservable component for the first time during the period.

	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021
	(in millions)
Beginning balance	$	28	$	28
Instruments realized or otherwise settled during period	(4)		(6)
Changes in fair value	(6)		(4)
Ending balance	$	18	$	18

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Derivatives (Tables)

6 Months Ended

Jun. 30, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Energy-Related Derivatives

At June 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(*)	978	2030	2031
Alabama Power	73	2024	—
Georgia Power	125	2024	—
Mississippi Power	85	2025	—
Southern Power	9	2030	2022
Southern Company Gas(*)	686	2024	2031

(*)Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 4.6 billion mmBtu and short natural gas positions of 3.9 billion mmBtu at June 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 June 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 June 30, 2021
	(in millions)					(in millions)
Cash Flow Hedges of Existing Debt
Mississippi Power	$	60	1-month LIBOR	0.58%	December 2021	$	—
Fair Value Hedges of Existing Debt
Southern Company parent	400		1.75%	1-month LIBOR + 0.68%	March 2028	—
Southern Company parent	1,000		3.70%	1-month LIBOR + 2.36%	April 2030	4
Southern Company Gas	500		1.75%	1-month LIBOR + 0.38%	January 2031	3
Southern Company	$	1,960				$	7

Schedule of Foreign Currency Derivatives

At June 30, 2021, Southern Power had the following outstanding foreign currency derivatives designated as cash flow hedges of existing debt:

Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at June 30, 2021
(in millions)			(in millions)				(in millions)
$	677	2.95%	€	600	1.00%	June 2022	$	27
564		3.78%	500		1.85%	June 2026	18
$	1,241		€	1,100			$	45

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 June 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	$	130	$	2	$	24	$	11
Other deferred charges and assets/Other deferred credits and liabilities	54		8		18		19
Total derivatives designated as hedging instruments for regulatory purposes	$	184	$	10	$	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	$	13	$	—	$	3	$	5
Other deferred charges and assets/Other deferred credits and liabilities	1		—		—		—
Interest rate derivatives:
Assets from risk management activities/Other current liabilities	17		—		20		—
Other deferred charges and assets/Other deferred credits and liabilities	—		9		—		—
Foreign currency derivatives:
Assets from risk management activities/Other current liabilities	27		10		—		23
Other deferred charges and assets/Other deferred credits and liabilities	28		—		87		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	86	$	19	$	110	$	28
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Other current liabilities	$	8	$	7	$	388	$	331
Other deferred charges and assets/Other deferred credits and liabilities	—		—		270		232
Assets held for sale, current/Liabilities held for sale, current	914		990		—		—
Total derivatives not designated as hedging instruments	$	922	$	997	$	658	$	563
Gross amounts recognized	$	1,192	$	1,026	$	810	$	621
Gross amounts offset(a)	(851)		(892)		(529)		(557)
Net amounts recognized in the Balance Sheets(b)	$	341	$	134	$	281	$	64

	At June 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	$	31	$	1	$	7	$	2
Other deferred charges and assets/Other deferred credits and liabilities	15		2		5		5
Total derivatives designated as hedging instruments for regulatory purposes	$	46	$	3	$	12	$	7
Gross amounts recognized	$	46	$	3	$	12	$	7
Gross amounts offset	(3)		(3)		(7)		(7)
Net amounts recognized in the Balance Sheets	$	43	$	—	$	5	$	—
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	52	$	1	$	7	$	5
Other deferred charges and assets/Other deferred credits and liabilities	21		3		8		8
Total derivatives designated as hedging instruments for regulatory purposes	$	73	$	4	$	15	$	13
Gross amounts recognized	$	73	$	4	$	15	$	13
Gross amounts offset	(4)		(4)		(12)		(12)
Net amounts recognized in the Balance Sheets	$	69	$	—	$	3	$	1
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	28	$	—	$	4	$	3
Other deferred charges and assets/Other deferred credits and liabilities	16		3		5		6
Total derivatives designated as hedging instruments for regulatory purposes	$	44	$	3	$	9	$	9
Gross amounts recognized	$	44	$	3	$	9	$	9
Gross amounts offset	(3)		(3)		(7)		(7)
Net amounts recognized in the Balance Sheets	$	41	$	—	$	2	$	2

	At June 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	$	4	$	—	$	2	$	2
Foreign currency derivatives:
Other current assets/Other current liabilities	27		10		—		23
Other deferred charges and assets/Other deferred credits and liabilities	28		—		87		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	59	$	10	$	89	$	25
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	—	$	—	$	—	$	1
Total derivatives not designated as hedging instruments	$	—	$	—	$	—	$	1
Net amounts recognized in the Balance Sheets	$	59	$	10	$	89	$	26

	At June 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	$	19	$	—	$	6	$	1
Other deferred charges and assets/Other deferred credits and liabilities	2		—		—		—
Total derivatives designated as hedging instruments for regulatory purposes	$	21	$	—	$	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	$	9	$	—	$	1	$	3
Other deferred charges and assets/Other deferred credits and liabilities	1		—		—		—
Interest rate derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	4		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	14	$	—	$	1	$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Other current liabilities	$	8	$	7	$	388	$	330
Other deferred charges and assets/Other deferred credits and liabilities	—		—		270		232
Assets held for sale, current/Liabilities held for sale, current	914		990		—		—
Total derivatives not designated as hedging instruments	$	922	$	997	$	658	$	562
Gross amounts of recognized	$	957	$	997	$	665	$	566
Gross amounts offset(a)	(841)		(882)		(503)		(531)
Net amounts recognized in the Balance Sheets(b)	$	116	$	115	$	162	$	35

(a)Gross amounts offset include cash collateral held on deposit in broker margin accounts of $41 million and $28 million at June 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 June 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 June 30, 2021:
Energy-related derivatives:
Other regulatory liabilities, current	$	120	$	31	$	51	$	28	$	10
Other regulatory liabilities, deferred	46		13		18		14		1
Total energy-related derivative gains (losses)	$	166	$	44	$	69	$	42	$	11
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 Cash Flow Hedging on AOCI

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

Gain (Loss) Recognized in OCI on Derivative	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Southern Company
Energy-related derivatives	$	16	$	(2)	$	20	$	(6)
Interest rate derivatives	(1)		(1)		2		(28)
Foreign currency derivatives	4		17		(43)		(65)
Total	$	19	$	14	$	(21)	$	(99)
Southern Power
Energy-related derivatives	$	5	$	(2)	$	8	$	(2)
Foreign currency derivatives	4		17		(43)		(65)
Total	$	9	$	15	$	(35)	$	(67)
Southern Company Gas
Energy-related derivatives	$	11	$	—	$	12	$	(4)
Interest rate derivatives	—		(1)		—		(25)
Total	$	11	$	(1)	$	12	$	(29)

Schedule of Pre-Tax Effects of Cash Flow and Fair Value Hedging on Income

For the three and six months ended June 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 June 30,				For the Six Months Ended June 30,
	2021		2020		2021		2020
	(in millions)				(in millions)
Southern Company
Total cost of natural gas	$	231	$	144	$	814	$	583
Gain (loss) on energy-related cash flow hedges(a)	1		(1)		(2)		(8)
Total depreciation and amortization	891		873		1,762		1,730
Gain (loss) on energy-related cash flow hedges(a)	1		(1)		4		(2)
Total interest expense, net of amounts capitalized	(450)		(444)		(901)		(900)
Gain (loss) on interest rate cash flow hedges(a)	(7)		(6)		(14)		(13)
Gain (loss) on foreign currency cash flow hedges(a)	(6)		(6)		(12)		(12)
Gain (loss) on interest rate fair value hedges(b)	(3)		1		(12)		30
Total other income (expense), net	108		101		167		204
Gain (loss) on foreign currency cash flow hedges(a)(c)	17		27		(43)		(4)
Southern Power
Total depreciation and amortization	$	132	$	121	$	251	$	239
Gain (loss) on energy-related cash flow hedges(a)	1		(1)		4		(2)
Total interest expense, net of amounts capitalized	(37)		(38)		(75)		(77)
Gain (loss) on foreign currency cash flow hedges(a)	(6)		(6)		(12)		(12)
Total other income (expense), net	1		1		8		4
Gain (loss) on foreign currency cash flow hedges(a)(c)	17		27		(43)		(4)

(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 June 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 June 30, 2021		At December 31, 2020		At June 30, 2021		At December 31, 2020
	(in millions)				(in millions)
Southern Company
Securities due within one year	$	—	$	(1,509)	$	—	$	(10)
Long-term debt	(1,883)		—		—		—
Southern Company Gas
Long-term debt	$	(492)	$	—	$	3	$	—

Schedule of Pre-tax Effect of Interest Rate and Energy Related Derivatives on Income

For the three and six months ended June 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 June 30,				Six Months Ended June 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(*)	$	(103)	$	14	$	(120)	$	84
	Cost of natural gas	9		5		16		13
Total derivatives in non-designated hedging relationships		$	(94)	$	19	$	(104)	$	97

(*)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)

6 Months Ended

Jun. 30, 2021

Business Combination and Asset Acquisition [Abstract]

Schedule of Asset Acquisitions

During the six months ended June 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 facility and consolidates the project's operating results in its financial statements. On March 30, 2021, Southern Power completed a tax equity transaction whereby it received $220 million. The tax equity partner, which is the Class A member, 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 June 30, 2021
Garland Solar Storage(a)	Battery energy storage system	88	Kern County, CA	August 2021	20 years
Tranquillity Solar Storage(a)	Battery energy storage system	72	Fresno County, CA	Fourth quarter 2021	20 years
Glass Sands(b)	Wind	118	Murray County, OK	Fourth quarter 2021	12 years

(a)Subsequent to June 30, 2021, Southern Power further restructured its ownership in the Garland battery energy storage project and completed a tax equity transaction whereby it received initial proceeds of $11 million, while retaining the controlling interest. Prior to commercial operation, Southern Power expects to further restructure its ownership in the Tranquillity battery energy storage project and complete a tax equity transaction, but expects to retain the controlling interest. The ultimate outcome of this matter cannot be determined at this time.

(b)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 and liabilities classified as held for sale by Southern Company and Southern Company Gas at June 30, 2021 and/or December 31, 2020:

	Southern Company				Southern Company Gas
	At June 30,		At December 31,		At June 30,
	2021		2020		2021
	(in millions)
Assets Held for Sale:
Receivables – energy marketing	$	486	$	—	$	486
Natural gas for sale	90		—		90
Other current assets	76		—		76
Total property, plant, and equipment	11		8		5
Leveraged leases	45		52		—
Accumulated deferred income taxes	30		—		30
Other non-current assets	49		—		49
Total Assets Held for Sale	$	787	$	60	$	736
Liabilities Held for Sale:
Energy marketing trade payables	$	491	$	—	$	491
Other current liabilities	148		—		148
Other non-current liabilities	38		—		38
Total Liabilities Held for Sale	$	677	$	—	$	677

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Segment and Related Information (Tables)

6 Months Ended

Jun. 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 six months ended June 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 June 30, 2021
Operating revenues	$	4,031	$	490	$	(114)	$	4,407	$	677	$	154	$	(40)	$	5,198
Segment net income (loss)(a)(b)(c)(d)	511		36		—		547		(65)		(108)		(2)		372
Six Months Ended June 30, 2021
Operating revenues	$	7,795	$	930	$	(201)	$	8,524	$	2,371	$	288	$	(75)	$	11,108
Segment net income (loss)(a)(b)(c)(d)(e)	1,267		133		—		1,400		333		(216)		(9)		1,508
At June 30, 2021
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	263	$	—	$	5,280
Assets held for sale	2		—		—		2		736		49		—		787
Total assets	87,330		13,708		(693)		100,345		23,235		3,063		(736)		125,907
Three Months Ended June 30, 2020
Operating revenues	$	3,539	$	439	$	(94)	$	3,884	$	636	$	135	$	(35)	$	4,620
Segment net income (loss)(a)(b)(d)	645		63		—		708		71		(177)		10		612
Six Months Ended June 30, 2020
Operating revenues	$	6,946	$	814	$	(181)	$	7,579	$	1,885	$	248	$	(74)	$	9,638
Segment net income (loss)(a)(b)(d)(f)	1,287		138		—		1,425		346		(299)		8		1,480
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 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 $460 million ($343 million after tax) and $508 million ($379 million after tax) for the three and six months ended June 30, 2021, respectively, and $149 million ($111 million after tax) for the three and six months ended June 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.

(c)For Southern Company Gas, includes a pre-tax impairment charge of $82 million ($58 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.

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

(e)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.

(f)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 six months ended June 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 June 30, 2021
Operating revenues	$	710	$	8	$	(110)	$	64	$	672	$	11	$	(6)	$	677
Segment net income (loss)(b)	80		(36)		(112)		6		(62)		(3)		—		(65)
Six Months Ended June 30, 2021
Operating revenues	$	1,910	$	16	$	188	$	259	$	2,373	$	18	$	(20)	$	2,371
Segment net income (loss)(b)	263		(7)		14		62		332		1		—		333
Total assets at June 30, 2021	20,245		1,492		807		1,486		24,030		11,300		(12,095)		23,235
Three Months Ended June 30, 2020
Operating revenues	$	587	$	8	$	(19)	$	56	$	632	$	8	$	(4)	$	636
Segment net income (loss)	74		21		(23)		5		77		(6)		—		71
Six Months Ended June 30, 2020
Operating revenues	$	1,607	$	16	$	32	$	233	$	1,888	$	16	$	(19)	$	1,885
Segment net income (loss)	238		51		—		62		351		(5)		—		346
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 June 30, 2021	$	1,292	$	27	$	1,319	$	1,429	$	(110)
Three Months Ended June 30, 2020	854		18		872		891		(19)
Six Months Ended June 30, 2021	$	3,881	$	90	$	3,971	$	3,783	$	188
Six Months Ended June 30, 2020	2,039		47		2,086		2,054		32

(b)For gas pipeline investments, includes a pre-tax impairment charge of $82 million ($58 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 June 30, 2021	$	3,599	$	546	$	262	$	4,407
Three Months Ended June 30, 2020	3,182		472		230		3,884
Six Months Ended June 30, 2021	$	6,941	$	1,091	$	492	$	8,524
Six Months Ended June 30, 2020	6,260		889		430		7,579

	Southern Company Gas' Revenues
	Gas Distribution Operations		Wholesale Gas Services(*)		Gas Marketing Services		Other		Total
	(in millions)
Three Months Ended June 30, 2021	$	706	$	(110)	$	64	$	17	$	677
Three Months Ended June 30, 2020	583		(19)		56		16		636
Six Months Ended June 30, 2021	$	1,898	$	188	$	259	$	26	$	2,371
Six Months Ended June 30, 2020	1,596		32		233		24		1,885

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

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Introduction - Schedule of Goodwill (Details) - USD ($) $ in Millions	Jun. 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	Jun. 30, 2021	Dec. 31, 2020
Other intangible assets subject to amortization:
Gross Carrying Amount	$ 677	$ 740
Accumulated Amortization	(286)	(328)
Other Intangible Assets, Net	391	412
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75	75
Total other intangible assets
Gross Carrying Amount	752	815
Accumulated Amortization	(286)	(328)
Other Intangible Assets, Net	466	487
Customer relationships
Other intangible assets subject to amortization:
Gross Carrying Amount	212	212
Accumulated Amortization	(142)	(135)
Other Intangible Assets, Net	70	77
Total other intangible assets
Accumulated Amortization	(142)	(135)
Trade names
Other intangible assets subject to amortization:
Gross Carrying Amount	64	64
Accumulated Amortization	(35)	(31)
Other Intangible Assets, Net	29	33
Total other intangible assets
Accumulated Amortization	(35)	(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	(99)	(89)
Other Intangible Assets, Net	291	301
Total other intangible assets
Accumulated Amortization	(99)	(89)
Other
Other intangible assets subject to amortization:
Gross Carrying Amount	11	10
Accumulated Amortization	(10)	(9)
Other Intangible Assets, Net	1	1
Total other intangible assets
Accumulated Amortization	(10)	(9)
SOUTHERN POWER CO
Other intangible assets subject to amortization:
Accumulated Amortization	(99)	(89)
Total other intangible assets
Accumulated Amortization	(99)	(89)
SOUTHERN POWER CO | PPA fair value adjustments
Other intangible assets subject to amortization:
Gross Carrying Amount	390	390
Accumulated Amortization	(99)	(89)
Other Intangible Assets, Net	291	301
Total other intangible assets
Accumulated Amortization	(99)	(89)
SOUTHERN Co GAS
Other intangible assets subject to amortization:
Gross Carrying Amount	182	246
Accumulated Amortization	(138)	(195)
Other Intangible Assets, Net	44	51
Total other intangible assets
Accumulated Amortization	(138)	(195)
Other Intangible Assets, Net	44	51
SOUTHERN Co GAS | Customer relationships
Other intangible assets subject to amortization:
Gross Carrying Amount	156	156
Accumulated Amortization	(124)	(119)
Other Intangible Assets, Net	32	37
Total other intangible assets
Accumulated Amortization	(124)	(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	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2021
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 10	$ 21
Decrease in operating revenues	5	10
SOUTHERN POWER CO
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	5	10
SOUTHERN Co GAS
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 3	$ 7

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Introduction - Schedule of Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020	Jun. 30, 2020	Dec. 31, 2019
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	$ 1,582	$ 1,065
Cash and cash equivalents classified as held for sale	8	0
Restricted cash:
Total cash, cash equivalents, and restricted cash	1,617	1,068	$ 1,885	$ 1,978
Other current assets
Restricted cash:
Restricted cash	2	2
Other deferred charges and assets
Restricted cash:
Restricted cash	24	0
SOUTHERN POWER CO
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	165	182
Cash and cash equivalents classified as held for sale	0
Restricted cash:
Total cash, cash equivalents, and restricted cash	189	183	156	279
SOUTHERN POWER CO | Other current assets
Restricted cash:
Restricted cash	0
SOUTHERN POWER CO | Other deferred charges and assets
Restricted cash:
Restricted cash	24
SOUTHERN Co GAS
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	37	17
Cash and cash equivalents classified as held for sale	8	0
Restricted cash:
Total cash, cash equivalents, and restricted cash	48	19	$ 124	$ 49
SOUTHERN Co GAS | Other current assets
Restricted cash:
Restricted cash	2	2
SOUTHERN Co GAS | Other deferred charges and assets
Restricted cash:
Restricted cash	$ 0	$ 0

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Regulatory Matters - Schedule of Cost Recovery Clauses (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Loss Contingencies [Line Items]
Natural gas cost under recovery	$ 485	$ 0
ALABAMA POWER CO | Other regulatory liabilities, current
Loss Contingencies [Line Items]
Rate CNP Compliance	1	28
Retail Energy Cost Recovery	0	18
ALABAMA POWER CO | Other regulatory liabilities, deferred
Loss Contingencies [Line Items]
Natural Disaster Reserve	36	77
ALABAMA POWER CO | Other regulatory assets, deferred
Loss Contingencies [Line Items]
Rate CNP PPA	64	58
Retail Energy Cost Recovery	54	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	21	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	45	41
Property Damage Reserve	5	0
MISSISSIPPI POWER CO | Over recovered regulatory clause liabilities
Loss Contingencies [Line Items]
Fuel Cost Recovery	9	24
MISSISSIPPI POWER CO | Other regulatory assets, current
Loss Contingencies [Line Items]
Ad Valorem Tax	12	11
SOUTHERN Co GAS
Loss Contingencies [Line Items]
Natural gas cost under recovery	485	0
SOUTHERN Co GAS | Other regulatory liabilities
Loss Contingencies [Line Items]
Natural gas cost under recovery	5	88
SOUTHERN Co GAS | Other regulatory assets, deferred
Loss Contingencies [Line Items]
Natural gas cost under recovery	119	0
SOUTHERN Co GAS | Other regulatory assets, current
Loss Contingencies [Line Items]
Natural gas cost under recovery	$ 485	$ 0

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Regulatory Matters - APC (Details) - USD ($)	3 Months Ended	6 Months Ended
	Dec. 31, 2021	Jun. 30, 2021	Apr. 15, 2021	Dec. 31, 2020
Public Utilities, General Disclosures [Line Items]
Construction work in progress		$ 9,264,000,000		$ 8,697,000,000
ALABAMA POWER CO
Public Utilities, General Disclosures [Line Items]
Construction work in progress		978,000,000		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 | Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Natural disaster reserve, expected recovery amount	$ 4,000,000
ALABAMA POWER CO | Plant Barry Unit 8
Public Utilities, General Disclosures [Line Items]
Construction work in progress		188,000,000
MISSISSIPPI POWER CO
Public Utilities, General Disclosures [Line Items]
Construction work in progress		$ 126,000,000		$ 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) $ in Millions	Jan. 01, 2021 USD ($)
GEORGIA POWER CO | 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 - Plant Vogtle Unit 3 - USD ($) $ in Millions	Jun. 15, 2021	Jun. 30, 2021
Public Utilities, General Disclosures [Line Items]
Requested revenues increase amount	$ 2,380
Requested rate increase, annual amount	370
Decrease in tariff	116
Fuel cost recovery balance		$ 45
Requested financing costs deferred, amount	$ 42

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Regulatory Matters - GPC Deferral of Incremental COVID-19 Costs (Details) - GEORGIA POWER CO $ in Millions	1 Months Ended
	Jun. 30, 2021 USD ($)
Public Utilities, General Disclosures [Line Items]
Decrease in incremental COVID-19 costs deferred	$ 20
Incremental COVID-19 costs deferred	20
Incremental COVID-19 costs deferred, bad debt costs	2
Incremental COVID-19 costs deferred, other	$ 18

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Regulatory Matters - GPC Nuclear Construction (Details) $ in Millions	3 Months Ended			6 Months Ended		12 Months Ended
	Jun. 30, 2021 USD ($)	Mar. 31, 2021 USD ($)	Jun. 30, 2020 USD ($)	Jun. 30, 2021 USD ($)	Jun. 30, 2020 USD ($)	Dec. 31, 2012 utility MW	Aug. 31, 2018
Loss Contingencies [Line Items]
Estimated loss on Plant Vogtle Units 3 and 4	$ 460		$ 149	$ 508	$ 149
GEORGIA POWER CO
Loss Contingencies [Line Items]
Estimated loss on Plant Vogtle Units 3 and 4	460	$ 48	149	508	149
Estimated loss on Plant Vogtle Units 3 and 4, net of tax	$ 343	36	$ 111	$ 379	$ 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	2,700			2,700
Construction contingency estimate	341	84		341
Construction contingency estimate, additional amount	119	$ 48		119
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 - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Loss Contingencies [Line Items]
Base project capital cost forecast	$ 9,096
Construction contingency estimate	119
Total project capital cost forecast	9,215
Net investment as of end of the period	(7,856)
Remaining estimate to complete	1,359
Estimated cost to complete, costs not shared with other owners	570
Expected capitalized costs	290
Capitalized interest accrued	143
Twenty Third Vogtle Construction Monitoring Report
Loss Contingencies [Line Items]
Guarantor obligations	1,700	$ 1,700
Customer refund	$ 188	$ 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		6 Months Ended
	Jan. 11, 2018	Jun. 30, 2021	Aug. 31, 2018
Public Utilities, General Disclosures [Line Items]
Production tax credits, aggregate purchase price, maximum		$ 300
Preliminary estimated cost to complete		$ 9,215
Additional construction capital costs	$ 3,300
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
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 | 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					1 Months Ended	6 Months Ended		12 Months Ended
	Jan. 01, 2021	Jan. 01, 2020	Jan. 11, 2018 USD ($)	Jan. 01, 2016	Nov. 30, 2020 USD ($)	Jun. 30, 2021 USD ($)	Jun. 30, 2020 USD ($) report	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2013
Public Utilities, General Disclosures [Line Items]
Estimated in-service capital cost												$ 4,418
Financing costs collected, net of tax						$ 2,600
Cost settlement agreement revised forecast, net of payments			$ 7,300
Requested decrease in tariff					$ 142
Additional construction capital costs			3,300
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
Twenty Third Vogtle Construction Monitoring Report
Public Utilities, General Disclosures [Line Items]
Number of approved construction management reports | report							23
Requested capital construction costs							$ 8,700
Guarantor obligations						$ 1,700	1,700
Customer refund						$ 188	$ 188
Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Return on equity reduction, negative impact on earnings								$ 90	$ 270	$ 270

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Regulatory Matters - MPC (Details) - MISSISSIPPI POWER CO $ in Millions	Jun. 08, 2021 USD ($)	Apr. 06, 2021 USD ($)	Jun. 30, 2021 USD ($)	Apr. 15, 2021 MW	Dec. 31, 2020 MW
Loss Contingencies [Line Items]
Approved rate increase | $	$ 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
Environmental Compliance Overview Plan
Loss Contingencies [Line Items]
Approved rate increase | $	$ 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 | $			$ 522

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Regulatory Matters - GAS Narrative (Details) $ in Millions	Jul. 21, 2021 USD ($)	May 10, 2021 USD ($)	Apr. 28, 2021 USD ($)	Nov. 01, 2020 USD ($)	Apr. 06, 2021 mi
Virginia Natural Gas
Loss Contingencies [Line Items]
Motion filed to withdraw project application, header improvement project, scope of project (in miles) | mi					9.5
Approved rate increase		$ 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%
Requested revenues increase amount				$ 50
Atlanta Gas Light
Loss Contingencies [Line Items]
Integrated capacity delivery plan, capital budgets and related operations and maintenance spending, term			10 years
Atlanta Gas Light | Minimum
Loss Contingencies [Line Items]
Integrated capacity delivery plan, capital forecast plan, amount, years one through three			$ 500
Atlanta Gas Light | Maximum
Loss Contingencies [Line Items]
Integrated capacity delivery plan, capital forecast plan, amount, years one through three			$ 600
Atlanta Gas Light | Subsequent Event
Loss Contingencies [Line Items]
Approved rate increase	$ 49

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Regulatory Matters - GAS Schedule of Infrastructure Replacement Programs and Capital Projects (Details) - SOUTHERN Co GAS $ in Millions	6 Months Ended
	Jun. 30, 2021 USD ($)
Public Utilities, General Disclosures [Line Items]
Capital expenditures	$ 201
Investing in Illinois
Public Utilities, General Disclosures [Line Items]
Capital expenditures	179
Steps to Advance Virginia's Energy
Public Utilities, General Disclosures [Line Items]
Capital expenditures	$ 22

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Contingencies - General Litigation Matters (Details) - Pending Litigation $ in Millions	1 Months Ended	12 Months Ended
	Mar. 31, 2019 plaintiff	Dec. 31, 2018 USD ($) defendant plaintiff	Dec. 31, 2017 claim
Shareholder Derivative Lawsuits
Loss Contingencies [Line Items]
Pending number of claims | claim			2
Stay period		30 days
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	Jun. 30, 2021	Dec. 31, 2020
GEORGIA POWER CO
Loss Contingencies [Line Items]
Environmental remediation liability, current and former sites	$ 15	$ 15
SOUTHERN Co GAS
Loss Contingencies [Line Items]
Environmental remediation liability, current and former sites	$ 247	$ 245

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Contingencies - Other Matters (Details) $ in Millions	6 Months Ended
	Jun. 30, 2021 USD ($)	Jun. 30, 2020 USD ($)	Jan. 30, 2020 mi
SOUTHERN Co GAS
Loss Contingencies [Line Items]
Asset impairment charges	$ 82	$ 0
Asset impairment charges, net of tax	$ 58
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
Ownership percentage, equity method investment	20.00%
SOUTHERN Co GAS | SNG
Loss Contingencies [Line Items]
Ownership percentage, equity method investment	50.00%
Commitment to fund contingent capital contribution	$ 150
SNG
Loss Contingencies [Line Items]
Debt maturing in June 2021	$ 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		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	$ 5,422	$ 4,765	$ 12,319	$ 10,053
Total operating revenues	5,198	4,620	11,108	9,638
Retail electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	3,396	3,198	6,674	6,417
Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,469	1,430	2,936	2,801
Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,176	1,103	2,294	2,247
Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	728	642	1,397	1,323
Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	23	23	47	46
Natural gas distribution revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	698	585	1,883	1,584
Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	311	239	925	736
Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	73	58	243	188
Transportation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	247	234	536	499
Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	8	5	24	17
Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	59	49	155	144
Wholesale electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	382	325	778	639
PPA energy revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	209	167	422	326
PPA capacity revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	118	108	237	213
Non-PPA revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	55	50	119	100
Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	651	406	2,442	972
Wholesale gas services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	578	341	2,168	737
Gas marketing services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	63	57	257	220
Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	10	8	17	15
Other revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	295	251	542	441
Other revenue sources
Disaggregation of Revenue [Line Items]
Other revenues	1,179	728	2,488	1,599
Other adjustments
Disaggregation of Revenue [Line Items]
Other revenues	(1,403)	(873)	(3,699)	(2,014)
ALABAMA POWER CO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,421	1,312	2,895	2,663
Total operating revenues	1,556	1,365	3,115	2,716
ALABAMA POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,277	1,210	2,602	2,454
ALABAMA POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	553	549	1,181	1,103
ALABAMA POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	386	353	758	717
ALABAMA POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	334	302	654	623
ALABAMA POWER CO | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	4	6	9	11
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	92	58	196	131
ALABAMA POWER CO | PPA energy revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	38	28	81	55
ALABAMA POWER CO | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	29	25	58	52
ALABAMA POWER CO | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	25	5	57	24
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	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	52	44	97	78
ALABAMA POWER CO | Other revenue sources
Disaggregation of Revenue [Line Items]
Other revenues	135	53	220	53
ALABAMA POWER CO | Other adjustments
Disaggregation of Revenue [Line Items]
Other revenues	0	0	0	0
GEORGIA POWER CO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	2,084	1,935	3,995	3,830
Total operating revenues	2,225	1,928	4,195	3,754
GEORGIA POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,914	1,794	3,677	3,572
GEORGIA POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	852	817	1,627	1,577
GEORGIA POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	724	689	1,410	1,409
GEORGIA POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	321	273	606	555
GEORGIA POWER CO | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	17	15	34	31
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	33	22	69	44
GEORGIA POWER CO | PPA energy revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	16	7	30	15
GEORGIA POWER CO | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	14	13	27	25
GEORGIA POWER CO | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	3	2	12	4
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	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	137	119	249	214
GEORGIA POWER CO | Other revenue sources
Disaggregation of Revenue [Line Items]
Other revenues	141	(7)	200	(76)
GEORGIA POWER CO | Other adjustments
Disaggregation of Revenue [Line Items]
Other revenues	0	0	0	0
MISSISSIPPI POWER CO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	290	276	582	552
Total operating revenues	303	283	610	559
MISSISSIPPI POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	205	194	395	391
MISSISSIPPI POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	64	64	128	121
MISSISSIPPI POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	66	61	126	121
MISSISSIPPI POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	73	67	137	145
MISSISSIPPI POWER CO | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	2	2	4	4
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	78	76	173	148
MISSISSIPPI POWER CO | PPA energy revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	2	2	7	4
MISSISSIPPI POWER CO | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1	1	4	2
MISSISSIPPI POWER CO | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	75	73	162	142
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	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	7	6	14	13
MISSISSIPPI POWER CO | Other revenue sources
Disaggregation of Revenue [Line Items]
Other revenues	13	7	28	7
MISSISSIPPI POWER CO | Other adjustments
Disaggregation of Revenue [Line Items]
Other revenues	0	0	0	0
SOUTHERN POWER CO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	316	268	611	519
Total operating revenues	490	439	930	814
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	311	264	602	512
SOUTHERN POWER CO | PPA energy revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	158	134	313	259
SOUTHERN POWER CO | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	75	71	150	136
SOUTHERN POWER CO | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	78	59	139	117
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	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	5	4	9	7
SOUTHERN POWER CO | Other revenue sources
Disaggregation of Revenue [Line Items]
Other revenues	174	171	319	295
SOUTHERN POWER CO | Other adjustments
Disaggregation of Revenue [Line Items]
Other revenues	0	0	0	0
SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,349	991	4,325	2,556
Total operating revenues	677	636	2,371	1,885
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	698	585	1,883	1,584
SOUTHERN Co GAS | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	311	239	925	736
SOUTHERN Co GAS | Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	73	58	243	188
SOUTHERN Co GAS | Transportation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	247	234	536	499
SOUTHERN Co GAS | Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	8	5	24	17
SOUTHERN Co GAS | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	59	49	155	144
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	651	406	2,442	972
SOUTHERN Co GAS | Wholesale gas services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	578	341	2,168	737
SOUTHERN Co GAS | Gas marketing services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	63	57	257	220
SOUTHERN Co GAS | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	10	8	17	15
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	731	518	1,745	1,343
SOUTHERN Co GAS | Other adjustments
Disaggregation of Revenue [Line Items]
Other revenues	$ (1,403)	$ (873)	$ (3,699)	$ (2,014)

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Revenue from Contracts with Customers and Lease Income - Schedule of Contract Balances (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Disaggregation of Revenue [Line Items]
Accounts Receivable	$ 2,271	$ 2,614
Contract Assets	98	158
Contract Liabilities	67	61
ALABAMA POWER CO
Disaggregation of Revenue [Line Items]
Accounts Receivable	633	632
Contract Assets	0	2
Contract Liabilities	5	6
GEORGIA POWER CO
Disaggregation of Revenue [Line Items]
Accounts Receivable	887	806
Contract Assets	36	71
Contract Liabilities	37	27
MISSISSIPPI POWER CO
Disaggregation of Revenue [Line Items]
Accounts Receivable	85	77
Contract Assets	0	0
Contract Liabilities	1	1
SOUTHERN POWER CO
Disaggregation of Revenue [Line Items]
Accounts Receivable	129	112
Contract Assets	1	0
Contract Liabilities	1	1
SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Accounts Receivable	368	788
Contract Assets	0	0
Contract Liabilities	$ 0	$ 1

XML

Revenue from Contracts with Customers and Lease Income - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2021	Dec. 31, 2020
Disaggregation of Revenue [Line Items]
Contract assets	$ 98	$ 98	$ 158
Contract liabilities	67	67	61
Revenue from contracts with customers recognized	12	21
Unregulated Distributed Generation
Disaggregation of Revenue [Line Items]
Contract assets	60	60	81
Contract liabilities	24	24	27
GEORGIA POWER CO
Disaggregation of Revenue [Line Items]
Contract assets	36	36	71
Contract liabilities	37	37	27
MISSISSIPPI POWER CO
Disaggregation of Revenue [Line Items]
Contract assets	0	0	0
Contract liabilities	1	1	$ 1
Sales-type lease, lease receivable	35	$ 35
Transfer of construction work in progress to lease receivables	$ 35

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Revenue from Contracts with Customers and Lease Income - Schedule of Remaining Performance Obligations (Details) $ in Millions	Jun. 30, 2021 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 354
Performance obligation, expected timing of satisfaction	6 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	$ 464
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	$ 343
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]: 2021-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 23
Performance obligation, expected timing of satisfaction	6 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	$ 31
Performance obligation, expected timing of satisfaction	1 year
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 24
Performance obligation, expected timing of satisfaction	1 year
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 7
Performance obligation, expected timing of satisfaction	1 year
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 5
Performance obligation, expected timing of satisfaction	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]: 2021-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 41
Performance obligation, expected timing of satisfaction	6 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	$ 58
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	$ 39
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]: 2021-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 165
Performance obligation, expected timing of satisfaction	6 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		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	$ 4	$ 3	$ 7	$ 6
Lease income - operating leases	56	47	112	97
Variable lease income	128	126	212	200
Total lease income	188	176	331	303
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	6	41	13
Variable lease income	(1)	0	0	0
Total lease income	20	6	41	13
GEORGIA POWER CO
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	0	0	0	0
Lease income - operating leases	10	15	21	30
Variable lease income	0	0	0	0
Total lease income	10	15	21	30
MISSISSIPPI POWER CO
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	4	3	7	5
Lease income - operating leases	0	0	1	0
Variable lease income	0	0	0	0
Total lease income	4	3	8	5
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	42	45
Variable lease income	138	136	228	215
Total lease income	159	157	270	260
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	17	17
Variable lease income	0	0	0	0
Total lease income	$ 9	$ 9	$ 17	$ 17

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Consolidated Entities and Equity Method Investments - Narrative (Details) $ in Millions	6 Months Ended
	Jun. 30, 2021 USD ($) investor	Dec. 31, 2020 USD ($)
Schedule of Equity Method Investments [Line Items]
Assets	$ 125,907	$ 122,935
Liabilities	92,870	90,410
Equity method investments	494	398
SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Assets	13,708	13,235
Liabilities	7,018	6,604
Equity method investments	$ 84	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	382	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	140	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	249	110
Noncontrolling interests related to other partners' interests	$ 913	$ 454

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Consolidated Entities and Equity Method Investments - Schedule of Equity Method Investments (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
Schedule of Equity Method Investments [Line Items]
Investment Balance	$ 1,287		$ 1,362
SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Investment Balance	1,189		1,290
Asset impairment charges	82	$ 0
Asset impairment charges, net of tax	58
SOUTHERN Co GAS | SNG
Schedule of Equity Method Investments [Line Items]
Investment Balance	1,143		1,167
SOUTHERN Co GAS | PennEast Pipeline
Schedule of Equity Method Investments [Line Items]
Investment Balance	13		91
SOUTHERN Co GAS | Other
Schedule of Equity Method Investments [Line Items]
Investment Balance	$ 33		$ 32

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Consolidated Entities and Equity Method Investments - Schedule of Earnings from Equity Method Investments (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Schedule of Equity Method Investments [Line Items]
Earnings (Loss) from Equity Method Investments	$ (40)	$ 30	$ 5	$ 72
SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Earnings (Loss) from Equity Method Investments	(52)	30	(11)	72
Asset impairment charges			82	0
Asset impairment charges, net of tax			58
SOUTHERN Co GAS | SNG
Schedule of Equity Method Investments [Line Items]
Earnings (Loss) from Equity Method Investments	28	28	66	65
SOUTHERN Co GAS | PennEast Pipeline
Schedule of Equity Method Investments [Line Items]
Earnings (Loss) from Equity Method Investments	(81)	1	(79)	3
SOUTHERN Co GAS | Other
Schedule of Equity Method Investments [Line Items]
Earnings (Loss) from Equity Method Investments	$ 1	$ 1	$ 2	$ 4

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Financing - Schedule of Credit Arrangements (Details) - USD ($)	Jun. 30, 2021	May 31, 2021	Apr. 30, 2021
Line of Credit Facility [Line Items]
Expires, 2021	$ 3,000,000
Expires, 2022	805,000,000
Expires, 2023	125,000,000
Expires, 2024	150,000,000
Expires, 2026	6,550,000,000
Total	7,633,000,000
Unused	7,550,000,000
Due within One Year	283,000,000
Southern Company parent
Line of Credit Facility [Line Items]
Expires, 2021	0
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, 2021	3,000,000
Expires, 2022	525,000,000
Expires, 2023	0
Expires, 2024	0
Expires, 2026	700,000,000
Total	1,228,000,000	$ 700,000,000	$ 800,000,000
Unused	1,228,000,000
Due within One Year	3,000,000
GEORGIA POWER CO
Line of Credit Facility [Line Items]
Expires, 2021	0
Expires, 2022	0
Expires, 2023	0
Expires, 2024	0
Expires, 2026	1,750,000,000
Total	1,750,000,000
Unused	1,728,000,000
Due within One Year	0
MISSISSIPPI POWER CO
Line of Credit Facility [Line Items]
Expires, 2021	0
Expires, 2022	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, 2021	0
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, 2021	0
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, 2021	0
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

XML

Financing - Narrative (Details) - USD ($)	Jun. 30, 2021	May 31, 2021	Apr. 30, 2021
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 7,633,000,000
Line of credit expiring in 2022	805,000,000
Variable rate pollution control revenue bonds outstanding	1,400,000,000
ALABAMA POWER CO
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	1,228,000,000	$ 700,000,000	$ 800,000,000
Line of credit expiring in 2022	525,000,000
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
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
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
Variable rate pollution control revenue bonds outstanding	550,000,000
Fixed rate pollution control revenue bonds outstanding	$ 105,000,000

XML

Financing - Schedule of Shares Used to Compute Diluted Earnings Per Share (Details) - shares shares in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Debt Disclosure [Abstract]
As reported shares (in shares)	1,061	1,058	1,060	1,057
Effect of stock-based compensation (in shares)	6	5	6	7
Effect of equity units (in shares)	0	0	0	1
Diluted shares (in shares)	1,067	1,063	1,066	1,065

XML

Income Taxes (Details) - USD ($) $ in Billions	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
ITC and PTC carryforwards
Income Tax Contingency [Line Items]
Deferred tax assets	$ 1.3		$ 1.4
GEORGIA POWER CO
Income Tax Contingency [Line Items]
Effective tax (benefit) rate	(6.90%)	4.00%
SOUTHERN POWER CO
Income Tax Contingency [Line Items]
Effective tax (benefit) rate	(12.80%)	10.50%

XML

Retirement Benefits (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 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	108,000,000	$ 94,000,000	217,000,000	$ 188,000,000
Interest cost	86,000,000	108,000,000	173,000,000	216,000,000
Expected return on plan assets	(297,000,000)	(275,000,000)	(595,000,000)	(550,000,000)
Amortization:
Prior service costs	0	0	0	1,000,000
Regulatory asset	0	0	0	0
Net (gain)/loss	79,000,000	67,000,000	157,000,000	134,000,000
Net periodic pension cost (income)	(24,000,000)	(6,000,000)	(48,000,000)	(11,000,000)
Pension Plans | ALABAMA POWER CO
Pension Plans and Postretirement Plans
Service cost	25,000,000	22,000,000	51,000,000	44,000,000
Interest cost	21,000,000	25,000,000	41,000,000	50,000,000
Expected return on plan assets	(71,000,000)	(66,000,000)	(143,000,000)	(132,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain)/loss	20,000,000	18,000,000	41,000,000	36,000,000
Net periodic pension cost (income)	(5,000,000)	(1,000,000)	(10,000,000)	(2,000,000)
Pension Plans | GEORGIA POWER CO
Pension Plans and Postretirement Plans
Service cost	28,000,000	24,000,000	56,000,000	48,000,000
Interest cost	26,000,000	34,000,000	52,000,000	67,000,000
Expected return on plan assets	(94,000,000)	(87,000,000)	(188,000,000)	(174,000,000)
Amortization:
Prior service costs	1,000,000	1,000,000	1,000,000	1,000,000
Regulatory asset	0	0	0	0
Net (gain)/loss	25,000,000	21,000,000	50,000,000	43,000,000
Net periodic pension cost (income)	(14,000,000)	(7,000,000)	(29,000,000)	(15,000,000)
Pension Plans | MISSISSIPPI POWER CO
Pension Plans and Postretirement Plans
Service cost	5,000,000	4,000,000	9,000,000	8,000,000
Interest cost	4,000,000	5,000,000	8,000,000	10,000,000
Expected return on plan assets	(13,000,000)	(12,000,000)	(27,000,000)	(25,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain)/loss	3,000,000	3,000,000	7,000,000	6,000,000
Net periodic pension cost (income)	(1,000,000)	0	(3,000,000)	(1,000,000)
Pension Plans | SOUTHERN POWER CO
Pension Plans and Postretirement Plans
Service cost	3,000,000	2,000,000	5,000,000	4,000,000
Interest cost	1,000,000	2,000,000	2,000,000	3,000,000
Expected return on plan assets	(4,000,000)	(3,000,000)	(7,000,000)	(6,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain)/loss	1,000,000	0	2,000,000	1,000,000
Net periodic pension cost (income)	1,000,000	1,000,000	2,000,000	2,000,000
Pension Plans | SOUTHERN Co GAS
Pension Plans and Postretirement Plans
Service cost	9,000,000	8,000,000	18,000,000	16,000,000
Interest cost	6,000,000	7,000,000	12,000,000	15,000,000
Expected return on plan assets	(22,000,000)	(20,000,000)	(43,000,000)	(39,000,000)
Amortization:
Prior service costs	0	0	(1,000,000)	(1,000,000)
Regulatory asset	4,000,000	4,000,000	8,000,000	8,000,000
Net (gain)/loss	3,000,000	3,000,000	6,000,000	5,000,000
Net periodic pension cost (income)	0	2,000,000	0	4,000,000
Postretirement Benefits
Pension Plans and Postretirement Plans
Service cost	6,000,000	6,000,000	12,000,000	11,000,000
Interest cost	9,000,000	14,000,000	17,000,000	27,000,000
Expected return on plan assets	(19,000,000)	(18,000,000)	(38,000,000)	(36,000,000)
Amortization:
Prior service costs	(1,000,000)	(1,000,000)	(1,000,000)	(1,000,000)
Regulatory asset	0	0	0	0
Net (gain)/loss	1,000,000	0	2,000,000	1,000,000
Net periodic pension cost (income)	(4,000,000)	1,000,000	(8,000,000)	2,000,000
Postretirement Benefits | ALABAMA POWER CO
Pension Plans and Postretirement Plans
Service cost	2,000,000	1,000,000	3,000,000	3,000,000
Interest cost	2,000,000	3,000,000	4,000,000	6,000,000
Expected return on plan assets	(7,000,000)	(7,000,000)	(14,000,000)	(14,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain)/loss	0	0	0	0
Net periodic pension cost (income)	(3,000,000)	(3,000,000)	(7,000,000)	(5,000,000)
Postretirement Benefits | GEORGIA POWER CO
Pension Plans and Postretirement Plans
Service cost	1,000,000	2,000,000	3,000,000	3,000,000
Interest cost	3,000,000	5,000,000	6,000,000	10,000,000
Expected return on plan assets	(6,000,000)	(6,000,000)	(13,000,000)	(13,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain)/loss	0	0	1,000,000	1,000,000
Net periodic pension cost (income)	(2,000,000)	1,000,000	(3,000,000)	1,000,000
Postretirement Benefits | MISSISSIPPI POWER CO
Pension Plans and Postretirement Plans
Service cost	0	1,000,000	0	1,000,000
Interest cost	1,000,000	1,000,000	1,000,000	1,000,000
Expected return on plan assets	(1,000,000)	(1,000,000)	(1,000,000)	(1,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain)/loss	0	0	0	0
Net periodic pension cost (income)	0	1,000,000	0	1,000,000
Postretirement Benefits | SOUTHERN POWER CO
Pension Plans and Postretirement Plans
Service cost	0	0	0	0
Interest cost	0	0	0	0
Expected return on plan assets	0	0	0	0
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain)/loss	0	0	0	0
Net periodic pension cost (income)	0	0	0	0
Postretirement Benefits | SOUTHERN Co GAS
Pension Plans and Postretirement Plans
Service cost	1,000,000	1,000,000	1,000,000	1,000,000
Interest cost	1,000,000	4,000,000	2,000,000	6,000,000
Expected return on plan assets	(2,000,000)	(2,000,000)	(4,000,000)	(4,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	1,000,000	1,000,000	3,000,000	3,000,000
Net (gain)/loss	0	(1,000,000)	(1,000,000)	(2,000,000)
Net periodic pension cost (income)	$ 1,000,000	$ 3,000,000	$ 1,000,000	$ 4,000,000

XML

Fair Value Measurements - Schedule of Assets and Liabilities Measured at Fair Value (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Assets:
Derivatives	$ 341	$ 281
Liabilities:
Derivatives	134	64
Collateral already posted, assets, aggregate fair value	41
Disposal Group, Held-for-sale, Not Discontinued Operations
Liabilities:
Assets held for sale	787	60
Disposal Group, Including Discontinued Operation, Liabilities	677	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Disposal Group, Held-for-sale, Not Discontinued Operations | Sequent
Liabilities:
Assets held for sale	626
Disposal Group, Including Discontinued Operation, Liabilities	657
Significant Other Observable Inputs (Level 2) | Disposal Group, Held-for-sale, Not Discontinued Operations | Sequent
Liabilities:
Assets held for sale	260
Disposal Group, Including Discontinued Operation, Liabilities	323
Significant Unobservable Inputs (Level 3) | Disposal Group, Held-for-sale, Not Discontinued Operations | Sequent
Liabilities:
Assets held for sale	28
Disposal Group, Including Discontinued Operation, Liabilities	10
ALABAMA POWER CO
Assets:
Derivatives	43	5
Liabilities:
Derivatives	0	0
GEORGIA POWER CO
Assets:
Derivatives	69	3
Investments in trusts	48
Liabilities:
Derivatives	0	1
MISSISSIPPI POWER CO
Assets:
Derivatives	41	2
Liabilities:
Derivatives	0	2
SOUTHERN POWER CO
Assets:
Derivatives	59	89
Liabilities:
Derivatives	10	26
SOUTHERN Co GAS
Assets:
Derivatives	116	162
Liabilities:
Derivatives	115	35
Collateral already posted, assets, aggregate fair value	41	$ 28
SOUTHERN Co GAS | Disposal Group, Held-for-sale, Not Discontinued Operations
Liabilities:
Assets held for sale	736
Disposal Group, Including Discontinued Operation, Liabilities	677
Fair Value, Measurements, Recurring
Assets:
Cash equivalents	1,052
Other investments	39
Total	4,770
Liabilities:
Contingent consideration	16
Total	1,042
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents	1,039
Other investments	9
Total	2,720
Liabilities:
Contingent consideration	0
Total	664
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents	13
Other investments	30
Total	1,920
Liabilities:
Contingent consideration	0
Total	352
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Cash equivalents	0
Other investments	0
Total	28
Liabilities:
Contingent consideration	16
Total	26
Fair Value, Measurements, Recurring | Net Asset Value as a Practical Expedient (NAV)
Assets:
Total	102
Fair Value, Measurements, Recurring | Energy-related derivatives
Assets:
Derivatives	1,120
Liabilities:
Derivatives	1,007
Fair Value, Measurements, Recurring | Energy-related derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	656
Liabilities:
Derivatives	664
Fair Value, Measurements, Recurring | Energy-related derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	436
Liabilities:
Derivatives	333
Fair Value, Measurements, Recurring | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	28
Liabilities:
Derivatives	10
Fair Value, Measurements, Recurring | Interest rate derivatives
Assets:
Derivatives	17
Liabilities:
Derivatives	9
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	17
Liabilities:
Derivatives	9
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	55
Liabilities:
Derivatives	10
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	55
Liabilities:
Derivatives	10
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	1,048
Fair Value, Measurements, Recurring | Domestic equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	812
Fair Value, Measurements, Recurring | Domestic equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	236
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	362
Fair Value, Measurements, Recurring | Foreign equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	171
Fair Value, Measurements, Recurring | Foreign equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	191
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	311
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	311
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	45
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	45
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	18
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	18
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	457
Fair Value, Measurements, Recurring | Corporate bonds | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	4
Fair Value, Measurements, Recurring | Corporate bonds | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	453
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	102
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	102
Fair Value, Measurements, Recurring | Other
Assets:
Investments in trusts	52
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	23
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	520
Other investments	30
Total	1,846
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents	507
Other investments	0
Total	1,141
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents	13
Other investments	30
Total	603
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	102
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Energy-related derivatives
Assets:
Derivatives	46
Liabilities:
Derivatives	3
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	46
Liabilities:
Derivatives	3
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Domestic equity
Assets:
Investments in trusts	679
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Domestic equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	453
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Domestic equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	226
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	171
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Foreign equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	171
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	4
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Corporate bonds | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	241
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	24
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	24
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	102
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	102
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:
Total	1,280
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Total	382
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Total	898
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Unobservable Inputs (Level 3)
Assets:
Total	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Energy-related derivatives
Assets:
Derivatives	73
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	73
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	360
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Domestic equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	359
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	188
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	188
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	289
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	289
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	44
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	44
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	212
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	212
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	68
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	68
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	46
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	23
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	455
Total	499
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents	455
Total	455
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents	0
Total	44
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	44
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	44
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	59
Liabilities:
Contingent consideration	16
Total	26
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	59
Liabilities:
Contingent consideration	0
Total	10
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	4
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Energy-related derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Energy-related derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	4
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Foreign currency derivatives
Assets:
Derivatives	55
Liabilities:
Derivatives	10
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	55
Liabilities:
Derivatives	10
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	987
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Total	656
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2)
Assets:
Total	303
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3)
Assets:
Total	28
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Energy-related derivatives
Assets:
Derivatives	953
Liabilities:
Derivatives	997
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Energy-related derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	656
Liabilities:
Derivatives	664
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Energy-related derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	269
Liabilities:
Derivatives	323
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	28
Liabilities:
Derivatives	10
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Interest rate derivatives
Assets:
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
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Interest rate derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	4
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Interest rate derivatives | Significant Unobservable Inputs (Level 3)
Assets:
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	18
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	18
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Pooled funds – fixed income | 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		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	$ 125	$ 223	$ 164	$ (23)
ALABAMA POWER CO
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	77	124	118	(42)
GEORGIA POWER CO
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	$ 48	$ 99	$ 46	$ 19

XML

Fair Value Measurements - Narrative (Details) $ in Millions	Jun. 30, 2021 USD ($) $ / MMBTU
ALABAMA POWER CO | Private equity
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair value	$ 102
Unfunded commitments	67
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Energy-related derivatives
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair value of derivatives	$ 18
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Energy-related derivatives | Forward Price | Valuation, Market Approach | Minimum
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Measurement input (usd per mmbtu) | $ / MMBTU	(0.06)
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Energy-related derivatives | Forward Price | Valuation, Market Approach | Maximum
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Measurement input (usd per mmbtu) | $ / MMBTU	0.38

XML

Fair Value Measurements - Schedule of Financial Instruments for which Carrying Amount did not Equal Fair Value (Details)	Jun. 30, 2021 USD ($)
Long-term debt, including securities due within one year:
Carrying amount	$ 50,400,000,000
Fair value	56,200,000,000
ALABAMA POWER CO
Long-term debt, including securities due within one year:
Carrying amount	9,300,000,000
Fair value	10,600,000,000
GEORGIA POWER CO
Long-term debt, including securities due within one year:
Carrying amount	13,500,000,000
Fair value	15,200,000,000
MISSISSIPPI POWER CO
Long-term debt, including securities due within one year:
Carrying amount	1,900,000,000
Fair value	2,100,000,000
SOUTHERN POWER CO
Long-term debt, including securities due within one year:
Carrying amount	4,000,000,000.0
Fair value	4,500,000,000
SOUTHERN Co GAS
Long-term debt, including securities due within one year:
Carrying amount	6,300,000,000
Fair value	$ 7,300,000,000

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	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2021
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	$ 28	$ 28
Instruments realized or otherwise settled during period	(4)	(6)
Changes in fair value	(6)	(4)
Ending balance	$ 18	$ 18

XML

Derivatives - Schedule of Energy-Related Derivatives (Details) - Energy-related, Natural Gas MMBTU in Millions	Jun. 30, 2021 MMBTU
Energy-related derivative contracts
Net Purchased mmBtu	978
ALABAMA POWER CO
Energy-related derivative contracts
Net Purchased mmBtu	73
GEORGIA POWER CO
Energy-related derivative contracts
Net Purchased mmBtu	125
MISSISSIPPI POWER CO
Energy-related derivative contracts
Net Purchased mmBtu	85
SOUTHERN POWER CO
Energy-related derivative contracts
Net Purchased mmBtu	9
SOUTHERN Co GAS
Energy-related derivative contracts
Net Purchased mmBtu	686
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Long
Energy-related derivative contracts
Derivative nonmonetary notional amount net long short position volume	4,600
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Short
Energy-related derivative contracts
Derivative nonmonetary notional amount net long short position volume	3,900

XML

Derivatives - Narrative (Details) MMBTU in Millions	6 Months Ended
	Jun. 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	44
Cash flow hedge gain (loss) to be reclassified within twelve months | $	$ (23,000,000)
Collateral already posted, assets, aggregate fair value | $	$ 41,000,000
ALABAMA POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	11
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	6
SOUTHERN POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	14
Parent Company and Southern Power
Derivative [Line Items]
Foreign currency cash flow hedge gain (loss) to be reclassified during next 12 months | $	$ 17,000,000
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 | $	$ 41,000,000	$ 28,000,000

XML

Derivatives - Schedule of Interest Rate Derivatives (Details) - Interest rate derivatives $ in Millions	6 Months Ended
	Jun. 30, 2021 USD ($)
Derivative [Line Items]
Notional Amount	$ 1,960
Fair Value Gain (Loss) at June 30, 2021	7
MISSISSIPPI POWER CO | Cash Flow Hedges of Existing Debt
Derivative [Line Items]
Notional Amount	$ 60
Weighted Average Interest Rate Paid	0.58%
Fair Value Gain (Loss) at June 30, 2021	$ 0
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 June 30, 2021	$ 0
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 June 30, 2021	$ 4
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 June 30, 2021	$ 3
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) - 6 months ended Jun. 30, 2021 - Cash Flow Hedges Of Existing Debt [Member] - Foreign currency derivatives € in Millions, $ in Millions	USD ($)	EUR (€)
Derivative [Line Items]
Pay Notional	$ 1,241
Receive Notional | €		€ 1,100
Fair Value Gain (Loss) at June 30, 2021	45
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 June 30, 2021	$ 27
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 June 30, 2021	$ 18

XML

Derivatives - Schedule of Derivative Category and Balance Sheet Location (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	$ 1,192	$ 810
Derivative asset, Gross amounts offset	(851)	(529)
Derivative asset, net amounts recognized in the balance sheets	341	281
Derivative liability, gross amount recognized	1,026	621
Derivative liability, Gross amounts offset	(892)	(557)
Derivative liability, net amounts recognized in the balance sheets	134	64
Collateral already posted, assets, aggregate fair value	41
Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	922	658
Derivative liability, gross amount recognized	997	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	8	388
Derivatives not designated as hedging instruments | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	7	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	0	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 not designated as hedging instruments | Energy-related derivatives | Assets held for sale, current
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	914	0
Derivatives not designated as hedging instruments | Energy-related derivatives | Liabilities held for sale, current
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	990	0
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	184	42
Derivative liability, gross amount recognized	10	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	130	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	2	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	54	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	8	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	86	110
Derivative liability, gross amount recognized	19	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	13	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	1	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	17	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	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 | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	27	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	10	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	28	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	0	0
ALABAMA POWER CO
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	46	12
Derivative asset, Gross amounts offset	(3)	(7)
Derivative asset, net amounts recognized in the balance sheets	43	5
Derivative liability, gross amount recognized	3	7
Derivative liability, Gross amounts offset	(3)	(7)
Derivative liability, net amounts recognized in the balance sheets	0	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	46	12
Derivative liability, gross amount recognized	3	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	31	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	1	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	15	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
GEORGIA POWER CO
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	73	15
Derivative asset, Gross amounts offset	(4)	(12)
Derivative asset, net amounts recognized in the balance sheets	69	3
Derivative liability, gross amount recognized	4	13
Derivative liability, Gross amounts offset	(4)	(12)
Derivative liability, net amounts recognized in the balance sheets	0	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	73	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	52	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	1	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	21	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	3	8
MISSISSIPPI POWER CO
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	44	9
Derivative asset, Gross amounts offset	(3)	(7)
Derivative asset, net amounts recognized in the balance sheets	41	2
Derivative liability, gross amount recognized	3	9
Derivative liability, Gross amounts offset	(3)	(7)
Derivative liability, net amounts recognized in the balance sheets	0	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	44	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	28	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	0	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	16	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	3	6
SOUTHERN POWER CO
Derivatives, Fair Value [Line Items]
Derivative asset, net amounts recognized in the balance sheets	59	89
Derivative liability, net amounts recognized in the balance sheets	10	26
SOUTHERN POWER CO | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	0	0
Derivative liability, gross amount recognized	0	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	0	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	0	1
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	59	89
Derivative liability, gross amount recognized	10	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	4	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 | Foreign currency derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	27	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	10	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	28	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	957	665
Derivative asset, Gross amounts offset	(841)	(503)
Derivative asset, net amounts recognized in the balance sheets	116	162
Derivative liability, gross amount recognized	997	566
Derivative liability, Gross amounts offset	(882)	(531)
Derivative liability, net amounts recognized in the balance sheets	115	35
Collateral already posted, assets, aggregate fair value	41	28
SOUTHERN Co GAS | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	922	658
Derivative liability, gross amount recognized	997	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	8	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	7	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	0	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 not designated as hedging instruments | Energy-related derivatives | Assets held for sale, current
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	914	0
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Liabilities held for sale, current
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	990	0
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	21	6
Derivative liability, gross amount recognized	0	1
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	19	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	0	1
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	2	0
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
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
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	14	1
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 | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	9	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	1	0
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
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	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	Jun. 30, 2021	Dec. 31, 2020
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	$ 166	$ 12
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)	120	12
Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	46	2
ALABAMA POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	44	6
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)	31	5
ALABAMA POWER CO | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	13	1
GEORGIA POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	69	2
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)	51	2
GEORGIA POWER CO | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	18	1
MISSISSIPPI POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	42	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)	28	1
MISSISSIPPI POWER CO | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	14	0
SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	11	4
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)	10	4
SOUTHERN Co GAS | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	$ 1	$ 0

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Derivatives - Schedule of Pre-Tax Effects of Cash Flow Hedging on AOCI (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	$ 19	$ 14	$ (21)	$ (99)
Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	16	(2)	20	(6)
Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	(1)	(1)	2	(28)
Foreign currency derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	4	17	(43)	(65)
Southern Power
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	9	15	(35)	(67)
Southern Power | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	5	(2)	8	(2)
Southern Power | Foreign currency derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	4	17	(43)	(65)
SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	11	(1)	12	(29)
SOUTHERN Co GAS | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	11	0	12	(4)
SOUTHERN Co GAS | Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	$ 0	$ (1)	$ 0	$ (25)

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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		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Derivative [Line Items]
Total cost of sales	$ 231	$ 144	$ 814	$ 583
Depreciation and amortization	891	873	1,762	1,730
Total interest expense, net of amounts capitalized	(450)	(444)	(901)	(900)
Total other income (expense), net	108	101	167	204
Cash Flow Hedging | Energy-related derivatives | Cost of Sales
Derivative [Line Items]
Gain (loss) on hedges	1	(1)	(2)	(8)
Cash Flow Hedging | Energy-related derivatives | Depreciation and Amortization
Derivative [Line Items]
Gain (loss) on hedges	1	(1)	4	(2)
Cash Flow Hedging | Interest rate derivatives | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	(7)	(6)	(14)	(13)
Cash Flow Hedging | Foreign currency derivatives | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	(6)	(6)	(12)	(12)
Cash Flow Hedging | Foreign currency derivatives | Other Income (Expense)
Derivative [Line Items]
Gain (loss) on hedges	17	27	(43)	(4)
Fair Value Hedging | Interest rate derivatives | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	(3)	1	(12)	30
SOUTHERN POWER CO
Derivative [Line Items]
Depreciation and amortization	132	121	251	239
Total interest expense, net of amounts capitalized	(37)	(38)	(75)	(77)
Total other income (expense), net	1	1	8	4
SOUTHERN POWER CO | Cash Flow Hedging | Energy-related derivatives | Depreciation and Amortization
Derivative [Line Items]
Gain (loss) on hedges	1	(1)	4	(2)
SOUTHERN POWER CO | Cash Flow Hedging | Foreign currency derivatives | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	(6)	(6)	(12)	(12)
SOUTHERN POWER CO | Cash Flow Hedging | Foreign currency derivatives | Other Income (Expense)
Derivative [Line Items]
Gain (loss) on hedges	$ 17	$ 27	$ (43)	$ (4)

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Derivatives - Schedule of Cumulative Basis Adjustments for Fair Value Hedges (Details) - Fair Value Hedging - USD ($) $ in Millions	Jun. 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	(1,883)	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	(492)	0
Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item	$ 3	$ 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		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	$ (94)	$ 19	$ (104)	$ 97
Natural gas revenues
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	(103)	14	(120)	84
Cost of natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	$ 9	$ 5	$ 16	$ 13

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Acquisitions and Dispositions - Schedule of Asset Acquisition (Details) - SOUTHERN POWER CO - Deuel Harvest $ in Millions		6 Months Ended
	Mar. 30, 2021 USD ($)	Jun. 30, 2021 MW
Business Acquisition [Line Items]
Approximate nameplate capacity (in MWs) | MW		300
Proceeds from tax equity transaction | $	$ 220
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) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
Business Acquisition [Line Items]
Construction work in progress	$ 9,264		$ 9,264		$ 8,697
Gain on equipment contribution	11	$ 0	54	$ 39
SOUTHERN POWER CO
Business Acquisition [Line Items]
Construction work in progress	250		250		$ 127
Gain on equipment contribution	0	$ 0	39	$ 39
SOUTHERN POWER CO | Series of Construction Projects
Business Acquisition [Line Items]
Construction work in progress	208		208
SOUTHERN POWER CO | Series of Construction Projects | Minimum
Business Acquisition [Line Items]
Estimated future construction payments	390		390
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 $ in Millions	1 Months Ended		3 Months Ended
	Aug. 31, 2021 MW	Jul. 28, 2021 USD ($)	Dec. 31, 2021 MW	Dec. 31, 2020
Subsequent Event
Business Acquisition [Line Items]
Proceeds from tax equity transaction | $		$ 11
Glass Sands | Glass Sands
Business Acquisition [Line Items]
Ownership percentage by parent				100.00%
Scenario, Forecast | Garland Solar Storage
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)	88
PPA Contract Period	20 years
Scenario, Forecast | Tranquillity Solar Storage
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)			72
PPA Contract Period			20 years
Scenario, Forecast | Glass Sands
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)			118
PPA Contract Period			12 years

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Acquisitions and Dispositions - Southern Company Gas Narrative (Details) - SOUTHERN Co GAS - Disposal Group, Disposed of by Sale $ in Millions	Jul. 01, 2021 USD ($)	Feb. 28, 2022 USD ($)	Jun. 30, 2021 USD ($)	Apr. 22, 2021 USD ($)	Mar. 31, 2020 payment
Sequent
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Guarantor obligations, current carrying value			$ 268
Guarantor obligations			$ 1,000
Sequent | Subsequent Event
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale price	$ 150
Gain on sale	$ 90
Pivotal LNG
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
Scenario, Forecast | Pivotal LNG
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	Jun. 30, 2021	Dec. 31, 2020
Assets Held for Sale:
Receivables – energy marketing	$ 486	$ 0
Natural gas for sale	90	0
Other current assets	76	0
Total property, plant, and equipment	11	8
Leveraged leases	45	52
Accumulated deferred income taxes	30	0
Other non-current assets	49	0
Total Assets Held for Sale	787	60
Liabilities Held for Sale:
Energy marketing trade payables	491	0
Other current liabilities	148	0
Other non-current liabilities	38	0
Total Liabilities Held for Sale	677	$ 0
SOUTHERN Co GAS
Assets Held for Sale:
Receivables – energy marketing	486
Natural gas for sale	90
Other current assets	76
Total property, plant, and equipment	5
Leveraged leases	0
Accumulated deferred income taxes	30
Other non-current assets	49
Total Assets Held for Sale	736
Liabilities Held for Sale:
Energy marketing trade payables	491
Other current liabilities	148
Other non-current liabilities	38
Total Liabilities Held for Sale	$ 677

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Segment and Related Information - Narrative (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021 USD ($) state	Jun. 30, 2020 USD ($)	Jun. 30, 2021 USD ($) state segment	Jun. 30, 2020 USD ($)
Segment Reporting Information [Line Items]
Number of states in which entity operates | state	3		3
Operating revenues	$ 5,422	$ 4,765	$ 12,319	$ 10,053
SOUTHERN POWER CO
Segment Reporting Information [Line Items]
Operating revenues	316	268	611	519
SOUTHERN POWER CO | Traditional Electric Operating Companies | Wholesale revenues, affiliates
Segment Reporting Information [Line Items]
Operating revenues	$ 112	92	$ 193	178
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Number of states in which entity operates | state	4		4
Operating revenues	$ 1,349	991	$ 4,325	2,556
Number of reportable segments | segment			4
SOUTHERN Co GAS | SOUTHERN POWER CO | Natural gas
Segment Reporting Information [Line Items]
Operating revenues	$ 6	$ 3	$ 18	$ 13
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%

XML

Segment and Related Information - Schedule of Financial Data for Business Segments (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2021	Mar. 31, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
Segment Reporting Information [Line Items]
Operating revenues	$ 5,198		$ 4,620	$ 11,108	$ 9,638
Segment net income (loss)	372		612	1,508	1,480
Goodwill	5,280			5,280		$ 5,280
Assets held for sale	787			787		60
Total assets	125,907			125,907		122,935
Estimated loss on Plant Vogtle Units 3 and 4	460		149	508	149
Impairment of leveraged leases	7		154	7	154
GEORGIA POWER CO
Segment Reporting Information [Line Items]
Operating revenues	2,225		1,928	4,195	3,754
Total assets	47,625			47,625		47,080
Estimated loss on Plant Vogtle Units 3 and 4	460	$ 48	149	508	149
Estimated loss on Plant Vogtle Units 3 and 4, net of tax	343	$ 36	111	379	111
SOUTHERN POWER CO
Segment Reporting Information [Line Items]
Operating revenues	490		439	930	814
Total assets	13,708			13,708		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	677		636	2,371	1,885
Segment net income (loss)	(65)		71	333	346
Goodwill	5,015			5,015		5,015
Assets held for sale	736			736		0
Total assets	23,235			23,235		22,630
Asset impairment charges				82	0
Asset impairment charges, net of tax				58
Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	4,407		3,884	8,524	7,579
Segment net income (loss)	547		708	1,400	1,425
Goodwill	2			2		2
Assets held for sale	2			2		5
Total assets	100,345			100,345		98,041
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	677		636	2,371	1,885
All Other
Segment Reporting Information [Line Items]
Impairment of leveraged leases	7		154	7	154
Impairment of leveraged lease, net of tax	6		74	6	74
Gas distribution operations | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Goodwill	4,034			4,034		4,034
Wholesale Gas Services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	(110)		(19)	188	32
Gas marketing services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Goodwill	981			981		981
Operating Segments | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	672		632	2,373	1,888
Segment net income (loss)	(62)		77	332	351
Total assets	24,030			24,030		23,040
Operating Segments | Traditional Electric Operating Companies | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	4,031		3,539	7,795	6,946
Segment net income (loss)	511		645	1,267	1,287
Goodwill	0			0		0
Assets held for sale	2			2		5
Total assets	87,330			87,330		85,486
Operating Segments | SOUTHERN POWER CO | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	490		439	930	814
Segment net income (loss)	36		63	133	138
Goodwill	2			2		2
Assets held for sale	0			0		0
Total assets	13,708			13,708		13,235
Operating Segments | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	677		636	2,371	1,885
Segment net income (loss)	(65)		71	333	346
Goodwill	5,015			5,015		5,015
Assets held for sale	736			736		0
Total assets	23,235			23,235		22,630
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues	154		135	288	248
Segment net income (loss)	(108)		(177)	(216)	(299)
Goodwill	263			263		263
Assets held for sale	49			49		55
Total assets	3,063			3,063		3,168
Operating Segments | All Other | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	11		8	18	16
Segment net income (loss)	(3)		(6)	1	(5)
Total assets	11,300			11,300		11,336
Operating Segments | Gas distribution operations | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	710		587	1,910	1,607
Segment net income (loss)	80		74	263	238
Total assets	20,245			20,245		19,090
Operating Segments | Gas Pipeline Investments | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	8		8	16	16
Segment net income (loss)	(36)		21	(7)	51
Total assets	1,492			1,492		1,597
Operating Segments | Wholesale Gas Services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	(110)		(19)	188	32
Segment net income (loss)	(112)		(23)	14	0
Total assets	807			807		850
Operating Segments | Gas marketing services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	64		56	259	233
Segment net income (loss)	6		5	62	62
Total assets	1,486			1,486		1,503
Eliminations
Segment Reporting Information [Line Items]
Operating revenues	(40)		(35)	(75)	(74)
Segment net income (loss)	(2)		10	(9)	8
Goodwill	0			0		0
Assets held for sale	0			0		0
Total assets	(736)			(736)		(904)
Eliminations | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	(6)		(4)	(20)	(19)
Segment net income (loss)	0		0	0	0
Total assets	(12,095)			(12,095)		(11,746)
Eliminations | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	(114)		(94)	(201)	(181)
Segment net income (loss)	0		$ 0	0	$ 0
Goodwill	0			0		0
Assets held for sale	0			0		0
Total assets	$ (693)			$ (693)		$ (680)

XML

Segment and Related Information - Schedule of Financial Data for Products and Services (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Concentration Risk [Line Items]
Operating revenues	$ 5,198	$ 4,620	$ 11,108	$ 9,638
Less Gross Gas Costs	231	144	814	583
Retail
Concentration Risk [Line Items]
Operating revenues	3,599	3,182	6,941	6,260
Wholesale
Concentration Risk [Line Items]
Operating revenues	546	472	1,091	889
Other
Concentration Risk [Line Items]
Operating revenues	175	168	346	320
Electric Utilities' Revenues
Concentration Risk [Line Items]
Operating revenues	4,407	3,884	8,524	7,579
Electric Utilities' Revenues | Retail
Concentration Risk [Line Items]
Operating revenues	3,599	3,182	6,941	6,260
Electric Utilities' Revenues | Wholesale
Concentration Risk [Line Items]
Operating revenues	546	472	1,091	889
Electric Utilities' Revenues | Other
Concentration Risk [Line Items]
Operating revenues	262	230	492	430
Southern Company Gas' Revenues
Concentration Risk [Line Items]
Operating revenues	677	636	2,371	1,885
Southern Company Gas' Revenues | Gas Distribution Operations
Concentration Risk [Line Items]
Operating revenues	706	583	1,898	1,596
Southern Company Gas' Revenues | Wholesale Gas Services
Concentration Risk [Line Items]
Operating revenues	(110)	(19)	188	32
Southern Company Gas' Revenues | Gas marketing services
Concentration Risk [Line Items]
Operating revenues	64	56	259	233
Southern Company Gas' Revenues | Other
Concentration Risk [Line Items]
Operating revenues	17	16	26	24
Southern Company Gas' Revenues
Concentration Risk [Line Items]
Operating revenues	677	636	2,371	1,885
Asset impairment charges			82	0
Asset impairment charges, net of tax			58
Southern Company Gas' Revenues | Wholesale Gas Services
Concentration Risk [Line Items]
Operating revenues	(110)	(19)	188	32
Less Gross Gas Costs	1,429	891	3,783	2,054
Third Party Gross Revenues | Southern Company Gas' Revenues | Wholesale Gas Services
Concentration Risk [Line Items]
Operating revenues	1,292	854	3,881	2,039
Intercompany Revenues | Southern Company Gas' Revenues | Wholesale Gas Services
Concentration Risk [Line Items]
Operating revenues	27	18	90	47
Total Gross Revenues | Southern Company Gas' Revenues | Wholesale Gas Services
Concentration Risk [Line Items]
Operating revenues	$ 1,319	$ 872	$ 3,971	$ 2,086