10-Q

    Table of Contents                                Index to Financial Statements

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2023

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 2017B 5.25% Junior Subordinated Notes due 2077	SOJC	NYSE
The Southern Company	Series 2020A 4.95% Junior Subordinated Notes due 2080	SOJD	NYSE
The Southern Company	Series 2020C 4.20% Junior Subordinated Notes due 2060	SOJE	NYSE
The Southern Company	Series 2021B 1.875% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2081	SO 81	NYSE
Georgia Power Company	Series 2017A 5.00% Junior Subordinated Notes due 2077	GPJA	NYSE
Southern Power Company	Series 2016B 1.850% Senior Notes due 2026	SO/26A	NYSE

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

Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit such files). Yes þ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

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

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

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

Registrant	Description of Common Stock	Shares Outstanding at September 30, 2023
The Southern Company	Par Value $5 Per Share	1,090,619,349
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	100
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	160
Item 4.	Controls and Procedures	160
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	161
Item 1A.	Risk Factors	161
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	161
Item 6.	Exhibits	161
	Signatures	164

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    Table of Contents                                Index to Financial Statements

DEFINITIONS

Term	Meaning
2022 ARP	Alternate Rate Plan approved by the Georgia PSC in 2022 for Georgia Power for the years 2023 through 2025
AFUDC	Allowance for funds used during construction
Alabama Power	Alabama Power Company
Amended and Restated Loan Guarantee Agreement	Loan guarantee agreement entered into by Georgia Power with the DOE in 2014, as amended and restated in March 2019, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4
ARO	Asset retirement obligation
ASU	Accounting Standards Update
Atlanta Gas Light	Atlanta Gas Light Company, a wholly-owned subsidiary of Southern Company Gas
Bechtel	Bechtel Power Corporation, the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4
Bechtel Agreement	The 2017 construction completion agreement between the Vogtle Owners and Bechtel
CCR	Coal combustion residuals
CCR Rule	Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015
Chattanooga Gas	Chattanooga Gas Company, a wholly-owned subsidiary of Southern Company Gas
Clean Air Act	Clean Air Act Amendments of 1990
COD	Commercial operation date
Contractor Settlement Agreement	The December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the Vogtle 3 and 4 Agreement
Cooperative Energy	Electric generation and transmission cooperative in Mississippi
COVID-19	The novel coronavirus disease declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention in March 2020
CWIP	Construction work in progress
Dalton	City of Dalton, Georgia, an incorporated municipality in the State of Georgia, acting by and through its Board of Water, Light, and Sinking Fund Commissioners
Dalton Pipeline	A pipeline facility in Georgia in which Southern Company Gas has a 50% undivided ownership interest
DOE	U.S. Department of Energy
ECO Plan	Mississippi Power's environmental compliance overview plan
ELG	Effluent limitations guidelines
Eligible Project Costs	Certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the loan guarantee program established under Title XVII of the Energy Policy Act of 2005
EPA	U.S. Environmental Protection Agency
EPC Contractor	Westinghouse and its affiliate, WECTEC Global Project Services Inc.; the former engineering, procurement, and construction contractor for Plant Vogtle Units 3 and 4
FASB	Financial Accounting Standards Board
FCC	Federal Communications Commission
FERC	Federal Energy Regulatory Commission
FFB	Federal Financing Bank
First Solar	First Solar Electric, LLC
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, 2022, as applicable
GAAP	U.S. generally accepted accounting principles

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DEFINITIONS

(continued)

Term	Meaning
Georgia Power	Georgia Power Company
GHG	Greenhouse gas
GRAM	Atlanta Gas Light's Georgia Rate Adjustment Mechanism
Guarantee Settlement Agreement	The June 9, 2017 settlement agreement between the Vogtle Owners and Toshiba related to certain payment obligations of the EPC Contractor guaranteed by Toshiba
Gulf Power	Gulf Power Company, until January 1, 2019 a wholly-owned subsidiary of Southern Company; effective January 1, 2021, Gulf Power Company merged with and into Florida Power and Light Company, with Florida Power and Light Company remaining as the surviving company
Heating Degree Days	A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Heating Season	The period from November through March when Southern Company Gas' natural gas usage and operating revenues are generally higher
HLBV	Hypothetical liquidation at book value
IGCC	Integrated coal gasification combined cycle, the technology originally approved for Mississippi Power's Kemper County energy facility
IIC	Intercompany Interchange Contract
Illinois Commission	Illinois Commerce Commission
IRP	Integrated resource plan
ITAAC	Inspections, Tests, Analyses, and Acceptance Criteria, standards established by the NRC
ITC	Investment tax credit
JEA	Jacksonville Electric Authority
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
LIFO	Last-in, first-out
LTSA	Long-term service agreement
MEAG Power	Municipal Electric Authority of Georgia
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal units
Moody's	Moody's Investors Service, Inc.
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 tariff
NDR	Alabama Power's Natural Disaster Reserve
Nicor Gas	Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas
N/M	Not meaningful
NRC	U.S. Nuclear Regulatory Commission
OCI	Other comprehensive income
OPC	Oglethorpe Power Corporation (an electric membership corporation)
PEP	Mississippi Power's Performance Evaluation Plan
PowerSecure	PowerSecure, Inc., a wholly-owned subsidiary of Southern Company
PPA	Power purchase agreements, as well as, for Southern Power, contracts for differences that provide the owner of a renewable facility a certain fixed price for the electricity sold to the grid
PSC	Public Service Commission
PTC	Production tax credit
Rate CNP	Alabama Power's Rate Certificated New Plant, consisting of Rate CNP New Plant, Rate CNP Compliance, Rate CNP PPA, and Rate CNP Depreciation
Rate ECR	Alabama Power's Rate Energy Cost Recovery

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DEFINITIONS

(continued)

Term	Meaning
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
SNG	Southern Natural Gas Company, L.L.C., a pipeline system in which Southern Company Gas has a 50% ownership interest
SOFR	Secured Overnight Financing Rate
Southern Company	The Southern Company
Southern Company Gas	Southern Company Gas and its subsidiaries
Southern Company Gas Capital	Southern Company Gas Capital Corporation, a 100%-owned subsidiary of Southern Company Gas
Southern Company power pool	The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations
Southern Company system	Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas, SEGCO, Southern Nuclear, SCS, Southern Communications Services, Inc., PowerSecure, and other subsidiaries
Southern Holdings	Southern Company Holdings, Inc., a wholly-owned subsidiary of Southern Company
Southern Linc	Southern Communications Services, Inc., a wholly-owned subsidiary of Southern Company, doing business as Southern Linc
Southern Nuclear	Southern Nuclear Operating Company, Inc., a wholly-owned subsidiary of Southern Company
Southern Power	Southern Power Company and its subsidiaries
SouthStar	SouthStar Energy Services, LLC (a Marketer), a wholly-owned subsidiary of Southern Company Gas
SP Solar	SP Solar Holdings I, LP, a limited partnership indirectly owning substantially all of Southern Power's solar and battery energy storage facilities, in which Southern Power has a 67% ownership interest
SP Wind	SP Wind Holdings II, LLC, a holding company owning a portfolio of eight operating wind facilities, in which Southern Power is the controlling partner in a tax equity arrangement
SRR	Mississippi Power's System Restoration Rider, a tariff for retail property damage cost recovery and reserve
Subsidiary Registrants	Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas
Toshiba	Toshiba Corporation, the parent company of Westinghouse
traditional electric operating companies	Alabama Power, Georgia Power, and Mississippi Power
VCM	Vogtle Construction Monitoring
VIE	Variable interest entity
Virginia Commission	Virginia State Corporation Commission
Virginia Natural Gas	Virginia Natural Gas, Inc., a wholly-owned subsidiary of Southern Company Gas
Vogtle 3 and 4 Agreement	Agreement entered into with the EPC Contractor in 2008 by Georgia Power, acting for itself and as agent for the Vogtle Owners, and rejected in bankruptcy in July 2017, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4

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DEFINITIONS

(continued)

Term	Meaning
Vogtle Owners	Georgia Power, OPC, 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

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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 regulated rates, the strategic goals for the business, customer and sales growth, economic conditions, including inflation, cost recovery and other rate actions, 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 extent and timing of costs and legal requirements related to CCR;

•current and future litigation or regulatory investigations, proceedings, or inquiries, including litigation and other disputes related to the Kemper County energy facility and Plant Vogtle Units 3 and 4;

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

•variations in demand for electricity and natural gas;

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

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

•transmission constraints;

•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 Unit 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), due to current and/or future challenges which include, but are not limited to, changes in labor costs, availability, and productivity; challenges with the 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; the impacts of inflation; delays due to judicial or regulatory action; nonperformance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems or any remediation related thereto; design and other licensing-based compliance matters; challenges with start-up activities, including major equipment failure, or system integration; and/or operational performance; continued challenges related to the COVID-19 pandemic or future pandemic health events; continued public and policymaker support for projects; environmental and geological conditions; delays or increased costs to interconnect facilities to transmission grids; and increased financing costs as a result of changes in market interest rates or as a result of project delays;

•the ability to overcome or mitigate the current challenges, or challenges yet to be identified, at Plant Vogtle Unit 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 past and ongoing construction projects, such as Plant Vogtle Units 3 and 4, 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 Unit 4 not to proceed with construction;

•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;

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

(continued)

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

•advances in technology, including the pace and extent of development of low- to no-carbon energy and battery energy storage technologies and negative carbon concepts;

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

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

•the ability to successfully operate the traditional electric operating companies' and SEGCO's generation, transmission, and distribution facilities, Southern Power's generation facilities, and Southern Company Gas' natural gas distribution and storage facilities and the successful performance of necessary corporate functions;

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

•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 cyber and physical attacks;

•global and U.S. economic conditions, including impacts from recession, inflation, 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;

•the ability of the traditional electric operating companies to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;

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

•the potential effects of COVID-19, including, but not limited to, those described in Item 1A "Risk Factors" of the Form 10-K;

•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 and 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	38
Condensed Consolidated Statements of Comprehensive Income	38
Condensed Consolidated Statements of Cash Flows	39
Condensed Consolidated Balance Sheets	40
Condensed Consolidated Statements of Stockholder's Equity	42
Combined Notes to the Condensed Financial Statements	43

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Operating Revenues:
Retail electric revenues	$	5,139	$	5,961	$	12,597	$	14,363
Wholesale electric revenues	727		1,197		1,930		2,798
Other electric revenues	203		185		602		554
Natural gas revenues (includes alternative revenue programs of     $—, $(1), $11, and $—, respectively)	689		857		3,417		3,998
Other revenues	222		178		662		519
Total operating revenues	6,980		8,378		19,208		22,232
Operating Expenses:
Fuel	1,367		2,423		3,376		5,249
Purchased power	207		645		680		1,285
Cost of natural gas	102		294		1,199		1,840
Cost of other sales	126		92		381		275
Other operations and maintenance	1,424		1,527		4,352		4,568
Depreciation and amortization	1,143		922		3,365		2,728
Taxes other than income taxes	341		352		1,076		1,073
Estimated loss on Plant Vogtle Units 3 and 4	160		(70)		160		(18)
Total operating expenses	4,870		6,185		14,589		17,000
Operating Income	2,110		2,193		4,619		5,232
Other Income and (Expense):
Allowance for equity funds used during construction	66		59		200		163
Earnings from equity method investments	32		28		110		109
Interest expense, net of amounts capitalized	(620)		(511)		(1,812)		(1,461)
Other income (expense), net	141		132		428		414
Total other income and (expense)	(381)		(292)		(1,074)		(775)
Earnings Before Income Taxes	1,729		1,901		3,545		4,457
Income taxes	297		414		492		891
Consolidated Net Income	1,432		1,487		3,053		3,566
Dividends on preferred stock of subsidiaries	—		3		—		10
Net income (loss) attributable to noncontrolling interests	10		12		(68)		(55)
Consolidated Net Income Attributable to    Southern Company	$	1,422	$	1,472	$	3,121	$	3,611
Common Stock Data:
Earnings per share -
Basic	$	1.30	$	1.36	$	2.86	$	3.38
Diluted	$	1.29	$	1.35	$	2.84	$	3.36
Average number of shares of common stock outstanding (in millions)
Basic	1,092		1,082		1,092		1,070
Diluted	1,099		1,088		1,098		1,076

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Consolidated Net Income	$	1,432	$	1,487	$	3,053	$	3,566
Other comprehensive income:
Qualifying hedges:
Changes in fair value, net of tax of     $3, $2, $(11), and $(5), respectively	2		—		(34)		(27)
Reclassification adjustment for amounts included in net income,    net of tax of $12, $8, $25, and $32, respectively	36		26		70		100
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income,    net of tax of $—, $1, $—, and $3, respectively	—		2		1		8
Total other comprehensive income	38		28		37		81
Comprehensive Income	1,470		1,515		3,090		3,647
Dividends on preferred stock of subsidiaries	—		3		—		10
Comprehensive income (loss) attributable to noncontrolling interests	10		12		(68)		(55)
Consolidated Comprehensive Income Attributable to    Southern Company	$	1,460	$	1,500	$	3,158	$	3,692

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2023		2022
	(in millions)
Operating Activities:
Consolidated net income	$	3,053	$	3,566
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	3,699		3,084
Deferred income taxes	(52)		608
Utilization of federal investment tax credits	195		266
Allowance for equity funds used during construction	(200)		(163)
Pension, postretirement, and other employee benefits	(397)		(322)
Settlement of asset retirement obligations	(444)		(314)
Stock based compensation expense	119		116
Estimated loss on Plant Vogtle Units 3 and 4	160		(18)
Storm damage accruals	41		160
Natural gas cost under recovery – long-term	—		207
Retail fuel cost under recovery – long-term	(157)		(1,701)
Other, net	(67)		(119)
Changes in certain current assets and liabilities —
-Receivables	524		(316)
-Retail fuel cost under recovery	513		(104)
-Fossil fuel for generation	(254)		(76)
-Materials and supplies	(271)		(138)
-Natural gas cost under recovery	108		(124)
-Other current assets	(32)		(310)
-Accounts payable	(1,031)		805
-Accrued taxes	376		167
-Accrued compensation	(197)		(123)
-Customer refunds	(177)		(52)
-Natural gas cost over recovery	165		—
-Other current liabilities	66		(82)
Net cash provided from operating activities	5,740		5,017
Investing Activities:
Property additions	(6,561)		(5,502)
Nuclear decommissioning trust fund purchases	(885)		(858)
Nuclear decommissioning trust fund sales	879		854
Proceeds from dispositions	165		120
Cost of removal, net of salvage	(421)		(518)
Change in construction payables, net	241		15
Other investing activities	(139)		(63)
Net cash used for investing activities	(6,721)		(5,952)
Financing Activities:
Decrease in notes payable, net	(298)		(349)
Proceeds —
Long-term debt	7,812		3,800
Short-term borrowings	250		1,200
Common stock	26		1,803
Redemptions and repurchases —
Long-term debt	(3,567)		(1,932)
Short-term borrowings	(850)		(900)
Capital contributions from noncontrolling interests	21		73
Distributions to noncontrolling interests	(148)		(175)
Payment of common stock dividends	(2,271)		(2,166)
Other financing activities	(141)		(235)
Net cash provided from financing activities	834		1,119
Net Change in Cash, Cash Equivalents, and Restricted Cash	(147)		184
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	2,037		1,829
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	1,890	$	2,013
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $97 and $74 capitalized for 2023 and 2022, respectively)	$	1,694	$	1,425
Income taxes, net	11		160
Noncash transactions —
Accrued property additions at end of period	1,224		872
Right-of-use assets obtained under operating leases	76		27
Right-of-use assets obtained under finance leases	3		114
Reassessment of right-of-use assets under operating leases	—		40

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2023		At December 31, 2022
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,676	$	1,917
Receivables —
Customer accounts	2,230		2,128
Unbilled revenues	547		1,012
Under recovered fuel clause revenues	757		10
Other accounts and notes	553		637
Accumulated provision for uncollectible accounts	(78)		(71)
Materials and supplies	1,913		1,664
Fossil fuel for generation	829		575
Natural gas for sale	406		438
Prepaid expenses	321		347
Assets from risk management activities, net of collateral	36		115
Regulatory assets – asset retirement obligations	358		332
Other regulatory assets	996		968
Other current assets	544		344
Total current assets	11,088		10,416
Property, Plant, and Equipment:
In service	125,573		117,529
Less: Accumulated depreciation	37,199		35,297
Plant in service, net of depreciation	88,374		82,232
Other utility plant, net	522		599
Nuclear fuel, at amortized cost	862		843
Construction work in progress	8,496		10,896
Total property, plant, and equipment	98,254		94,570
Other Property and Investments:
Goodwill	5,161		5,161
Nuclear decommissioning trusts, at fair value	2,207		2,145
Equity investments in unconsolidated subsidiaries	1,376		1,443
Other intangible assets, net of amortization of $367 and $340, respectively	377		406
Miscellaneous property and investments	651		602
Total other property and investments	9,772		9,757
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,467		1,531
Deferred charges related to income taxes	889		866
Prepaid pension costs	2,574		2,290
Unamortized loss on reacquired debt	224		238
Deferred under recovered fuel clause revenues	1,279		2,056
Regulatory assets – asset retirement obligations, deferred	5,629		5,764
Other regulatory assets, deferred	5,666		5,918
Other deferred charges and assets	1,479		1,485
Total deferred charges and other assets	19,207		20,148
Total Assets	$	138,321	$	134,891

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At September 30, 2023		At December 31, 2022
	(in millions)
Current Liabilities:
Securities due within one year	$	3,076	$	4,285
Notes payable	1,726		2,609
Accounts payable	2,942		3,525
Customer deposits	511		502
Accrued taxes —
Accrued income taxes	177		60
Other accrued taxes	862		764
Accrued interest	573		614
Accrued compensation	936		1,127
Asset retirement obligations	727		694
Liabilities from risk management activities, net of collateral	232		178
Operating lease obligations	181		197
Natural gas cost over recovery	165		—
Other regulatory liabilities	163		382
Other current liabilities	943		787
Total current liabilities	13,214		15,724
Long-term Debt	56,003		50,656
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	10,774		10,036
Deferred credits related to income taxes	4,813		5,235
Accumulated deferred ITCs	2,071		2,133
Employee benefit obligations	1,184		1,238
Operating lease obligations, deferred	1,320		1,388
Asset retirement obligations, deferred	9,872		10,146
Other cost of removal obligations	1,940		1,903
Other regulatory liabilities, deferred	660		733
Other deferred credits and liabilities	1,166		1,167
Total deferred credits and other liabilities	33,800		33,979
Total Liabilities	103,017		100,359
Total Stockholders' Equity (See accompanying statements)	35,304		34,532
Total Liabilities and Stockholders' Equity	$	138,321	$	134,891

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, 2021	1,061	(1)	$	5,279	$	11,950	$	(47)	$	10,929	$	(237)	$	4,402	$	32,276
Consolidated net income (loss)	—	—	—		—		—		1,032		—		(45)		987
Other comprehensive income	—	—	—		—		—		—		42		—		42
Stock issued	3	—	7		31		—		—		—		—		38
Stock-based compensation	—	—	—		6		—		—		—		—		6
Cash dividends of $0.66 per share	—	—	—		—		—		(702)		—		—		(702)
Capital contributions from    noncontrolling interests	—	—	—		—		—		—		—		73		73
Distributions to noncontrolling interests	—	—	—		—		—		—		—		(98)		(98)
Other	—	—	—		7		(2)		2		—		—		7
Balance at March 31, 2022	1,064	(1)	5,286		11,994		(49)		11,261		(195)		4,332		32,629
Consolidated net income (loss)	—	—	—		—		—		1,107		—		(22)		1,085
Other comprehensive income	—	—	—		—		—		—		11		—		11
Stock issued	—	—	2		21		—		—		—		—		23
Stock-based compensation	—	—	—		14		—		—		—		—		14
Cash dividends of $0.68 per share	—	—	—		—		—		(723)		—		—		(723)
Distributions to noncontrolling interests	—	—	—		—		—		—		—		(28)		(28)
Other	—	—	—		4		(2)		—		—		—		2
Balance at June 30, 2022	1,064	(1)	5,288		12,033		(51)		11,645		(184)		4,282		33,013
Consolidated net income	—	—	—		—		—		1,472		—		12		1,484
Other comprehensive income	—	—	—		—		—		—		28		—		28
Stock issued	26	—	129		1,613		—		—		—		—		1,742
Stock-based compensation	—	—	—		15		—		—		—		—		15
Cash dividends of $0.68 per share	—	—	—		—		—		(741)		—		—		(741)
Distributions to noncontrolling interests	—	—	—		—		—		—		—		(57)		(57)
Other	—	—	—		(4)		(1)		(2)		(1)		—		(8)
Balance at September 30, 2022	1,090	(1)	$	5,417	$	13,657	$	(52)	$	12,374	$	(157)	$	4,237	$	35,476

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	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, 2022	1,090	(1)	$	5,417	$	13,673	$	(53)	$	11,538	$	(167)	$	4,124	$	34,532
Consolidated net income (loss)	—	—	—		—		—		862		—		(63)		799
Other comprehensive income (loss)	—	—	—		—		—		—		(44)		—		(44)
Stock issued	2	—	4		11		—		—		—		—		15
Stock-based compensation	—	—	—		29		—		—		—		—		29
Cash dividends of $0.68 per share	—	—	—		—		—		(742)		—		—		(742)
Capital contributions from    noncontrolling interests	—	—	—		—		—		—		—		21		21
Distributions to noncontrolling interests	—	—	—		—		—		—		—		(48)		(48)
Other	—	—	—		2		(2)		—		—		—		—
Balance at March 31, 2023	1,092	(1)	5,421		13,715		(55)		11,658		(211)		4,034		34,562
Consolidated net income (loss)	—	—	—		—		—		838		—		(15)		823
Other comprehensive income	—	—	—		—		—		—		43		—		43
Stock issued	—	—	1		6		—		—		—		—		7
Stock-based compensation	—	—	—		19		—		—		—		—		19
Cash dividends of $0.70 per share	—	—	—		—		—		(764)		—		—		(764)
Distributions to noncontrolling interests	—	—	—		—		—		—		—		(42)		(42)
Other	—	—	—		2		(1)		—		—		(1)		—
Balance at June 30, 2023	1,092	(1)	5,422		13,742		(56)		11,732		(168)		3,976		34,648
Consolidated net income	—	—	—		—		—		1,422		—		10		1,432
Other comprehensive income	—	—	—		—		—		—		38		—		38
Stock issued	—	—	—		4		—		—		—		—		4
Stock-based compensation	—	—	—		7		—		—		—		—		7
Cash dividends of $0.70 per share	—	—	—		—		—		(765)		—		—		(765)
Distributions to noncontrolling interests	—	—	—		—		—		—		—		(59)		(59)
Other	—	—	—		(2)		(1)		2		—		—		(1)
Balance at September 30, 2023	1,092	(1)	$	5,422	$	13,751	$	(57)	$	12,391	$	(130)	$	3,927	$	35,304

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

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ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Operating Revenues:
Retail revenues	$	1,860	$	2,008	$	4,708	$	5,015
Wholesale revenues, non-affiliates	106		250		358		522
Wholesale revenues, affiliates	14		70		43		170
Other revenues	103		116		311		316
Total operating revenues	2,083		2,444		5,420		6,023
Operating Expenses:
Fuel	402		666		1,013		1,399
Purchased power, non-affiliates	42		185		197		347
Purchased power, affiliates	80		113		193		260
Other operations and maintenance	411		418		1,275		1,270
Depreciation and amortization	351		220		1,045		652
Taxes other than income taxes	110		106		333		309
Total operating expenses	1,396		1,708		4,056		4,237
Operating Income	687		736		1,364		1,786
Other Income and (Expense):
Allowance for equity funds used during construction	23		18		65		51
Interest expense, net of amounts capitalized	(104)		(98)		(311)		(278)
Other income (expense), net	38		38		117		101
Total other income and (expense)	(43)		(42)		(129)		(126)
Earnings Before Income Taxes	644		694		1,235		1,660
Income taxes	79		166		103		394
Net Income	565		528		1,132		1,266
Dividends on Preferred Stock	—		3		—		10
Net Income After Dividends on Preferred Stock	$	565	$	525	$	1,132	$	1,256

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Net Income	$	565	$	528	$	1,132	$	1,266
Other comprehensive income:
Qualifying hedges:
Changes in fair value, net of tax of     $—, $—, $—, and $—, respectively	—		1		1		(1)
Reclassification adjustment for amounts included in net income,    net of tax of $—, $—, $—, and $1, respectively	1		1		1		3
Total other comprehensive income	1		2		2		2
Comprehensive Income	$	566	$	530	$	1,134	$	1,268

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

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ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2023		2022
	(in millions)
Operating Activities:
Net income	$	1,132	$	1,266
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	1,158		817
Deferred income taxes	(210)		210
Pension, postretirement, and other employee benefits	(148)		(85)
Settlement of asset retirement obligations	(188)		(139)
Retail fuel cost under recovery – long-term	—		(413)
Other, net	(21)		(98)
Changes in certain current assets and liabilities —
-Receivables	(108)		(296)
-Fossil fuel stock	(113)		(40)
-Retail fuel cost under recovery	334		(93)
-Other current assets	(124)		(75)
-Accounts payable	(358)		(22)
-Accrued taxes	271		110
-Other current liabilities	(103)		(70)
Net cash provided from operating activities	1,522		1,072
Investing Activities:
Property additions	(1,377)		(1,483)
Nuclear decommissioning trust fund purchases	(226)		(273)
Nuclear decommissioning trust fund sales	226		273
Cost of removal, net of salvage	(128)		(163)
Change in construction payables	(68)		36
Other investing activities	27		(31)
Net cash used for investing activities	(1,546)		(1,641)
Financing Activities:
Proceeds —
Senior notes	200		1,700
Revenue bonds	326		—
Other long-term debt	28		—
Redemptions — Senior notes	—		(550)
Capital contributions from parent company	380		660
Payment of common stock dividends	(856)		(762)
Other financing activities	(12)		(81)
Net cash provided from financing activities	66		967
Net Change in Cash, Cash Equivalents, and Restricted Cash	42		398
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	687		1,060
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	729	$	1,458
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $21 and $14 capitalized for 2023 and 2022, respectively)	$	329	$	278
Income taxes, net	152		178
Noncash transactions —
Accrued property additions at end of period	114		186
Right-of-use assets obtained under operating leases	28		7
Right-of-use assets obtained under finance leases	3		2

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

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    Table of Contents                                Index to Financial Statements

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2023		At December 31, 2022
	(in millions)
Current Assets:
Cash and cash equivalents	$	621	$	687
Receivables —
Customer accounts	624		431
Unbilled revenues	162		174
Affiliated	113		101
Other accounts and notes	114		153
Accumulated provision for uncollectible accounts	(16)		(14)
Fossil fuel stock	342		229
Materials and supplies	624		557
Prepaid expenses	72		65
Other regulatory assets	549		474
Other current assets	171		67
Total current assets	3,376		2,924
Property, Plant, and Equipment:
In service	34,313		33,472
Less: Accumulated provision for depreciation	11,042		10,470
Plant in service, net of depreciation	23,271		23,002
Other utility plant, net	522		599
Nuclear fuel, at amortized cost	240		239
Construction work in progress	1,759		1,526
Total property, plant, and equipment	25,792		25,366
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,165		1,127
Equity investments in unconsolidated subsidiaries	53		57
Miscellaneous property and investments	156		124
Total other property and investments	1,374		1,308
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	88		71
Deferred charges related to income taxes	263		250
Prepaid pension and other postretirement benefit costs	735		657
Regulatory assets – asset retirement obligations	1,881		1,845
Other regulatory assets, deferred	1,706		2,107
Other deferred charges and assets	455		442
Total deferred charges and other assets	5,128		5,372
Total Assets	$	35,670	$	34,970

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 September 30, 2023		At December 31, 2022
	(in millions)
Current Liabilities:
Securities due within one year	$	522	$	301
Accounts payable —
Affiliated	305		443
Other	377		641
Customer deposits	105		106
Accrued taxes	305		57
Accrued interest	84		120
Accrued compensation	193		229
Asset retirement obligations	342		330
Other regulatory liabilities	28		96
Other current liabilities	158		91
Total current liabilities	2,419		2,414
Long-term Debt	10,661		10,329
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	4,082		3,981
Deferred credits related to income taxes	1,626		1,925
Accumulated deferred ITCs	76		81
Employee benefit obligations	146		145
Operating lease obligations	81		67
Asset retirement obligations, deferred	3,859		3,957
Other regulatory liabilities, deferred	284		315
Other deferred credits and liabilities	85		69
Total deferred credits and other liabilities	10,239		10,540
Total Liabilities	23,319		23,283
Common Stockholder's Equity (See accompanying statements)	12,351		11,687
Total Liabilities and Stockholder's Equity	$	35,670	$	34,970

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, 2021	31	$	1,222	$	6,056	$	3,448	$	(13)	$	10,713
Net income after dividends on    preferred stock	—	—		—		347		—		347
Capital contributions from parent company	—	—		626		—		—		626
Cash dividends on common stock	—	—		—		(254)		—		(254)
Balance at March 31, 2022	31	1,222		6,682		3,541		(13)		11,432
Net income after dividends on    preferred stock	—	—		—		383		—		383
Capital contributions from parent company	—	—		32		—		—		32
Other comprehensive income	—	—		—		—		1		1
Cash dividends on common stock	—	—		—		(254)		—		(254)
Balance at June 30, 2022	31	1,222		6,714		3,670		(12)		11,594
Net income after dividends on    preferred stock	—	—		—		525		—		525
Capital contributions from parent company	—	—		7		—		—		7
Other comprehensive income	—	—		—		—		2		2
Cash dividends on common stock	—	—		—		(254)		—		(254)
Balance at September 30, 2022	31	$	1,222	$	6,721	$	3,941	$	(10)	$	11,874
Balance at December 31, 2022	31	$	1,222	$	6,710	$	3,764	$	(9)	$	11,687
Net income after dividends on    preferred stock	—	—		—		255		—		255
Capital contributions from parent company	—	—		330		—		—		330
Cash dividends on common stock	—	—		—		(285)		—		(285)
Balance at March 31, 2023	31	1,222		7,040		3,734		(9)		11,987
Net income after dividends on    preferred stock	—	—		—		312		—		312
Capital contributions from parent company	—	—		29		—		—		29
Cash dividends on common stock	—	—		—		(286)		—		(286)
Balance at June 30, 2023	31	1,222		7,069		3,760		(9)		12,042
Net income after dividends on    preferred stock	—	—		—		565		—		565
Capital contributions from parent company	—	—		28		—		—		28
Other comprehensive income	—	—		—		—		1		1
Cash dividends on common stock	—	—		—		(285)		—		(285)
Balance at September 30, 2023	31	$	1,222	$	7,097	$	4,040	$	(8)	$	12,351

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

22

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GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Operating Revenues:
Retail revenues	$	2,996	$	3,703	$	7,142	$	8,629
Wholesale revenues	69		56		147		186
Other revenues	172		130		516		403
Total operating revenues	3,237		3,889		7,805		9,218
Operating Expenses:
Fuel	576		841		1,392		1,887
Purchased power, non-affiliates	131		304		397		700
Purchased power, affiliates	221		571		579		1,100
Other operations and maintenance	512		595		1,505		1,686
Depreciation and amortization	429		359		1,248		1,066
Taxes other than income taxes	144		155		406		420
Estimated loss on Plant Vogtle Units 3 and 4	160		(70)		160		(18)
Total operating expenses	2,173		2,755		5,687		6,841
Operating Income	1,064		1,134		2,118		2,377
Other Income and (Expense):
Allowance for equity funds used during construction	37		37		121		102
Interest expense, net of amounts capitalized	(166)		(123)		(472)		(347)
Other income (expense), net	45		36		125		140
Total other income and (expense)	(84)		(50)		(226)		(105)
Earnings Before Income Taxes	980		1,084		1,892		2,272
Income taxes	200		226		345		421
Net Income	$	780	$	858	$	1,547	$	1,851

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Net Income	$	780	$	858	$	1,547	$	1,851
Other comprehensive income:
Qualifying hedges:
Changes in fair value, net of tax of     $—, $—, $(1), and $8, respectively	—		—		(1)		23
Reclassification adjustment for amounts included in net income,    net of tax of $—, $—, $1, and $1, respectively	1		1		3		4
Total other comprehensive income	1		1		2		27
Comprehensive Income	$	781	$	859	$	1,549	$	1,878

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

23

    Table of Contents                                Index to Financial Statements

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2023		2022
	(in millions)
Operating Activities:
Net income	$	1,547	$	1,851
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	1,411		1,211
Deferred income taxes	102		266
Allowance for equity funds used during construction	(121)		(102)
Pension, postretirement, and other employee benefits	(207)		(178)
Settlement of asset retirement obligations	(228)		(149)
Storm damage accruals	24		160
Retail fuel cost under recovery – long-term	(157)		(1,287)
Estimated loss on Plant Vogtle Units 3 and 4	160		(18)
Other, net	(12)		(22)
Changes in certain current assets and liabilities —
-Receivables	(311)		(321)
-Retail fuel cost under recovery	204		—
-Fossil fuel stock	(138)		(23)
-Materials and supplies	(135)		(67)
-Contract assets	(57)		(51)
-Other current assets	16		(72)
-Accounts payable	(142)		211
-Accrued taxes	118		151
-Customer refunds	(121)		1
-Other current liabilities	16		(79)
Net cash provided from operating activities	1,969		1,482
Investing Activities:
Property additions	(3,501)		(2,556)
Nuclear decommissioning trust fund purchases	(659)		(585)
Nuclear decommissioning trust fund sales	654		581
Cost of removal, net of salvage	(191)		(250)
Change in construction payables, net of joint owner portion	338		148
Proceeds from dispositions	59		56
Other investing activities	(76)		(47)
Net cash used for investing activities	(3,376)		(2,653)
Financing Activities:
Increase in notes payable, net	50		415
Proceeds —
Senior notes	1,750		1,500
Short-term borrowings	250		650
Revenue bonds	229		—
Redemptions and repurchases —
Senior notes	(800)		(400)
Short-term borrowings	(650)		(250)
FFB loan	(64)		(66)
Revenue bonds	—		(53)
Other long-term debt	—		(125)
Capital contributions from parent company	1,837		813
Payment of common stock dividends	(1,392)		(1,268)
Other financing activities	(27)		(45)
Net cash provided from financing activities	1,183		1,171
Net Change in Cash, Cash Equivalents, and Restricted Cash	(224)		—
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	480		33
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	256	$	33
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $63 and $52 capitalized for 2023 and 2022, respectively)	$	439	$	332
Income taxes, net	74		151
Noncash transactions —
Accrued property additions at end of period	942		609
Right-of-use assets obtained under operating leases	17		7
Right-of-use assets obtained under finance leases	18		112

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

24

    Table of Contents                                Index to Financial Statements

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2023		At December 31, 2022
	(in millions)
Current Assets:
Cash and cash equivalents	$	173	$	364
Receivables —
Customer accounts, net	1,056		735
Unbilled revenues	250		309
Under recovered fuel clause revenues	730		—
Joint owner accounts	157		128
Affiliated	75		53
Other accounts and notes	70		62
Fossil fuel stock	429		291
Materials and supplies	856		729
Regulatory assets – asset retirement obligations	183		158
Other regulatory assets	379		324
Other current assets	266		246
Total current assets	4,624		3,399
Property, Plant, and Equipment:
In service	48,083		41,879
Less: Accumulated provision for depreciation	13,771		13,115
Plant in service, net of depreciation	34,312		28,764
Nuclear fuel, at amortized cost	622		604
Construction work in progress	5,055		8,103
Total property, plant, and equipment	39,989		37,471
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,042		1,018
Equity investments in unconsolidated subsidiaries	47		51
Miscellaneous property and investments	131		107
Total other property and investments	1,220		1,176
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	914		1,007
Deferred charges related to income taxes	595		583
Prepaid pension costs	839		738
Deferred under recovered fuel clause revenues	1,279		2,056
Regulatory assets – asset retirement obligations, deferred	3,508		3,671
Other regulatory assets, deferred	2,685		2,522
Other deferred charges and assets	496		540
Total deferred charges and other assets	10,316		11,117
Total Assets	$	56,149	$	53,163

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

25

    Table of Contents                                Index to Financial Statements

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2023		At December 31, 2022
	(in millions)
Current Liabilities:
Securities due within one year	$	503	$	901
Notes payable	1,250		1,600
Accounts payable —
Affiliated	770		928
Other	1,632		1,076
Customer deposits	251		252
Accrued taxes	620		508
Accrued interest	178		157
Accrued compensation	205		254
Operating lease obligations	134		151
Asset retirement obligations	328		295
Other regulatory liabilities	22		170
Other current liabilities	421		286
Total current liabilities	6,314		6,578
Long-term Debt	15,522		14,009
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,914		3,707
Deferred credits related to income taxes	2,171		2,244
Accumulated deferred ITCs	311		319
Employee benefit obligations	291		318
Operating lease obligations, deferred	744		851
Asset retirement obligations, deferred	5,567		5,739
Other deferred credits and liabilities	458		540
Total deferred credits and other liabilities	13,456		13,718
Total Liabilities	35,292		34,305
Common Stockholder's Equity (See accompanying statements)	20,857		18,858
Total Liabilities and Stockholder's Equity	$	56,149	$	53,163

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, 2021	9	$	398	$	14,153	$	2,724	$	(41)	$	17,234
Net income	—	—		—		385		—		385
Capital contributions from parent company	—	—		443		—		—		443
Other comprehensive income	—	—		—		—		10		10
Cash dividends on common stock	—	—		—		(423)		—		(423)
Balance at March 31, 2022	9	398		14,596		2,686		(31)		17,649
Net income	—	—		—		608		—		608
Capital contributions from parent company	—	—		46		—		—		46
Other comprehensive income	—	—		—		—		16		16
Cash dividends on common stock	—	—		—		(422)		—		(422)
Balance at June 30, 2022	9	398		14,642		2,872		(15)		17,897
Net income	—	—		—		858		—		858
Capital contributions from parent company	—	—		324		—		—		324
Other comprehensive income	—	—		—		—		1		1
Cash dividends on common stock	—	—		—		(423)		—		(423)
Balance at September 30, 2022	9	$	398	$	14,966	$	3,307	$	(14)	$	18,657
Balance at December 31, 2022	9	$	398	$	15,626	$	2,846	$	(12)	$	18,858
Net income	—	—		—		296		—		296
Capital contributions from parent company	—	—		752		—		—		752
Cash dividends on common stock	—	—		—		(464)		—		(464)
Other	—	—		—		1		—		1
Balance at March 31, 2023	9	398		16,378		2,679		(12)		19,443
Net income	—	—		—		471		—		471
Capital contributions from parent company	—	—		33		—		—		33
Other comprehensive income	—	—		—		—		1		1
Cash dividends on common stock	—	—		—		(464)		—		(464)
Balance at June 30, 2023	9	398		16,411		2,686		(11)		19,484
Net income	—	—		—		780		—		780
Capital contributions from parent company	—	—		1,056		—		—		1,056
Other comprehensive income	—	—		—		—		1		1
Cash dividends on common stock	—	—		—		(464)		—		(464)
Balance at September 30, 2023	9	$	398	$	17,467	$	3,002	$	(10)	$	20,857

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 AND COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Operating Revenues:
Retail revenues	$	284	$	250	$	747	$	718
Wholesale revenues, non-affiliates	77		60		201		191
Wholesale revenues, affiliates	65		187		158		336
Other revenues	10		13		31		34
Total operating revenues	436		510		1,137		1,279
Operating Expenses:
Fuel and purchased power	169		262		416		601
Other operations and maintenance	84		86		258		252
Depreciation and amortization	48		45		139		135
Taxes other than income taxes	32		32		92		93
Total operating expenses	333		425		905		1,081
Operating Income	103		85		232		198
Other Income and (Expense):
Interest expense, net of amounts capitalized	(19)		(15)		(53)		(42)
Other income (expense), net	9		9		29		32
Total other income and (expense)	(10)		(6)		(24)		(10)
Earnings Before Income Taxes	93		79		208		188
Income taxes	18		17		35		38
Net Income and Comprehensive Income	$	75	$	62	$	173	$	150

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

28

    Table of Contents                                Index to Financial Statements

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2023		2022
	(in millions)
Operating Activities:
Net income	$	173	$	150
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	171		164
Deferred income taxes	(10)		(4)
Pension, postretirement, and other employee benefits	(15)		(12)
Settlement of asset retirement obligations	(12)		(15)
Other, net	12		36
Changes in certain current assets and liabilities —
-Receivables	55		(49)
-Retail fuel cost under recovery	(24)		(9)
-Other current assets	14		(17)
-Accounts payable	(83)		41
-Accrued taxes	(16)		(3)
-Accrued compensation	(5)		(5)
-Other current liabilities	—		2
Net cash provided from operating activities	260		279
Investing Activities:
Property additions	(231)		(165)
Cost of removal, net of salvage	(21)		(20)
Construction payables	(5)		(9)
Payments pursuant to LTSAs	(21)		(23)
Other investing activities	(2)		(2)
Net cash used for investing activities	(280)		(219)
Financing Activities:
Increase in notes payable, net	20		—
Proceeds — Senior notes	100		—
Capital contributions from parent company	8		55
Payment of common stock dividends	(139)		(128)
Other financing activities	(1)		1
Net cash used for financing activities	(12)		(72)
Net Change in Cash, Cash Equivalents, and Restricted Cash	(32)		(12)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	59		61
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	27	$	49
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest	$	53	$	49
Income taxes, net	33		18
Noncash transactions —
Accrued property additions at end of period	20		16
Right-of-use assets obtained under operating leases	1		—

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

29

    Table of Contents                                Index to Financial Statements

MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2023		At December 31, 2022
	(in millions)
Current Assets:
Cash and cash equivalents	$	27	$	59
Receivables —
Customer accounts, net	78		47
Unbilled revenues	41		47
Affiliated	38		82
Other accounts and notes	22		35
Fossil fuel stock	37		44
Materials and supplies	85		80
Other regulatory assets	54		72
Other current assets	10		38
Total current assets	392		504
Property, Plant, and Equipment:
In service	5,473		5,254
Less: Accumulated provision for depreciation	1,763		1,689
Plant in service, net of depreciation	3,710		3,565
Construction work in progress	183		208
Total property, plant, and equipment	3,893		3,773
Other Property and Investments	160		167
Deferred Charges and Other Assets:
Deferred charges related to income taxes	29		30
Prepaid pension costs	123		109
Regulatory assets – asset retirement obligations	241		239
Other regulatory assets, deferred	246		249
Accumulated deferred income taxes	95		107
Other deferred charges and assets	79		94
Total deferred charges and other assets	813		828
Total Assets	$	5,258	$	5,272

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

30

    Table of Contents                                Index to Financial Statements

MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2023		At December 31, 2022
	(in millions)
Current Liabilities:
Securities due within one year	$	201	$	1
Notes payable	20		—
Accounts payable —
Affiliated	79		121
Other	61		106
Accrued taxes	108		124
Accrued compensation	32		37
Asset retirement obligations	26		37
Other regulatory liabilities	30		43
Other current liabilities	74		85
Total current liabilities	631		554
Long-term Debt	1,443		1,544
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	466		466
Deferred credits related to income taxes	229		253
Employee benefit obligations	67		69
Asset retirement obligations, deferred	145		142
Other cost of removal obligations	192		196
Other regulatory liabilities, deferred	81		96
Other deferred credits and liabilities	30		21
Total deferred credits and other liabilities	1,210		1,243
Total Liabilities	3,284		3,341
Common Stockholder's Equity (See accompanying statements)	1,974		1,931
Total Liabilities and Stockholder's Equity	$	5,258	$	5,272

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)		Total
	(in millions)
Balance at December 31, 2021	1	$	38	$	4,582	$	(2,753)	$	1,867
Net income	—	—		—		42		42
Capital contributions from parent company	—	—		51		—		51
Cash dividends on common stock	—	—		—		(43)		(43)
Balance at March 31, 2022	1	38		4,633		(2,754)		1,917
Net income	—	—		—		45		45
Capital contributions from parent company	—	—		1		—		1
Cash dividends on common stock	—	—		—		(42)		(42)
Balance at June 30, 2022	1	38		4,634		(2,751)		1,921
Net income	—	—		—		62		62
Capital contributions from parent company	—	—		5		—		5
Cash dividends on common stock	—	—		—		(42)		(42)
Balance at September 30, 2022	1	$	38	$	4,639	$	(2,731)	$	1,946
Balance at December 31, 2022	1	$	38	$	4,652	$	(2,759)	$	1,931
Net income	—	—		—		58		58
Cash dividends on common stock	—	—		—		(46)		(46)
Balance at March 31, 2023	1	38		4,652		(2,747)		1,943
Net income	—	—		—		40		40
Capital contributions from parent company	—	—		12		—		12
Cash dividends on common stock	—	—		—		(47)		(47)
Balance at June 30, 2023	1	38		4,664		(2,754)		1,948
Net income	—	—		—		75		75
Return of capital to parent company	—	—		(3)		—		(3)
Cash dividends on common stock	—	—		—		(46)		(46)
Balance at September 30, 2023	1	$	38	$	4,661	$	(2,725)	$	1,974

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 September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	479	$	835	$	1,234	$	1,918
Wholesale revenues, affiliates	156		336		406		673
Other revenues	18		9		46		27
Total operating revenues	653		1,180		1,686		2,618
Operating Expenses:
Fuel	196		605		526		1,274
Purchased power	33		144		87		233
Other operations and maintenance	104		113		327		332
Depreciation and amortization	130		133		380		384
Taxes other than income taxes	13		13		38		38
Gain on dispositions, net	—		—		(20)		(2)
Total operating expenses	476		1,008		1,338		2,259
Operating Income	177		172		348		359
Other Income and (Expense):
Interest expense, net of amounts capitalized	(32)		(32)		(98)		(105)
Other income (expense), net	4		3		8		5
Total other income and (expense)	(28)		(29)		(90)		(100)
Earnings Before Income Taxes	149		143		258		259
Income taxes	39		36		38		49
Net Income	110		107		220		210
Net income (loss) attributable to noncontrolling interests	10		12		(68)		(55)
Net Income Attributable to Southern Power	$	100	$	95	$	288	$	265

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Net Income	$	110	$	107	$	220	$	210
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of     $(2), $(11), $(3), and $(35), respectively	(13)		(35)		(17)		(106)
Reclassification adjustment for amounts included in net income,    net of tax of $4, $9, $6, and $35, respectively	17		28		24		106
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income,    net of tax of $—, $—, $—, and $—, respectively	—		—		—		1
Total other comprehensive income (loss)	4		(7)		7		1
Comprehensive Income	114		100		227		211
Comprehensive income (loss) attributable to noncontrolling interests	10		12		(68)		(55)
Comprehensive Income Attributable to Southern Power	$	104	$	88	$	295	$	266

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

33

    Table of Contents                                Index to Financial Statements

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2023		2022
	(in millions)
Operating Activities:
Net income	$	220	$	210
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	395		404
Deferred income taxes	1		21
Utilization of federal investment tax credits	179		218
Amortization of investment tax credits	(44)		(44)
Gain on dispositions, net	(20)		(2)
Other, net	4		1
Changes in certain current assets and liabilities —
-Receivables	100		(124)
-Prepaid income taxes	31		22
-Other current assets	(14)		(15)
-Accounts payable	(70)		95
-Accrued taxes	9		55
-Other current liabilities	8		(14)
Net cash provided from operating activities	799		827
Investing Activities:
Acquisitions, net of cash acquired	(181)		—
Property additions	(40)		(64)
Proceeds from dispositions	59		48
Change in construction payables	(18)		(60)
Payments pursuant to LTSAs	(49)		(52)
Other investing activities	5		—
Net cash used for investing activities	(224)		(128)
Financing Activities:
Increase (decrease) in notes payable, net	136		(5)
Redemptions — Senior notes	(290)		(677)
Capital contributions from parent company	16		330
Capital contributions from noncontrolling interests	21		73
Distributions to noncontrolling interests	(148)		(175)
Payment of common stock dividends	(189)		(148)
Other financing activities	3		(1)
Net cash used for financing activities	(451)		(603)
Net Change in Cash, Cash Equivalents, and Restricted Cash	124		96
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	133		135
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	257	$	231
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $1 and $— capitalized for 2023 and 2022, respectively)	$	103	$	120
Income taxes, net	(124)		(202)
Noncash transactions —
Accrued property additions at end of period	23		30
Right-of-use assets obtained under operating leases	7		—
Reassessment of right-of-use assets under operating leases	—		40

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

34

    Table of Contents                                Index to Financial Statements

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2023		At December 31, 2022
	(in millions)
Current Assets:
Cash and cash equivalents	$	236	$	131
Receivables —
Customer accounts, net	164		226
Affiliated	60		51
Other	44		70
Materials and supplies	84		88
Prepaid income taxes	130		5
Other current assets	71		50
Total current assets	789		621
Property, Plant, and Equipment:
In service	14,678		14,658
Less: Accumulated provision for depreciation	4,001		3,661
Plant in service, net of depreciation	10,677		10,997
Construction work in progress	224		41
Total property, plant, and equipment	10,901		11,038
Other Property and Investments:
Intangible assets, net of amortization of $143 and $129, respectively	248		263
Equity investments in unconsolidated subsidiaries	—		49
Net investment in sales-type leases	150		154
Total other property and investments	398		466
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	490		489
Prepaid LTSAs	225		193
Other deferred charges and assets	287		274
Total deferred charges and other assets	1,002		956
Total Assets	$	13,090	$	13,081

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

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At September 30, 2023		At December 31, 2022
	(in millions)
Current Liabilities:
Securities due within one year	$	—	$	290
Notes payable	359		225
Accounts payable —
Affiliated	80		139
Other	43		67
Accrued taxes	33		24
Accrued interest	22		28
Other current liabilities	117		111
Total current liabilities	654		884
Long-term Debt	2,687		2,689
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	619		279
Accumulated deferred ITCs	1,512		1,556
Operating lease obligations	516		514
Other deferred credits and liabilities	259		243
Total deferred credits and other liabilities	2,906		2,592
Total Liabilities	6,247		6,165
Total Stockholders' Equity (See accompanying statements)	6,843		6,916
Total Liabilities and Stockholders' Equity	$	13,090	$	13,081

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, 2021	$	638	$	1,585	$	(27)	$	2,196	$	4,402	$	6,598
Net income (loss)	—		72		—		72		(45)		27
Other comprehensive income	—		—		5		5		—		5
Cash dividends on common stock	—		(49)		—		(49)		—		(49)
Capital contributions from    noncontrolling interests	—		—		—		—		73		73
Distributions to noncontrolling interests	—		—		—		—		(98)		(98)
Balance at March 31, 2022	638		1,608		(22)		2,224		4,332		6,556
Net income (loss)	—		98		—		98		(22)		76
Capital contributions from parent company	322		—		—		322		—		322
Other comprehensive income	—		—		3		3		—		3
Cash dividends on common stock	—		(50)		—		(50)		—		(50)
Distributions to noncontrolling interests	—		—		—		—		(28)		(28)
Balance at June 30, 2022	960		1,656		(19)		2,597		4,282		6,879
Net income	—		95		—		95		12		107
Capital contributions from parent company	9		—		—		9		—		9
Other comprehensive income (loss)	—		—		(7)		(7)		—		(7)
Cash dividends on common stock	—		(49)		—		(49)		—		(49)
Distributions to noncontrolling interests	—		—		—		—		(57)		(57)
Other	—		(1)		(1)		(2)		—		(2)
Balance at September 30, 2022	$	969	$	1,701	$	(27)	$	2,643	$	4,237	$	6,880

Balance at December 31, 2022	$	1,069	$	1,741	$	(18)	$	2,792	$	4,124	$	6,916
Net income (loss)	—		102		—		102		(63)		39
Other comprehensive income (loss)	—		—		(7)		(7)		—		(7)
Cash dividends on common stock	—		(63)		—		(63)		—		(63)
Capital contributions from    noncontrolling interests	—		—		—		—		21		21
Distributions to noncontrolling interests	—		—		—		—		(48)		(48)
Balance at March 31, 2023	1,069		1,780		(25)		2,824		4,034		6,858
Net income (loss)	—		85		—		85		(15)		70
Capital contributions from parent company	14		—		—		14		—		14
Other comprehensive income	—		—		10		10		—		10
Cash dividends on common stock	—		(63)		—		(63)		—		(63)
Distributions to noncontrolling interests	—		—		—		—		(42)		(42)
Other	—		—		1		1		(1)		—
Balance at June 30, 2023	1,083		1,802		(14)		2,871		3,976		6,847
Net income	—		100		—		100		10		110
Capital contributions from parent company	3		—		—		3		—		3
Other comprehensive income	—		—		4		4		—		4
Cash dividends on common stock	—		(63)		—		(63)		—		(63)
Distributions to noncontrolling interests	—		—		—		—		(59)		(59)
Other	1		—		—		1		—		1
Balance at September 30, 2023	$	1,087	$	1,839	$	(10)	$	2,916	$	3,927	$	6,843

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

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SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Operating Revenues:
Natural gas revenues (includes revenue taxes of     $11, $15, $103, and $118, respectively)	$	689	$	857	$	3,417	$	3,998
Total operating revenues	689		857		3,417		3,998
Operating Expenses:
Cost of natural gas	102		294		1,199		1,840
Other operations and maintenance	264		252		879		824
Depreciation and amortization	145		140		429		414
Taxes other than income taxes	42		45		203		208
Total operating expenses	553		731		2,710		3,286
Operating Income	136		126		707		712
Other Income and (Expense):
Earnings from equity method investments	32		34		104		105
Interest expense, net of amounts capitalized	(77)		(65)		(226)		(187)
Other income (expense), net	19		15		50		47
Total other income and (expense)	(26)		(16)		(72)		(35)
Earnings Before Income Taxes	110		110		635		677
Income taxes	28		27		160		161
Net Income	$	82	$	83	$	475	$	516

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Net Income	$	82	$	83	$	475	$	516
Other comprehensive income:
Qualifying hedges:
Changes in fair value, net of tax of     $(2), $8, $(11), and $16, respectively	(6)		19		(30)		39
Reclassification adjustment for amounts included in net income,     net of tax of $7, $(2), $15, and $(7), respectively	16		(5)		37		(17)
Total other comprehensive income	10		14		7		22
Comprehensive Income	$	92	$	97	$	482	$	538

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

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SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2023		2022
	(in millions)
Operating Activities:
Net income	$	475	$	516
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	429		414
Deferred income taxes	75		109
Natural gas cost under recovery – long-term	—		207
Other, net	(15)		(12)
Changes in certain current assets and liabilities —
-Receivables	776		301
-Natural gas for sale, net of temporary LIFO liquidation	31		(136)
-Prepaid income taxes	12		(77)
-Natural gas cost under recovery	108		(124)
-Other current assets	(32)		7
-Accounts payable	(346)		342
-Natural gas cost over recovery	165		—
-Other current liabilities	(34)		(15)
Net cash provided from operating activities	1,644		1,532
Investing Activities:
Property additions	(1,151)		(1,063)
Cost of removal, net of salvage	(82)		(84)
Change in construction payables, net	(38)		(103)
Other investing activities	45		11
Net cash used for investing activities	(1,226)		(1,239)
Financing Activities:
Decrease in notes payable, net	(493)		(749)
Proceeds —
Senior notes	500		500
First mortgage bonds	125		100
Short-term borrowings	—		50
Other long-term debt	29		—
Redemptions —
Short-term borrowings	(200)		(150)
Medium-term notes	—		(46)
Capital contributions from parent company	377		357
Payment of common stock dividends	(439)		(389)
Other financing activities	(1)		14
Net cash used for financing activities	(102)		(313)
Net Change in Cash, Cash Equivalents, and Restricted Cash	316		(20)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	83		48
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	399	$	28
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $12 and $7 capitalized for 2023 and 2022, respectively)	$	214	$	186
Income taxes, net	70		193
Noncash transactions —
Accrued property additions at end of period	139		10
Right-of-use assets obtained under operating leases	3		—

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

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SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2023		At December 31, 2022
	(in millions)
Current Assets:
Cash and cash equivalents	$	397	$	81
Receivables —
Customer accounts	242		616
Unbilled revenues	74		453
Other accounts and notes	52		76
Accumulated provision for uncollectible accounts	(53)		(50)
Natural gas for sale	406		438
Prepaid expenses	92		93
Natural gas cost under recovery	—		108
Other regulatory assets	144		119
Other current assets	108		104
Total current assets	1,462		2,038
Property, Plant, and Equipment:
In service	20,459		19,723
Less: Accumulated depreciation	5,454		5,276
Plant in service, net of depreciation	15,005		14,447
Construction work in progress	1,158		909
Total property, plant, and equipment	16,163		15,356
Other Property and Investments:
Goodwill	5,015		5,015
Equity investments in unconsolidated subsidiaries	1,243		1,276
Other intangible assets, net of amortization of $163 and $156, respectively	19		26
Miscellaneous property and investments	24		28
Total other property and investments	6,301		6,345
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	47		57
Prepaid pension costs	205		183
Other regulatory assets, deferred	483		497
Other deferred charges and assets	162		145
Total deferred charges and other assets	897		882
Total Assets	$	24,823	$	24,621

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

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SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2023		At December 31, 2022
	(in millions)
Current Liabilities:
Securities due within one year	$	400	$	400
Notes payable	75		768
Accounts payable —
Affiliated	62		104
Other	374		701
Customer deposits	133		125
Accrued taxes	75		77
Accrued interest	79		67
Accrued compensation	85		105
Natural gas cost over recovery	165		—
Other regulatory liabilities	44		36
Other current liabilities	146		187
Total current liabilities	1,638		2,570
Long-term Debt	7,657		7,042
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,629		1,560
Deferred credits related to income taxes	766		788
Employee benefit obligations	108		120
Operating lease obligations	40		51
Other cost of removal obligations	1,748		1,707
Accrued environmental remediation	202		207
Other deferred credits and liabilities	202		179
Total deferred credits and other liabilities	4,695		4,612
Total Liabilities	13,990		14,224
Common Stockholder's Equity (See accompanying statements)	10,833		10,397
Total Liabilities and Stockholder's Equity	$	24,823	$	24,621

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, 2021	$	10,024	$	(132)	$	24	$	9,916
Net income	—		319		—		319
Capital contributions from parent company	50		—		—		50
Other comprehensive income	—		—		20		20
Cash dividends on common stock	—		(130)		—		(130)
Balance at March 31, 2022	10,074		57		44		10,175
Net income	—		115		—		115
Capital contributions from parent company	312		—		—		312
Other comprehensive income (loss)	—		—		(12)		(12)
Cash dividends on common stock	—		(130)		—		(130)
Balance at June 30, 2022	10,386		42		32		10,460
Net income	—		83		—		83
Capital contributions from parent company	11		—		—		11
Other comprehensive income	—		—		14		14
Cash dividends on common stock	—		(130)		—		(130)
Balance at September 30, 2022	$	10,397	$	(5)	$	46	$	10,438
Balance at December 31, 2022	$	10,445	$	(79)	$	31	$	10,397
Net income	—		309		—		309
Capital contributions from parent company	203		—		—		203
Other comprehensive income (loss)	—		—		(10)		(10)
Cash dividends on common stock	—		(146)		—		(146)
Other	1		(1)		—		—
Balance at March 31, 2023	10,649		83		21		10,753
Net income	—		85		—		85
Capital contributions from parent company	40		—		—		40
Other comprehensive income	—		—		7		7
Cash dividends on common stock	—		(147)		—		(147)
Balance at June 30, 2023	10,689		21		28		10,738
Net income	—		82		—		82
Capital contributions from parent company	149		—		—		149
Other comprehensive income	—		—		10		10
Cash dividends on common stock	—		(146)		—		(146)
Balance at September 30, 2023	$	10,838	$	(43)	$	38	$	10,833

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	44
B	Regulatory Matters	49
C	Contingencies	60
D	Revenue from Contracts with Customers and Lease Income	65
E	Consolidated Entities and Equity Method Investments	71
F	Financing and Leases	73
G	Income Taxes	76
H	Retirement Benefits	77
I	Fair Value Measurements	80
J	Derivatives	84
K	Acquisitions and Dispositions	96
L	Segment and Related Information	96

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, 2022 have been derived from the audited financial statements of each Registrant. In the opinion of each Registrant's management, the information regarding such Registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2023 and 2022. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each Registrant believes that the disclosures regarding such Registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy and other factors, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the overall results of operations, financial position, or cash flows of any Registrant.

Recently Adopted Accounting Standards

In March 2020 and December 2022, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting and ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, respectively, providing temporary guidance to ease the potential burden in accounting for reference rate reform primarily resulting from the discontinuation of LIBOR through December 31, 2024. See Note 1 to the financial statements under "Recently Adopted Accounting Standards" in Item 8 of the Form 10-K for additional information on the temporary guidance.

Certain provisions in PPAs at Southern Power include references to LIBOR. Contract amendments have been executed to change to a SOFR-based interest rate. Southern Power adopted and applied the practical expedients guidance to these PPAs. Additionally, the Registrants referenced LIBOR for certain debt and hedging arrangements. As of July 1, 2023, all of the debt and hedging arrangements of the Registrants have transitioned to a SOFR-based interest rate based on the terms of the agreements. There were no material impacts from the transition to SOFR and no impacts to any existing accounting conclusions. See Note (J) under "Interest Rate Derivatives" for additional information.

Goodwill and Other Intangible Assets

Goodwill at September 30, 2023 and December 31, 2022 was as follows:

	Goodwill
	(in millions)
Southern Company	$	5,161
Southern Company Gas:
Gas distribution operations	$	4,034
Gas marketing services	981
Southern Company Gas total	$	5,015

Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if goodwill impairment indicators arise.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

Other intangible assets were as follows:

	At September 30, 2023						At December 31, 2022
	Gross Carrying Amount		Accumulated Amortization		Other Intangible Assets, Net		Gross Carrying Amount		Accumulated Amortization		Other Intangible Assets, Net
	(in millions)						(in millions)
Southern Company
Subject to amortization:
Customer relationships	$	211	$	(169)	$	42	$	212	$	(162)	$	50
Trade names	63		(50)		13		64		(44)		20
PPA fair value adjustments	390		(143)		247		390		(129)		261
Other	5		(5)		—		5		(5)		—
Total subject to amortization	$	669	$	(367)	$	302	$	671	$	(340)	$	331
Not subject to amortization:
FCC licenses	75		—		75		75		—		75
Total other intangible assets	$	744	$	(367)	$	377	$	746	$	(340)	$	406
Southern Power(*)
PPA fair value adjustments	$	390	$	(143)	$	247	$	390	$	(129)	$	261
Southern Company Gas(*)
Gas marketing services
Customer relationships	$	156	$	(143)	$	13	$	156	$	(139)	$	17
Trade names	26		(20)		6		26		(17)		9
Total other intangible assets	$	182	$	(163)	$	19	$	182	$	(156)	$	26

(*) All subject to amortization.

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Nine Months Ended		Three Months Ended		Nine Months Ended
	September 30, 2023				September 30, 2022
	(in millions)
Southern Company(a)	$	10	$	27	$	11	$	30
Southern Power(b)	5		14		5		15
Southern Company Gas	3		7		4		9

(a)Includes $5 million, $14 million, $5 million, and $15 million for the three and nine months ended September 30, 2023 and 2022, respectively, recorded as a reduction to operating revenues.

(b)Recorded as a reduction to operating revenues.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

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		Alabama Power		Georgia Power		Southern Power		Southern Company Gas
	(in millions)
At September 30, 2023
Cash and cash equivalents	$	1,676	$	621	$	173	$	236	$	397
Restricted cash(a):
Other current assets	176		108		48		18		2
Other deferred charges and assets	38		—		35		3		—
Total cash, cash equivalents, and restricted cash(b)	$	1,890	$	729	$	256	$	257	$	399
At December 31, 2022
Cash and cash equivalents	$	1,917	$	687	$	364	$	131	$	81
Restricted cash(a):
Other current assets	62		—		60		—		2
Other deferred charges and assets	58		—		56		3		—
Total cash, cash equivalents, and restricted cash(b)	$	2,037	$	687	$	480	$	133	$	83

(a)For Alabama Power, balance at September 30, 2023 reflects proceeds from the issuance of solid waste disposal facility revenue bonds in 2023. For Georgia Power, reflects proceeds from the issuance of solid waste disposal facility revenue bonds in 2022. For Southern Power, reflects $18 million at September 30, 2023 resulting from an arbitration interim award held to fund future replacement costs and $3 million at both September 30, 2023 and December 31, 2022 held to fund estimated construction completion costs at the Deuel Harvest wind facility. See Note (C) under "General Litigation Matters – Southern Power" for additional information. For Southern Company Gas, reflects collateral for workers' compensation, life insurance, and long-term disability insurance.

(b)Total may not add due to rounding.

Natural Gas for Sale

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

Southern Company Gas recorded no material adjustments to natural gas inventories for either period presented. Nicor Gas' inventory decrement at September 30, 2023 is expected to be restored prior to year-end.

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Storm Damage Reserves

See Note 1 to the financial statements in Item 8 of the Form 10-K under "Storm Damage and Reliability Reserves" for additional information.

Storm damage reserve activity for the traditional electric operating companies during the nine months ended September 30, 2023 was as follows:

	Southern Company(*)		Alabama Power		Georgia Power(*)		Mississippi Power
	(in millions)
Balance at December 31, 2022	$	216	$	97	$	83	$	36
Accrual	42		9		24		9
Weather-related damages	(242)		(35)		(204)		(3)
Balance at September 30, 2023	$	16	$	71	$	(97)	$	42

(*)See Note (B) under "Georgia Power – Storm Damage Recovery" for additional information.

Asset Retirement Obligations

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

Following initial criticality on March 6, 2023, Georgia Power recorded AROs of approximately $90 million related to Plant Vogtle Unit 3. See Note (B) under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.

In September 2023, Georgia Power recorded a net decrease of approximately $175 million to its AROs related to the CCR Rule and the related state rule resulting from changes in estimates, including lower future inflation rates and the timing of closure activities.

In June 2023, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated cost of decommissioning based on the study resulted in a decrease in Alabama Power's ARO liability of approximately $15 million. See "Nuclear Decommissioning" herein for additional information.

Nuclear Decommissioning

See Note 6 to the financial statements in Item 8 of the Form 10-K under "Nuclear Decommissioning" for additional information. Site study cost is the estimate to decommission a specific facility as of the site study year. The decommissioning cost estimates are based on removal of the plant from service and prompt dismantlement. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.

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The estimated costs of decommissioning Plant Farley based on Alabama Power's June 2023 site study are as follows:

	Plant Farley
Decommissioning periods:
Beginning year	2037
Completion year	2087
	(in millions)
Site study costs:
Radiated structures	$	1,402
Spent fuel management	513
Non-radiated structures	133
Total site study costs	$	2,048

For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an estimated inflation rate of 4.5% and an estimated trust earnings rate of 7.0%.

Amounts previously contributed to the external trust funds are currently projected to be adequate to meet the updated decommissioning obligations. Alabama Power's site-specific estimates of decommissioning costs for Plant Farley are updated every five years. The next site study for Alabama Power is expected to be completed in 2028. Projections of funds are reviewed with the Alabama PSC to ensure that, over time, the deposits and earnings of the funds in the external trust will provide adequate funding to cover the site-specific costs. If necessary, Alabama Power would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements.

Income Taxes

In the third quarter 2023, Georgia Power started generating advanced nuclear PTCs for Plant Vogtle Unit 3 beginning on the in-service date of July 31, 2023. PTCs are recognized as an income tax benefit based on KWH production. In addition, pursuant to the Global Amendments to the Vogtle Joint Ownership Agreements (as defined in Note (B) under "Georgia Power – Nuclear Construction – Joint Owner Contracts"), Georgia Power is purchasing advanced nuclear PTCs for Plant Vogtle Unit 3 from certain other Vogtle Owners. The gain recognized on the purchase of the joint owner PTCs is recognized as an income tax benefit. See Note 1 to the financial statements under "Income Taxes" in Item 8 of the Form 10-K for additional information regarding accounting policies related to income taxes. See Note (B) under "Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4. Also see Note (G) under "Current and Deferred Income Taxes" for additional information.

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(B) REGULATORY MATTERS

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

The recovery balances for certain retail regulatory clauses of the traditional electric operating companies and Southern Company Gas at September 30, 2023 and December 31, 2022 were as follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2023		December 31, 2022
		(in millions)
Alabama Power
Rate CNP Compliance	Other regulatory liabilities, deferred	$	3	$	—
	Other regulatory assets, current	—		47
Rate CNP PPA	Other regulatory assets, current	17		18
	Other regulatory assets, deferred	90		102
Retail Energy Cost Recovery	Other regulatory assets, current	208		102
	Other regulatory assets, deferred	80		520
Georgia Power
Fuel Cost Recovery(*)	Receivables – under recovered fuel clause revenues	$	730	$	—
	Deferred under recovered fuel clause revenues	1,279		2,056
Mississippi Power
Fuel Cost Recovery	Receivables – customer accounts, net	$	25	$	1
Ad Valorem Tax	Other regulatory assets, current	3		12
	Other regulatory assets, deferred	11		19
Southern Company Gas
Natural Gas Cost Recovery	Natural gas cost under recovery	$	—	$	108
	Natural gas cost over recovery	165		—

(*)See "Georgia Power – Fuel Cost Recovery" herein for additional information.

Alabama Power

Certificates of Convenience and Necessity

In 2020, the Alabama PSC approved a certificate of convenience and necessity authorizing Alabama Power's construction of Plant Barry Unit 8 and the recovery of estimated in-service costs of $652 million. At September 30, 2023, project expenditures associated with Plant Barry Unit 8 totaled approximately $583 million, of which $578 million and $5 million was included in CWIP and property, plant, and equipment in service, respectively. On November 1, 2023, the unit was placed in service. The ultimate outcome of this matter cannot be determined at this time.

Excess Accumulated Deferred Income Tax Accounting Order

On October 3, 2023, the Alabama PSC issued an order modifying its December 2022 order and authorizing Alabama Power to (i) flow back in 2023 approximately $24 million of certain federal excess accumulated deferred income taxes resulting from the Tax Cuts and Jobs Act of 2017 and (ii) make available any remaining balance of excess accumulated deferred income taxes at the end of 2023 for the benefit of customers in 2024 and/or 2025. The ultimate outcome of this matter cannot be determined at this time.

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Rate CNP New Plant

On March 24, 2023, Alabama Power filed Rate CNP New Plant with the Alabama PSC to recover costs associated with the acquisition of the Central Alabama Generating Station. The filing reflected an annual increase in retail revenues of $78 million effective with June 2023 billings. Through May 2023, Alabama Power recovered substantially all costs associated with the Central Alabama Generating Station through Rate RSE, offset by revenues from a power sales agreement. On May 24, 2023, the Central Alabama Generating Station was placed into retail service. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.

Renewable Generation Certificate

Through the issuance of a Renewable Generation Certificate (RGC), Alabama Power is authorized by the Alabama PSC to procure renewable capacity and energy and to market the related energy and environmental attributes to customers and other third parties. On April 4, 2023, the Alabama PSC approved two new solar PPAs totaling 160 MWs. Upon approval of these PPAs, Alabama Power had procured solar capacity totaling approximately 490 MWs under the RGC's original 500-MW limit.

On June 14, 2023, the Alabama PSC issued an order approving modifications to Alabama Power's RGC. The modifications authorized Alabama Power to procure an additional 2,400 MWs of renewable capacity and energy by June 14, 2029 and to market the related energy and environmental attributes to customers and other third parties. The modifications also increased the size of allowable renewable projects from 80 MWs to 200 MWs and increased the annual approval limit from 160 MWs to 400 MWs.

Reliability Reserve Accounting Order

On July 11, 2023, the Alabama PSC issued an order authorizing Alabama Power to expand the existing authority of its reliability reserve to include certain production-related expenses that are intended to maintain reliability in between scheduled generating unit maintenance outages.

On August 18, 2023, Alabama Power notified the Alabama PSC of its intent to use a portion of its $166 million reliability reserve balance during 2023. The ultimate outcome of this matter cannot be determined at this time.

Georgia Power

Rate Plans

In accordance with the terms of the 2022 ARP, on October 2, 2023, Georgia Power filed the following tariff adjustments to become effective January 1, 2024 pending approval by the Georgia PSC:

•increase traditional base tariffs by approximately $275 million;

•decrease the Environmental Compliance Cost Recovery tariff by approximately $99 million;

•increase the Demand-Side Management tariffs by approximately $10 million; and

•increase the Municipal Franchise Fee tariffs by approximately $5 million.

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

Plant Vogtle Unit 3 and Common Facilities Rate Proceeding

In compliance with a Georgia PSC order approved in November 2021, Georgia Power increased annual retail base rates by $318 million effective August 1, 2023 based on the in-service date of July 31, 2023 for Plant Vogtle Unit 3. See "Plant Vogtle Units 3 and 4 Prudency Proceeding" and "Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

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Plant Vogtle Units 3 and 4 Prudency Proceeding

On August 30, 2023, as provided for in the December 2017 Georgia PSC approval of the seventeenth VCM report, Georgia Power filed with the Georgia PSC an application to adjust rates to include reasonable and prudent Plant Vogtle Units 3 and 4 costs (Application). The Application provides the necessary support to justify the reasonableness, prudence, and recovery of $8.826 billion in total construction and capital costs, $1.07 billion in associated retail rate base items, and the operating costs related to the full operation and output of Plant Vogtle Units 3 and 4. Through the VCM process, the Georgia PSC has verified and approved all expenditures up to the revised approved construction and capital cost of $7.3 billion and has reviewed, but not verified and approved, all expenditures through December 31, 2022 above that amount.

Also on August 30, 2023, the staff of the Georgia PSC filed a stipulated agreement (Prudency Stipulation) among Georgia Power, the staff of the Georgia PSC, and certain intervenors. The Prudency Stipulation is intended to resolve all issues for determination by the Georgia PSC regarding the reasonableness, prudence, and cost recovery for the remaining costs not already in retail base rates, after considering many of the issues raised by the staff of the Georgia PSC and intervenors in prior VCM proceedings, including the extended construction time, required rework, scheduling of activities, and challenges with testing and productivity. If the Prudency Stipulation is approved, Georgia Power will recover $7.562 billion in total construction and capital costs and associated retail rate base items of $1.02 billion, which includes AFUDC financing costs above $4.418 billion (the Georgia PSC-certified amount) up to $7.562 billion.

The Prudency Stipulation also provides for the recovery of projected operations and maintenance expenses, depreciation expense, nuclear decommissioning accruals, and property taxes, net of projected production tax credits. After considering construction and capital costs already in retail base rates of $2.1 billion and $362 million of associated retail rate base items (approved by the Georgia PSC in November 2021), and upon achieving commercial operation of Unit 4, Georgia Power will include in retail rate base the remaining $5.462 billion of construction and capital costs as well as $656 million of associated retail rate base items.

Under the terms of the Prudency Stipulation, when the rate adjustment occurs, Georgia Power's NCCR tariff will cease to be collected and financing costs will be included in Georgia Power's general revenue requirements. Additionally, if commercial operation for Unit 4 is not achieved by March 31, 2024, Georgia Power's ROE used to determine the NCCR tariff and calculate AFUDC will be reduced to zero, which would result in an estimated negative impact to earnings of approximately $12 million per month until commercial operation for Unit 4 is achieved. The Prudency Stipulation also provides that as of each Unit's respective first refueling outage, if the respective Unit's performance has materially deviated from expected performance, the Georgia PSC may order Georgia Power to credit customers for operations and maintenance expenses or disallow costs associated with the repair or replacement of any system, structure, or component found to have caused the material deviation in performance if proven to be the result of imprudent engineering, construction, procurement, testing, or start-up.

If the Prudency Stipulation is approved by the Georgia PSC, annual retail base revenues will increase approximately $729 million and the average retail base rates will be adjusted by approximately 5% (net of the elimination of the NCCR tariff described above) effective the first day of the month after Unit 4 achieves commercial operation.

Georgia Power expects the Georgia PSC to render a final decision on these matters on December 19, 2023. The ultimate outcome of these matters cannot be determined at this time. See "Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" and "Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

Fuel Cost Recovery

On May 16, 2023, the Georgia PSC approved a stipulation agreement between Georgia Power and the staff of the Georgia PSC to increase annual fuel billings by 54%, or approximately $1.1 billion, effective June 1, 2023. The increase includes a three-year recovery period for $2.2 billion of Georgia Power's under recovered fuel balance at May 31, 2023. Under the approved stipulation agreement, Georgia Power is allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case, subject to a maximum 40% cumulative change, if its

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under or over recovered fuel balance accumulated since May 31, 2023 exceeds $200 million. Georgia Power is scheduled to file its next fuel case no later than February 28, 2026. Changes in fuel rates have no significant effect on Southern Company's or Georgia Power's net income but do impact the related operating cash flows.

Integrated Resource Plans

In August 2022, Restore Chattooga Gorge Coalition (RCG) filed a petition in the Superior Court of Fulton County, Georgia against Georgia Power and the Georgia PSC. The petition challenges Georgia Power's plan to expend $115 million to modernize Plant Tugalo (a hydro facility), as approved in the 2019 IRP, and seeks judicial review of the Georgia PSC's order in the 2022 IRP proceeding with respect to the denial of RCG's challenge to the modernization plan. On October 23, 2023, the court granted Georgia Power's and the Georgia PSC's motions to dismiss the RCG petition. RCG has until November 22, 2023 to file a notice of appeal.

On October 27, 2023, Georgia Power filed an updated IRP (2023 IRP Update) with the Georgia PSC, which sets forth a plan to support the recent increase in the state of Georgia's projected energy needs since the 2022 IRP. In the 2023 IRP Update, Georgia Power requested the following:

•Authority to develop, own, and operate up to 1,400 MWs from three simple cycle combustion turbines at Plant Yates.

•Approval to pursue potential acquisition of an additional ownership interest in an existing generation asset within the Southern Company system's retail electric service territory.

•Certification of an affiliate PPA with Mississippi Power for 750 MWs starting January 2024 through December 2028.

•Certification of a non-affiliate PPA for 230 MWs starting the month after conclusion of the 2023 IRP Update proceeding continuing through December 2028.

•Authority to develop, own, and operate up to 1,000 MWs of battery energy storage facilities collocated with existing and new Georgia Power-owned solar facilities.

•Approval of transmission projects necessary to support the generation resources requested in the 2023 IRP Update.

The schedule for the Georgia PSC to consider the 2023 IRP Update has not been determined. Georgia Power has requested that the Georgia PSC evaluate the 2023 IRP Update by the end of April 2024.

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

Storm Damage Recovery

Georgia Power is recovering $31 million annually under the 2022 ARP for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. During August 2023, Hurricane Idalia caused significant damage to Georgia Power's transmission and distribution facilities. The incremental restoration costs related to this hurricane deferred in the regulatory asset for storm damage totaled approximately $110 million. At September 30, 2023, Georgia Power's regulatory asset balance related to storm damage was $97 million. The rate of storm damage cost recovery is expected to be adjusted in future regulatory proceedings as necessary. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's or Georgia Power's net income but do impact the related operating cash flows.

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.

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(UNAUDITED)

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, under which Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, 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, and mandatory prepayment events.

Cost and Schedule

Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4, including contingency, through July 2023 and March 2024, respectively, is as follows:

	(in millions)
Base project capital cost forecast(a)(b)	$	10,736
Construction contingency estimate	17
Total project capital cost forecast(a)(b)	10,753
Net investment at September 30, 2023(b)	(10,495)
Remaining estimate to complete	$	258

(a)Includes approximately $610 million of costs that are not shared with the other Vogtle Owners, including $33 million of construction monitoring costs approved for recovery by the Georgia PSC in its nineteenth VCM order, and approximately $567 million of incremental costs under the cost-sharing provisions of the joint ownership agreements described below. Excludes financing costs expected to be capitalized through AFUDC of approximately $420 million, of which $385 million had been accrued through September 30, 2023.

(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 $3.5 billion, of which $3.4 billion had been incurred through September 30, 2023.

Georgia Power placed Unit 3 in service on July 31, 2023. See "Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" herein for additional information.

As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts for Unit 4 on a regular basis to incorporate current information available, particularly in the areas of start-up testing and related test results, engineering support, system turnovers, and workforce statistics. Southern Nuclear establishes aggressive target values for monthly testing and system turnover activities, which are reflected in the site work plan for Unit 4.

Since March 2020, the number of active COVID-19 cases at the site has fluctuated consistent with the surrounding area and impacted productivity levels and pace of activity completion, with the site experiencing peaks in the

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(UNAUDITED)

number of active cases in January 2021, August 2021, and January 2022. Georgia Power estimates the productivity impacts of the COVID-19 pandemic have consumed approximately three to four months of schedule margin previously embedded in the site work plans. As of September 30, 2023, Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is estimated to be approximately $200 million and is included in the total project capital cost forecast.

During the first nine months of 2023, established construction contingency totaling $43 million was assigned to the base capital cost forecast for costs primarily associated with the Unit 3 schedule extension and completion of start-up and pre-operational testing, including continued need of support resources for Unit 3 testing, as well as additional craft and support resources and subcontract work for Unit 4.

Hot functional testing for Unit 4 was completed on May 1, 2023. On July 20, 2023, Southern Nuclear announced that all Unit 4 ITAACs had been submitted to the NRC, and, on July 28, 2023, the NRC published its 103(g) finding that the accepted criteria in the combined license for Unit 4 had been met, which allowed nuclear fuel to be loaded and start-up testing to begin. Fuel load for Unit 4 was completed on August 19, 2023. On October 6, 2023, Georgia Power announced that during the start-up and pre-operational testing for Plant Vogtle Unit 4, Southern Nuclear identified a motor fault in one of four reactor coolant pumps (RCPs) and has started the process to replace this RCP with an on-site spare RCP from inventory. Considering this remediation and the remaining pre-operational testing, Unit 4 is projected to be placed in service during the first quarter 2024.

With Unit 3's four RCPs operating as designed, Southern Nuclear believes that the motor fault on this single Unit 4 RCP is an isolated event. However, any findings related to the root cause of the motor fault on the single Unit 4 RCP could require engineering changes or remediation related to the other seven Unit 3 and Unit 4 RCPs. The projected schedule for Unit 4 significantly depends on the pace and success of replacing the RCP, which involves removing and re-installing commodities around the RCP. As Unit 4 completes the RCP replacement, including any associated repairs to other RCPs, and transitions further into testing, ongoing and potential future challenges include the management of contractors and vendors, subcontractor performance, the availability of materials and parts, and/or related cost escalation; the pace of remaining work package closures; the availability of craft, supervisory, and technical support resources; and the timeframe and duration of final component and pre-operational testing. New challenges also may continue to arise as Unit 4 moves further into testing and start-up, which may result in required engineering changes or remediation related to plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale). These challenges may result in further schedule delays and/or cost increases.

There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to ensure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. With the receipt of the NRC's 103(g) findings for Units 3 and 4 in August 2022 and July 2023, respectively, the site is subject to the NRC's operating reactor oversight process and must meet applicable technical and operational requirements contained in its operating license. Various design and other licensing-based compliance matters may result in additional license amendment requests or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the Unit 4 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 March 2024 for Unit 4, including the joint owner cost sharing impacts described below, is estimated to result in additional base capital costs for Georgia Power of up to $25 million per month, as well as the related AFUDC and any additional related construction, support resources, or testing costs. Pursuant to Georgia Power's Application and the Prudency Stipulation (as discussed under "Plant Vogtle Units 3 and 4 Prudency Proceeding" herein), any further changes to the capital cost forecast are not expected to be recoverable through regulated rates and will be required to be charged to income. Such charges could be material.

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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.

Amendments to the Vogtle Joint Ownership Agreements

In connection with a September 2018 vote by the Vogtle Owners to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide up to $300 million of funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. In January 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. In February 2019, Georgia Power, the other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet (Global Amendments).

Pursuant to the Global Amendments: (i) each Vogtle Owner paid 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, of which Georgia Power's share is $8.4 billion (VCM 19 Forecast Amount), plus $800 million; (ii) Georgia Power was responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the VCM 19 Forecast Amount (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 was responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the VCM 19 Forecast Amount (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests. The Global Amendments provide that if the EAC was revised and exceeded the VCM 19 Forecast Amount by more than $2.1 billion, each of the other Vogtle Owners had a one-time option at the time the project budget cost forecast was 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 VCM 19 Forecast Amount 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 (Project Adverse Events) occur, including, among other events: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power's public announcement of its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Global Amendments described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more from the seventeenth VCM report estimated in-

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(UNAUDITED)

service dates of November 2021 and November 2022 for Units 3 and 4, respectively. The schedule extension announced in February 2022 triggered the requirement for a vote to continue construction and all the Vogtle Owners voted to continue construction. The filing of the Application with the Georgia PSC, which included Georgia Power's public announcement of its intention not to submit for rate recovery an amount that is greater than the first 6% of costs during any six-month VCM reporting period, triggered the requirement for a vote to continue construction and all the Vogtle Owners voted to continue construction. See "Plant Vogtle Units 3 and 4 Prudency Proceeding" herein for additional information on Georgia Power's prudency application filing.

Georgia Power and the other Vogtle Owners did not agree on either the starting dollar amount for the determination of cost increases subject to the cost-sharing and tender provisions of the Global Amendments or the extent to which COVID-19-related costs impact those provisions. The other Vogtle Owners notified Georgia Power that they believed the project capital cost forecast approved by the Vogtle Owners in February 2022 triggered the tender provisions. In June 2022 and July 2022, OPC and Dalton, respectively, notified Georgia Power of their purported exercises of their tender options. Georgia Power did not accept these purported tender exercises.

In June 2022, OPC and MEAG Power each filed a separate lawsuit against Georgia Power in the Superior Court of Fulton County, Georgia seeking a declaratory judgment that the starting dollar amount is $17.1 billion and that the cost-sharing and tender provisions had been triggered. The lawsuits also assert other claims, including breach of contract allegations, and seek, among other remedies, damages and injunctive relief requiring Georgia Power to track and allocate construction costs consistent with MEAG Power's and OPC's interpretations of the Global Amendments. In July 2022, Georgia Power filed its answers in the lawsuits filed by MEAG Power and OPC and included counterclaims seeking a declaratory judgment that the starting dollar amount is $18.38 billion and that costs related to force majeure events are excluded prior to calculating the cost-sharing and tender provisions and when calculating Georgia Power's related financial obligations. In September 2022, Dalton filed complaints in each of these lawsuits.

Also in September 2022, Georgia Power and MEAG Power reached an agreement to resolve their dispute regarding the proper interpretation of the cost-sharing and tender provisions of the Global Amendments. Under the terms of the agreement, among other items, (i) MEAG Power will not exercise its tender option and will retain its full ownership interest in Plant Vogtle Units 3 and 4; (ii) Georgia Power will reimburse a portion of MEAG Power's costs of construction for Plant Vogtle Units 3 and 4 as such costs are incurred and with no further adjustment for force majeure costs, which payments will total approximately $92 million based on the current project capital cost forecast; and (iii) Georgia Power will reimburse 20% of MEAG Power's costs of construction with respect to any amounts over the current project capital cost forecast, with no further adjustment for force majeure costs. In addition, MEAG Power agreed to vote to continue construction upon occurrence of a Project Adverse Event unless the commercial operation date of either of Plant Vogtle Unit 3 or Unit 4 is not projected to occur by December 31, 2025. In October 2022, MEAG Power and Georgia Power filed a notice of settlement and voluntary dismissal of their pending litigation, including Georgia Power's counterclaim, and Dalton dismissed its related complaint.

On October 5, 2023 and October 17, 2023, Georgia Power reached agreements with OPC and Dalton, respectively, to resolve its respective dispute with each of OPC and Dalton regarding the proper interpretation of the cost-sharing and tender provisions of the joint ownership agreements relating to the Global Amendments. Under the terms of the agreements with OPC and Dalton, among other items, (i) each of OPC and Dalton retracted its exercise of the tender option and will retain its full ownership interest in Plant Vogtle Units 3 and 4, (ii) Georgia Power made payments immediately after execution of the agreements of $308 million and $17 million to OPC and Dalton, respectively, representing payment for a portion of each of OPC's and Dalton's costs of construction for Plant Vogtle Units 3 and 4 previously incurred, (iii) Georgia Power will pay a portion of each of OPC's and Dalton's further costs of construction for Plant Vogtle Units 3 and 4 as such costs are incurred and with no further adjustment for force majeure costs, which payments will be in an aggregate amount of approximately $105 million and $6 million for OPC and Dalton, respectively, based on the current project capital cost forecast, and (iv) Georgia Power will pay 66% of each of OPC's and Dalton's costs of construction with respect to any amounts above the current project capital cost forecast, with no further adjustment for force majeure costs. On October 23, 2023, OPC, Dalton, and

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(UNAUDITED)

Georgia Power filed a stipulation of dismissal with prejudice of their litigation described above, including Georgia Power's counterclaims.

Georgia Power recorded pre-tax charges to income through the fourth quarter 2022 of $407 million ($304 million after tax) associated with the cost-sharing provisions of the Global Amendments, including the settlement with MEAG Power. Based on the current project capital cost forecast and the settlements with OPC and Dalton described above, Georgia Power recorded a pre-tax charge to income of approximately $160 million ($120 million after tax) in the third quarter 2023. These charges are included in the total project capital cost forecast and will not be recovered from retail customers.

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

Regulatory Matters

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At September 30, 2023, Georgia Power had recovered approximately $3.0 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 is not recording AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery. In December 2022, the Georgia PSC approved Georgia Power's filing to increase the NCCR tariff by $36 million annually, effective January 1, 2023. On November 1, 2023, Georgia Power filed a request to continue the current NCCR tariff for 2024, pending Georgia PSC approval. See "Plant Vogtle Units 3 and 4 Prudency Proceeding" herein for additional information on the NCCR tariff following commercial operation of Unit 4.

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 at that time) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%,

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effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that effective the first month after Unit 3 reaches commercial operation, retail base rates would be adjusted to include the costs related to Unit 3 and common facilities deemed prudent in the Vogtle Cost Settlement Agreement. On July 31, 2023, Georgia Power notified the Georgia PSC that Unit 3 had reached commercial operation, and, effective August 1, 2023, Georgia Power adjusted retail base rates for Unit 3 and the common facilities shared between Units 3 and 4 (see "Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" herein for additional information). On August 19, 2023, fuel load for Unit 4 was completed, and, on August 30, 2023, Georgia Power filed an application to adjust rates to include reasonable and prudent Plant Vogtle Units 3 and 4 costs (see "Plant Vogtle Units 3 and 4 Prudency Proceeding" herein for additional information).

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 $300 million in 2022 and are estimated to have negative earnings impacts of approximately $290 million in 2023 and $60 million in 2024. 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. See "Plant Vogtle Units 3 and 4 Prudency Proceeding" herein for additional information on impacts to the NCCR tariff if commercial operation for Unit 4 is not achieved by March 31, 2024.

In the August 2021 order approving the twenty-fourth VCM report, the Georgia PSC approved a stipulation addressing the following matters: (i) beginning with its twenty-fifth VCM report, Georgia Power will continue to report to the Georgia PSC all costs incurred during the period for review and will request for approval costs up to the $7.3 billion determined to be reasonable in the Georgia PSC's seventeenth VCM order and (ii) Georgia Power will not seek rate recovery of the $0.7 billion increase to the base capital cost forecast included in the nineteenth VCM report and charged to income by Georgia Power in the second quarter 2018. In addition, the August 2021 stipulation confirmed that Georgia Power may request verification and approval of costs above $7.3 billion for inclusion in rate base at a later time, but no earlier than the prudence review contemplated by the seventeenth VCM order described previously. See "Plant Vogtle Units 3 and 4 Prudency Proceeding" herein for additional information on Georgia Power's request for verification and approval of costs above $7.3 billion for inclusion in rate base.

The Georgia PSC approved 25 VCM reports covering periods through June 30, 2021. These reports reflect total construction capital costs incurred of $7.9 billion (net of $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds), of which the Georgia PSC has verified and approved $7.3 billion as described above. The Georgia PSC also has reviewed three additional VCM reports, which reflected $1.6 billion of additional construction capital costs incurred through December 31, 2022. Georgia Power filed its twenty-ninth VCM report with the Georgia PSC on August 30, 2023, which reflects the revised capital cost forecast as of June 30, 2023 of $10.6 billion and $390 million of construction capital costs incurred from January 1, 2023 through June 30, 2023.

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

Mississippi Power

Performance Evaluation Plan

On June 13, 2023, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2023 indicating no change in retail rates.

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Ad Valorem Tax Adjustment

On May 2, 2023, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment filing for 2023, resulting in a $7 million annual decrease in revenues effective with the first billing cycle of June 2023.

Mississippi Power's operating revenues are adjusted for differences in actual recoverable ad valorem taxes and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on Mississippi Power's revenues or net income but will affect operating cash flows.

Environmental Compliance Overview Plan

On April 4, 2023, the Mississippi PSC approved Mississippi Power's annual ECO Plan filing for 2023, resulting in a $3 million annual increase in revenues effective with the first billing cycle of May 2023.

System Restoration Rider

On April 4, 2023, the Mississippi PSC approved Mississippi Power's annual SRR filing, which indicated no change in retail rates. Mississippi Power's minimum annual SRR accrual was increased from $8 million to $12 million.

Municipal and Rural Associations Tariff

On October 27, 2023, the FERC approved a settlement agreement filed by Mississippi Power and Cooperative Energy on July 31, 2023 related to Mississippi Power's July 2022 request for a $23 million increase in annual wholesale base revenues under the MRA tariff. The settlement agreement provides for a $16 million increase in annual wholesale base revenues, effective September 14, 2022, and a refund to customers of approximately $6 million primarily related to the difference between the approved rates and interim rates.

Integrated Resource Plans

In October 2023, Mississippi Power signed an affiliate PPA with Georgia Power for 750 MWs of capacity and energy starting January 2024 through December 2028. In order to fulfill this agreement and serve the interests of customers, Mississippi Power will need to delay the anticipated retirement of certain electric generating units, as identified in its 2021 IRP. Mississippi Power is expected to file its next IRP in April 2024 in accordance with the rules and orders of the Mississippi PSC.

Southern Company Gas

Infrastructure Replacement Programs and Capital Projects

Capital expenditures incurred under specific infrastructure replacement programs and capital projects during the first nine months of 2023 were as follows:

Utility	Program	Nine Months Ended September 30, 2023
		(in millions)
Nicor Gas	Investing in Illinois	$	320
Virginia Natural Gas	SAVE	56
Atlanta Gas Light	System Reinforcement Rider	84
Chattanooga Gas	Pipeline Replacement Program	7
Total		$	467

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Nicor Gas

On June 15, 2023, the Illinois Commission concluded its review of the Qualifying Infrastructure Plant (QIP) capital investments by Nicor Gas for calendar year 2019 under the QIP Rider, also referred to as Investing in Illinois, program. The Illinois Commission disallowed $32 million of the $415 million of capital investments commissioned in 2019, together with the related return on investment. Nicor Gas recorded a pre-tax charge to income in the second quarter 2023 of $38 million ($28 million after tax) associated with the disallowance of capital investments. The disallowance is reflected on the statement of income as an $8 million reduction to revenues and a $30 million increase in operating expenses. On August 3, 2023, the Illinois Commission denied a rehearing request filed by Nicor Gas. On August 24, 2023, Nicor Gas filed a notice of appeal with the Illinois Appellate Court. Nicor Gas defends these investments in infrastructure as prudently incurred. The Illinois Commission has not yet conducted its review for calendar years 2020 through 2022 or the nine months ended September 30, 2023. Any further disallowance by the Illinois Commission could be material. The ultimate outcome of these matters cannot be determined at this time.

Rate Proceedings

Atlanta Gas Light

On July 14, 2023, Atlanta Gas Light filed its annual GRAM update with the Georgia PSC. The filing requests an annual base rate increase of $53 million based on the projected 12-month period beginning January 1, 2024. Resolution of the GRAM filing is expected by December 31, 2023, with new rates effective January 1, 2024. The ultimate outcome of this matter cannot be determined at this time.

Virginia Natural Gas

On August 28, 2023, the Virginia Commission approved a stipulation agreement related to Virginia Natural Gas' August 2022 general base rate case filing. The approved agreement provides for a $48 million increase in annual base rate revenues, including the recovery of investments under the SAVE program, an ROE of 9.70%, and an equity ratio of 49.06%. Interim rates became effective January 1, 2023, subject to refund, based on Virginia Natural Gas' original requested increase of approximately $69 million. Refunds to customers related to the difference between the approved rates effective September 1, 2023 and the interim rates will be completed later in the fourth quarter 2023.

(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 and Mississippi Power

In 2010, the DOE, through a cooperative agreement with SCS, agreed to fund $270 million of the Kemper County energy facility through the grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2. In 2016, additional DOE grants in the amount of $137 million were awarded to the Kemper County energy facility. In 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of total grants received. In 2020, Mississippi Power and Southern Company executed an agreement with the DOE completing Mississippi Power's request, which enabled Mississippi Power to proceed with full dismantlement of the abandoned gasifier-related assets and site restoration activities. In connection with the DOE closeout discussions, in 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of a civil investigation related to the DOE grants. On August 4, 2023, the U.S. District Court for the Northern District of Georgia unsealed a civil action in which defendants Southern Company, SCS, and Mississippi Power are alleged to have violated certain provisions of the False Claims Act by fraudulently inducing the DOE to disburse funds pursuant to the grants. The federal government declined to intervene in the action. On October 30, 2023, the plaintiff, a former SCS employee, filed an amended complaint, again alleging certain violations of the False Claims Act. The plaintiff seeks to recover all damages incurred personally and on behalf of the government caused by the defendants' alleged violations, as well as treble damages and attorneys' fees, among other relief. The ultimate outcome of this matter cannot be determined at this time; however, an adverse outcome could have a material impact on Southern Company's and Mississippi Power's financial statements.

Alabama Power

In September 2022, Mobile Baykeeper filed a citizen suit in the U.S. District Court for the Southern District of Alabama alleging that Alabama Power's plan to close the Plant Barry ash pond utilizing a closure-in-place methodology violates the Resource Conservation and Recovery Act (RCRA) and regulations governing CCR. Among other relief requested, Mobile Baykeeper seeks a declaratory judgment that the RCRA and regulations governing CCR are being violated, preliminary and injunctive relief to prevent implementation of Alabama Power's closure plan and the development of a closure plan that satisfies regulations governing CCR requirements. On December 19, 2022, Alabama Power filed a motion to dismiss the case. On September 30, 2023, the magistrate judge issued a report and recommendation to deny Alabama Power's motion to dismiss, to which Alabama Power has filed objections.

On January 31, 2023, the EPA issued a Notice of Potential Violations associated with Alabama Power's plan to close the Plant Barry ash pond. Alabama Power has affirmed to the EPA its position that it is in compliance with CCR requirements.

The ultimate outcome of these matters cannot be determined at this time but could have a material impact on Alabama Power's ARO estimates and cash flows. See Note 6 to the financial statements in Item 8 of the Form 10-K for a discussion of Alabama Power's ARO liabilities.

Georgia Power

Municipal Franchise Fees

In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state law claims. This case has been ruled upon and appealed numerous times over the last several years. In 2019, the Georgia PSC issued an order that found Georgia Power has appropriately implemented the municipal franchise fee schedule. In March 2021, the Superior Court of Fulton County granted class certification and Georgia Power's motion for summary judgment and the plaintiffs filed a notice of appeal. In April 2021, Georgia Power filed a notice of cross appeal on the issue of class certification. In December 2021, the Georgia Court of Appeals affirmed the Superior Court's ruling that granted summary judgment to Georgia Power and dismissed Georgia Power's cross appeal on the

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issue of class certification as moot. Also in December 2021, the plaintiffs filed a petition for writ of certiorari to the Georgia Supreme Court, which was denied on January 27, 2023. On February 6, 2023, the plaintiffs filed a motion for reconsideration with the Georgia Supreme Court, which was denied on February 16, 2023. This matter is now concluded.

Plant Scherer

In July 2020, a group of individual plaintiffs filed a complaint, which was amended in December 2022, in the Superior Court of Fulton County, Georgia against Georgia Power alleging that the construction and operation of Plant Scherer has impacted groundwater 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 December 2022, the Superior Court of Fulton County, Georgia granted Georgia Power's motion to transfer the case to the Superior Court of Monroe County, Georgia. On May 9, 2023, the Superior Court of Monroe County, Georgia denied Georgia Power's motion to dismiss the case for lack of subject matter jurisdiction. On July 27, 2023, the Superior Court of Monroe County, Georgia denied the remaining motions to dismiss certain claims and plaintiffs that Georgia Power filed at the outset of the case.

In October 2021, February 2022, and January 2023, a total of eight additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs sought an unspecified amount of monetary damages including punitive damages. After Georgia Power removed these cases to the U.S. District Court for the Middle District of Georgia, the plaintiffs voluntarily dismissed their complaints without prejudice in November 2022 and January 2023. On May 12, 2023, the plaintiffs in the cases originally filed in October 2021, February 2022, and January 2023 refiled their eight complaints in the Superior Court of Monroe County, Georgia. Also on May 12, 2023, a new complaint was filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that the construction and operation of Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries. The plaintiff seeks an unspecified amount of monetary damages, including punitive damages. On May 18, 2023, Georgia Power removed all of these cases to the U.S. District Court for the Middle District of Georgia. The plaintiffs are requesting the court remand the cases back to the Superior Court of Monroe County, Georgia.

The amount of possible loss, if any, from these matters cannot be estimated at this time.

Mississippi Power

In 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi, which was amended in March 2019 to include four additional plaintiffs. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper and make claims for gross negligence, reckless conduct, and intentional wrongdoing. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. The district court dismissed the amended complaint; however, in March 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. In July 2020, the plaintiffs filed a motion for leave to file a third amended complaint, which included the same federal claims as the proposed second amended complaint, as well as several additional state law claims based on the allegation that Mississippi Power failed to disclose the annual percentage rate of interest applicable to refunds. In November 2020, the district court denied each of the plaintiffs' pending

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motions and entered final judgment in favor of Mississippi Power. In January 2021, the district court denied further motions by the plaintiffs to vacate the judgment and to file a revised second amended complaint. In February 2021, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fifth Circuit. In March 2022, the U.S. Court of Appeals for the Fifth Circuit issued an opinion affirming the dismissal of the claims against the Mississippi PSC defendants but reversing the dismissal of the claims against Mississippi Power. In May 2022, the U.S. Court of Appeals for the Fifth Circuit denied a petition by Mississippi Power for a rehearing en banc and remanded the case to the U.S. District Court for the Southern District of Mississippi for further proceedings. In June 2022, Mississippi Power filed with the trial court a motion to dismiss the complaint with prejudice, which was granted on March 15, 2023. On March 28, 2023, 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.

Southern Power

In July 2021, Southern Power and certain of its subsidiaries filed an arbitration demand with the American Arbitration Association against First Solar for defective design of actuators on trackers and inverters installed by First Solar under the engineering, procurement, and construction agreements associated with five solar projects owned by Southern Power and partners and managed by Southern Power. In February 2023, arbitration hearings concluded. In July 2023, an interim award of approximately $36 million was entered in favor of Southern Power and was subsequently received in September 2023. The interim award included $18 million representing recovery of losses associated with replacement costs, penalty payments, and lost revenues previously incurred. This recovery is reflected in Southern Power's third quarter and year-to-date 2023 statements of income as an $11 million reduction to other operations and maintenance expense and a $7 million increase in other revenues, with $6 million allocated through noncontrolling interests to Southern Power's partners. The remaining $18 million in award proceeds received in excess of the losses incurred is recognized on the balance sheet at September 30, 2023 as restricted cash and a liability to fund future replacement costs. The parties are awaiting issuance of a final award. The ultimate outcome of this matter cannot be determined at this time.

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 $14 million and $15 million at September 30, 2023 and December 31, 2022, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.

Southern Company Gas' environmental remediation liability was $234 million and $256 million at September 30, 2023 and December 31, 2022, 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.

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Other Matters

Traditional Electric Operating Companies

In April 2019, Bellsouth Telecommunications d/b/a AT&T Alabama (AT&T) filed a complaint against Alabama Power with the FCC alleging that the pole rental rate AT&T is required to pay pursuant to the parties' joint use agreement is unjust and unreasonable under federal law. The complaint sought a new rate and approximately $87 million in refunds of alleged overpayments for the preceding six years. In August 2019, the FCC stayed the case in favor of arbitration, which AT&T has not pursued. The ultimate outcome of this matter cannot be determined at this time, but an adverse outcome could have a material impact on the financial statements of Southern Company and Alabama Power. Georgia Power and Mississippi Power have joint use agreements with other AT&T affiliates.

Mississippi Power

In August 2022, the Mississippi Department of Revenue (Mississippi DOR) completed an audit of sales and use taxes paid by Mississippi Power from 2016 to 2019 and entered a final assessment, indicating a total amount due of $28 million, including associated penalties and interest. In October 2022, Mississippi Power filed an administrative appeal with the Mississippi DOR contesting the assessment. On October 2, 2023, Mississippi Power and the Mississippi DOR reached a settlement agreement on an assessment of approximately $11 million including associated penalties and interest, $7 million of which was previously paid by Mississippi Power. On October 5, 2023, Mississippi Power made a final $4 million payment and considers this matter closed.

Pursuant to an accounting order approved by the Mississippi PSC in December 2022, Mississippi Power deferred $3 million of the agreed upon assessment related to taxes and associated interest to a regulatory asset for disposition in a future rate proceeding.

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(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.

The following table disaggregates revenue from contracts with customers for the three and nine months ended September 30, 2023 and 2022:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2023
Operating revenues
Retail electric revenues
Residential	$	2,543	$	969	$	1,473	$	101	$	—	$	—
Commercial	1,845		599		1,151		95		—		—
Industrial	1,116		498		528		90		—		—
Other	30		3		25		2		—		—
Total retail electric revenues	5,534		2,069		3,177		288		—		—
Natural gas distribution revenues
Residential	217		—		—		—		—		217
Commercial	56		—		—		—		—		56
Transportation	275		—		—		—		—		275
Industrial	4		—		—		—		—		4
Other	60		—		—		—		—		60
Total natural gas distribution revenues	612		—		—		—		—		612
Wholesale electric revenues
PPA energy revenues	317		66		31		2		226		—
PPA capacity revenues	151		26		13		3		110		—
Non-PPA revenues	101		15		21		137		126		—
Total wholesale electric revenues	569		107		65		142		462		—
Other natural gas revenues
Gas marketing services	54		—		—		—		—		54
Other natural gas revenues	8		—		—		—		—		8
Total natural gas revenues	62		—		—		—		—		62
Other revenues	330		54		146		10		18		—
Total revenue from contracts with customers	7,107		2,230		3,388		440		480		674
Other revenue sources(*)	(127)		(147)		(151)		(4)		173		15
Total operating revenues	$	6,980	$	2,083	$	3,237	$	436	$	653	$	689

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	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Nine Months Ended September 30, 2023
Operating revenues
Retail electric revenues
Residential	$	5,717	$	2,277	$	3,202	$	238	$	—	$	—
Commercial	4,464		1,493		2,733		238		—		—
Industrial	2,770		1,324		1,195		251		—		—
Other	84		10		68		6		—		—
Total retail electric revenues	13,035		5,104		7,198		733		—		—
Natural gas distribution revenues
Residential	1,443		—		—		—		—		1,443
Commercial	370		—		—		—		—		370
Transportation	878		—		—		—		—		878
Industrial	33		—		—		—		—		33
Other	228		—		—		—		—		228
Total natural gas distribution revenues	2,952		—		—		—		—		2,952
Wholesale electric revenues
PPA energy revenues	853		196		66		8		601		—
PPA capacity revenues	490		130		38		36		289		—
Non-PPA revenues	199		49		30		315		312		—
Total wholesale electric revenues	1,542		375		134		359		1,202		—
Other natural gas revenues
Gas marketing services	358		—		—		—		—		358
Other natural gas revenues	28		—		—		—		—		28
Total natural gas revenues	386		—		—		—		—		386
Other revenues	971		159		422		31		46		—
Total revenue from contracts with customers	18,886		5,638		7,754		1,123		1,248		3,338
Other revenue sources(*)	322		(218)		51		14		438		79
Total operating revenues	$	19,208	$	5,420	$	7,805	$	1,137	$	1,686	$	3,417

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	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2022
Operating revenues
Retail electric revenues
Residential	$	2,104	$	799	$	1,212	$	93	$	—	$	—
Commercial	1,637		499		1,051		87		—		—
Industrial	1,183		452		642		89		—		—
Other	27		3		22		2		—		—
Total retail electric revenues	4,951		1,753		2,927		271		—		—
Natural gas distribution revenues
Residential	331		—		—		—		—		331
Commercial	93		—		—		—		—		93
Transportation	259		—		—		—		—		259
Industrial	12		—		—		—		—		12
Other	49		—		—		—		—		49
Total natural gas distribution revenues	744		—		—		—		—		744
Wholesale electric revenues
PPA energy revenues	812		187		40		4		591		—
PPA capacity revenues	175		56		12		1		107		—
Non-PPA revenues	58		67		4		242		303		—
Total wholesale electric revenues	1,045		310		56		247		1,001		—
Other natural gas revenues
Gas marketing services	84		—		—		—		—		84
Other natural gas revenues	15		—		—		—		—		15
Total natural gas revenues	99		—		—		—		—		99
Other revenues	277		65		110		13		9		—
Total revenue from contracts with customers	7,116		2,128		3,093		531		1,010		843
Other revenue sources(*)	1,262		316		796		(21)		170		14
Total operating revenues	$	8,378	$	2,444	$	3,889	$	510	$	1,180	$	857

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	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Nine Months Ended September 30, 2022
Operating revenues
Retail electric revenues
Residential	$	5,282	$	2,049	$	2,995	$	238	$	—	$	—
Commercial	4,202		1,285		2,688		229		—		—
Industrial	2,914		1,143		1,529		242		—		—
Other	79		10		62		7		—		—
Total retail electric revenues	12,477		4,487		7,274		716		—		—
Natural gas distribution revenues
Residential	1,821		—		—		—		—		1,821
Commercial	493		—		—		—		—		493
Transportation	872		—		—		—		—		872
Industrial	60		—		—		—		—		60
Other	244		—		—		—		—		244
Total natural gas distribution revenues	3,490		—		—		—		—		3,490
Wholesale electric revenues
PPA energy revenues	1,739		354		112		11		1,285		—
PPA capacity revenues	443		135		35		4		273		—
Non-PPA revenues	182		166		19		511		572		—
Total wholesale electric revenues	2,364		655		166		526		2,130		—
Other natural gas revenues
Gas marketing services	417		—		—		—		—		417
Other natural gas revenues	41		—		—		—		—		41
Total natural gas revenues	458		—		—		—		—		458
Other revenues	810		173		327		34		27		—
Total revenue from contracts with customers	19,599		5,315		7,767		1,276		2,157		3,948
Other revenue sources(*)	2,633		708		1,451		3		461		50
Total operating revenues	$	22,232	$	6,023	$	9,218	$	1,279	$	2,618	$	3,998

(*)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 (including those related to fuel costs) that meet other scope exceptions for revenues from contracts with customers at the traditional electric operating companies.

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Contract Balances

The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers at September 30, 2023 and December 31, 2022:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Accounts Receivable
At September 30, 2023	$	2,680	$	858	$	1,175	$	106	$	138	$	331
At December 31, 2022	3,123		696		922		92		237		1,107
Contract Assets
At September 30, 2023	$	267	$	6	$	146	$	—	$	—	$	41
At December 31, 2022	156		2		89		—		—		—
Contract Liabilities
At September 30, 2023	$	62	$	—	$	8	$	2	$	8	$	—
At December 31, 2022	45		4		9		—		1		—

Contract assets for Georgia Power primarily relate to retail customer fixed bill programs, where the payment is contingent upon Georgia Power's continued performance and the customer's continued participation in the program over a one-year contract term, and unregulated service agreements, where payment is contingent on project completion. Contract liabilities for Georgia Power primarily relate to cash collections recognized in advance of revenue for unregulated service agreements. At September 30, 2023, Southern Company Gas' contract assets relate to work performed on an energy efficiency enhancement and upgrade contract with the U.S. General Services Administration. Southern Company Gas receives cash advances from a third-party financial institution to fund work performed, of which approximately $51 million had been received at September 30, 2023. These advances have been accounted for as long-term debt on the balance sheets. See Note 1 to the financial statements under "Affiliate Transactions" in Item 8 of the Form 10-K for additional information regarding the construction contract. At September 30, 2023 and December 31, 2022, Southern Company's unregulated distributed generation business had contract assets of $75 million and $65 million, respectively, and contract liabilities of $47 million and $32 million, respectively, for outstanding performance obligations.

Revenues recognized in the three and nine months ended September 30, 2023, which were included in contract liabilities at December 31, 2022, were immaterial for the applicable Registrants. Contract liabilities are primarily classified as current on the balance sheets as the corresponding revenues are generally expected to be recognized within one year.

Remaining Performance Obligations

The Subsidiary Registrants may enter into long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. For Alabama Power, Georgia Power, and Southern Power, these contracts primarily relate to PPAs whereby electricity and generation capacity are provided to a customer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. For Southern Company Gas, these contracts primarily relate to the U.S. General Services Administration contract described above. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain

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fixed price contracts. Revenues from contracts with customers related to these performance obligations remaining at September 30, 2023 are expected to be recognized as follows:

	2023 (remaining)		2024		2025		2026		2027		Thereafter
	(in millions)
Southern Company	$	166	$	599	$	359	$	318	$	319	$	2,245
Alabama Power	10		24		8		—		—		—
Georgia Power	23		66		34		14		14		23
Southern Power	84		356		302		303		310		2,233
Southern Company Gas	4		29		—		—		—		—

Lease Income

Lease income for the three and nine months ended September 30, 2023 and 2022 is as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
For the Three Months Ended September 30, 2023
Lease income - interest income on sales-type leases	$	6	$	—	$	—	$	4	$	2	$	—
Lease income - operating leases	36		3		7		—		21		9
Variable lease income	134		—		—		—		144		—
Total lease income	$	176	$	3	$	7	$	4	$	167	$	9
For the Nine Months Ended September 30, 2023
Lease income - interest income on sales-type leases	$	18	$	—	$	—	$	11	$	7	$	—
Lease income - operating leases	129		32		22		2		64		27
Variable lease income	327		1		—		—		351		—
Total lease income	$	474	$	33	$	22	$	13	$	422	$	27
For the Three Months Ended September 30, 2022
Lease income - interest income on sales-type leases	$	7	$	—	$	—	$	4	$	3	$	—
Lease income - operating leases	50		19		8		1		21		9
Variable lease income	139		—		—		—		145		—
Total lease income	$	196	$	19	$	8	$	5	$	169	$	9
For the Nine Months Ended September 30, 2022
Lease income - interest income on sales-type leases	$	19	$	—	$	—	$	11	$	8	$	—
Lease income - operating leases	149		58		24		1		64		27
Variable lease income	355		1		—		—		372		—
Total lease income	$	523	$	59	$	24	$	12	$	444	$	27

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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(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 Company

At September 30, 2023 and December 31, 2022, Southern Holdings had equity method investments totaling $126 million and $112 million, respectively, primarily related to investments in venture capital funds focused on energy and utility investments. Earnings from these investments were immaterial for all periods presented.

Southern Power

Variable Interest Entities

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

SP Solar and SP Wind

At September 30, 2023 and December 31, 2022, SP Solar had total assets of $5.8 billion and $5.9 billion, respectively, total liabilities of $0.4 billion, and noncontrolling interests of $1.1 billion. Cash distributions from SP Solar are allocated 67% to Southern Power and 33% to the limited partner in accordance with their partnership interest percentage. Under the terms of the limited partnership agreement, distributions without limited partner consent are limited to available cash and SP Solar is obligated to distribute all such available cash to its partners each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves.

At September 30, 2023 and December 31, 2022, SP Wind had total assets of $2.2 billion, total liabilities of $184 million and $169 million, respectively, and noncontrolling interests of $38 million and $39 million, respectively. Under the terms of the limited liability agreement, distributions without Class A member consent are limited to available cash and SP Wind is obligated to distribute all such available cash to its members each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves. Cash distributions from SP Wind are generally allocated 60% to Southern Power and 40% to the three financial investors in accordance with the limited liability agreement.

Southern Power consolidates both SP Solar and SP Wind, as the primary beneficiary, since it controls the most significant activities of each entity, including operating and maintaining their assets. Certain transfers and sales of the assets in the VIEs are subject to partner consent and the liabilities are non-recourse to the general credit of Southern Power. Liabilities consist of customary working capital items and do not include any long-term debt.

Other Variable Interest Entities

Southern Power has other consolidated VIEs that relate to certain subsidiaries that have either sold noncontrolling interests to tax equity investors or acquired less than a 100% interest from facility developers. These entities are considered VIEs because the arrangements are structured similar to a limited partnership and the noncontrolling members do not have substantive kick-out rights.

At September 30, 2023 and December 31, 2022, the other VIEs had total assets of $1.7 billion and $1.8 billion, respectively, total liabilities of $0.2 billion, and noncontrolling interests of $0.8 billion. Under the terms of the partnership agreements, distributions of all available cash are required each month or quarter and additional distributions require partner consent.

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Equity Method Investments

At December 31, 2022, Southern Power had equity method investments in wind and battery energy storage projects totaling $49 million. During the first quarter 2023, Southern Power sold its remaining equity method investments in the projects and received proceeds of $50 million. Earnings (loss) from these investments, including the gains associated with the sales, were immaterial for all periods presented.

Southern Company Gas

Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments at September 30, 2023 and December 31, 2022 and related earnings from those investments for the three and nine months ended September 30, 2023 and 2022 were as follows:

Investment Balance	September 30, 2023		December 31, 2022
	(in millions)
SNG	$	1,210	$	1,243
Other	33		33
Total	$	1,243	$	1,276

	Three Months Ended September 30,				Nine Months Ended September 30,
Earnings from Equity Method Investments	2023		2022		2023		2022
	(in millions)
SNG	$	32	$	34	$	104	$	104
Other	—		—		—		1
Total	$	32	$	34	$	104	$	105

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(F) FINANCING AND LEASES

Bank Credit Arrangements

See Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K for additional information.

At September 30, 2023, committed credit arrangements with banks were as follows:

	Expires
Company	2024		2025		2026		2028		Total		Unused		Expires within One Year
	(in millions)
Southern Company parent(a)	$	150	$	—	$	—	$	1,850	$	2,000	$	1,998	$	150
Alabama Power	—		—		650		700		1,350		1,350		—
Georgia Power	—		—		—		1,750		1,750		1,726		—
Mississippi Power	—		125		150		—		275		275		—
Southern Power(a)(b)	—		—		—		600		600		589		—
Southern Company Gas(c)	100		—		—		1,500		1,600		1,598		100
SEGCO	30		—		—		—		30		30		30
Southern Company	$	280	$	125	$	800	$	6,400	$	7,605	$	7,566	$	280

(a)Arrangement expiring in 2028 represents a $2.45 billion combined arrangement for Southern Company and Southern Power as borrowers. Pursuant to the combined facility, the allocations between Southern Company and Southern Power may be adjusted.

(b)Does not include Southern Power Company's $75 million and $100 million continuing letter of credit facilities for standby letters of credit, expiring in 2025 and 2026, respectively, of which $9 million and $16 million, respectively, was unused at September 30, 2023. In March 2023, Southern Power amended the $100 million letter of credit facility, which, among other things, extended the expiration date from 2025 to 2026 and increased the amount from $75 million. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.

(c)Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $800 million of the credit arrangement expiring in 2028. Southern Company Gas' committed credit arrangement expiring in 2028 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 2028, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. Nicor Gas is also the borrower under a $100 million credit arrangement expiring in 2024.

As reflected in the table above, in May 2023, Southern Company and Southern Power combined and extended their multi-year credit arrangements previously maturing in 2026, resulting in a single aggregate $2.45 billion facility (currently allocated $1.85 billion for Southern Company and $600 million for Southern Power) maturing in 2028. Pursuant to the combined facility, the allocations between Southern Company and Southern Power may be adjusted. Alabama Power, Georgia Power, and Southern Company Gas Capital, along with Nicor Gas, amended and restated certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2026 to 2028. Mississippi Power amended and restated certain of its multi-year credit arrangements aggregating $150 million, which, among other things, extended the maturity dates from 2024 to 2026. Nicor Gas also entered into a $100 million credit arrangement maturing in 2024 to replace its $250 million credit arrangement that expired in 2023. In June 2023, Southern Company also entered into a new $150 million credit arrangement maturing in 2024. In August 2023, Alabama Power amended and restated one of its multi-year credit arrangements, which, among other things, extended the maturity date from 2024 to 2026 and increased the borrowing capacity from $550 million to $650 million.

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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 provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. The cross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2023, 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 certain revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. At September 30, 2023, outstanding variable rate demand revenue bonds of the traditional electric operating companies with allocated liquidity support totaled approximately $1.7 billion (comprised of approximately $818 million at Alabama Power, $819 million at Georgia Power, and $69 million at Mississippi Power). In addition, at September 30, 2023, Alabama Power and Georgia Power had approximately $120 million and $325 million, respectively, of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months. The variable rate demand revenue bonds and fixed rate revenue bonds required to be remarketed within the next 12 months are classified as long-term debt on the balance sheets as a result of available long-term committed credit.

Convertible Senior Notes

In February 2023, Southern Company issued $1.5 billion aggregate principal amount of Series 2023A 3.875% Convertible Senior Notes due December 15, 2025 (Series 2023A Convertible Senior Notes). In March 2023, Southern Company issued an additional $225 million aggregate principal amount of the Series 2023A Convertible Senior Notes upon the exercise by the initial purchasers of their over-allotment option.

Interest on the Series 2023A Convertible Senior Notes is payable semiannually, which began on June 15, 2023. The Series 2023A Convertible Senior Notes will mature on December 15, 2025, unless earlier converted or repurchased, but are not redeemable at the option of Southern Company. The Series 2023A Convertible Senior Notes are direct, unsecured, and unsubordinated obligations of Southern Company, ranking equally with all of Southern Company's other unsecured and unsubordinated indebtedness from time to time outstanding, and are effectively subordinated to all secured indebtedness of Southern Company.

Holders may convert their Series 2023A Convertible Senior Notes at their option prior to the close of business on the business day preceding September 15, 2025, but only under the following circumstances:

•during any calendar quarter (and only during such calendar quarter), if the last reported sale price of Southern Company's common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day as determined by Southern Company;

•during the five business day period after any 10 consecutive trading day period (Measurement Period) in which the trading price per $1,000 principal amount of Series 2023A Convertible Senior Notes for each trading day of the Measurement Period was less than 98% of the product of the last reported sale price of the common stock and the conversion rate on each such trading day; or

•upon the occurrence of certain corporate events specified in the indenture governing the Series 2023A Convertible Senior Notes.

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On or after September 15, 2025, a holder may convert all or any portion of its Series 2023A Convertible Senior Notes at any time prior to the close of business on the second scheduled trading day immediately preceding the maturity date regardless of the foregoing conditions.

Southern Company will settle conversions of the Series 2023A Convertible Senior Notes by paying cash up to the aggregate principal amount of the Series 2023A Convertible Senior Notes to be converted and paying or delivering, as the case may be, cash, shares of common stock or a combination of cash and shares of common stock, at Southern Company's election, in respect of the remainder, if any, of Southern Company's conversion obligation in excess of the aggregate principal amount of the Series 2023A Convertible Senior Notes being converted. The Series 2023A Convertible Senior Notes are initially convertible at a rate of 11.8818 shares of common stock per $1,000 principal amount converted, which is approximately equal to $84.16 per share of common stock. The conversion rate will be subject to adjustment upon the occurrence of certain specified events but will not be adjusted for accrued and unpaid interest. In addition, upon the occurrence of a make-whole fundamental change (as defined in the indenture governing the Series 2023A Convertible Senior Notes), Southern Company will, in certain circumstances, increase the conversion rate by a number of additional shares of common stock for conversions in connection with the make-whole fundamental change.

Upon the occurrence of a fundamental change (as defined in the indenture governing the Series 2023A Convertible Senior Notes), holders of the Series 2023A Convertible Senior Notes may require Southern Company to purchase all or a portion of their Series 2023A Convertible Senior Notes, in principal amounts equal to $1,000 or an integral multiple thereof, for cash at a price equal to 100% of the principal amount of the Series 2023A Convertible Senior Notes to be purchased plus any accrued and unpaid interest.

Earnings per Share

For Southern Company, the only difference in computing basic and diluted earnings per share (EPS) is attributable to awards outstanding under stock-based compensation plans and the Series 2023A Convertible Senior Notes. EPS dilution resulting from stock-based compensation plans is determined using the treasury stock method and EPS dilution resulting from the Series 2023A Convertible Senior Notes is determined using the net share settlement method. See Note 12 to the financial statements in Item 8 of the Form 10-K and "Convertible Senior Notes" herein for additional information. Shares used to compute diluted EPS were as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2023	2022	2023	2022
	(in millions)
As reported shares	1,092	1,082	1,092	1,070
Effect of stock-based compensation	7	6	6	6
Diluted shares	1,099	1,088	1,098	1,076

For all periods presented, an immaterial number of stock-based compensation awards was excluded from the diluted EPS calculation because the awards were anti-dilutive.

For all periods presented, there was no dilution resulting from the Series 2023A Convertible Senior Notes.

Southern Company Leveraged Lease

See Note 9 to the financial statements in Item 8 of the Form 10-K for information on a leveraged lease agreement related to energy generation. In June 2022, the Southern Holdings subsidiary operating the generating plant for the lessee provided notice to the lessee to terminate the related operating and maintenance agreement effective June 30, 2023. Subsequently, the lessee failed to make the semi-annual lease payment due in December 2022. As a result, the Southern Holdings subsidiary was unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. The parties to the lease entered into forbearance agreements which suspended the related contractual rights of the parties while they continued restructuring negotiations, during which

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(UNAUDITED)

the termination date for the operating and maintenance agreement was delayed until July 31, 2023. The negotiations were completed on July 14, 2023, resulting in the Southern Holdings subsidiary agreeing to continue operating the plant for the lessee until the lessee's associated power off-take agreement ends in 2032, subject to certain terms and conditions. The restructuring had no material impact on Southern Company's financial statements. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to meet its obligations, including those associated with a future closure or retirement of the generation assets and associated properties, including the dry ash landfill.

(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 $1.0 billion and $1.1 billion at September 30, 2023 and December 31, 2022, respectively.

Southern Company's federal PTC and ITC carryforwards begin expiring in 2031, but are expected to be fully utilized by 2028. 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, changes in taxable income projections, transfer of eligible credits, and potential income tax rate changes. In the third quarter 2023, Georgia Power started generating advanced nuclear PTCs for Plant Vogtle Unit 3 beginning on the in-service date of July 31, 2023. In addition, pursuant to the Global Amendments to the Vogtle Joint Ownership Agreements (as defined in Note (B) under "Georgia Power – Nuclear Construction – Joint Owner Contracts"), Georgia Power is purchasing advanced nuclear PTCs for Plant Vogtle Unit 3 from certain other Vogtle Owners. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.

Effective Tax Rate

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

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

Southern Company

Southern Company's effective tax rate was 13.9% for the nine months ended September 30, 2023 compared to 20.0% for the corresponding period in 2022. The effective tax rate decrease was primarily due to an increase in the flowback of certain excess deferred income taxes at Alabama Power in 2023, lower pre-tax earnings in 2023, and an adjustment related to state tax credit carryforwards and the related valuation allowance at Georgia Power in 2022 and 2023, partially offset by the flowback of certain excess deferred income taxes ending in 2022 at Georgia Power.

Alabama Power

Alabama Power's effective tax rate was 8.3% for the nine months ended September 30, 2023 compared to 23.7% for the corresponding period in 2022. The effective tax rate decrease was primarily due to an increase in the flowback of certain excess deferred income taxes in 2023. See Note 2 to the financial statements under "Alabama Power – Excess Accumulated Deferred Income Tax Accounting Order" in Item 8 of the Form 10-K for additional information.

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Georgia Power

Georgia Power's effective tax rate was 18.2% for the nine months ended September 30, 2023 compared to 18.5% for the corresponding period in 2022. The effective tax rate decrease was primarily due to an adjustment related to state tax credit carryforwards in 2022, a decrease in a valuation allowance on certain state tax credit carryforwards in 2023, and lower pre-tax earnings in 2023, largely offset by the flowback of certain excess deferred income taxes ending in 2022.

Mississippi Power

Mississippi Power's effective tax rate was 16.9% for the nine months ended September 30, 2023 compared to 20.1% for the corresponding period in 2022. The effective tax rate decrease was primarily due to an increase in the flowback of certain excess deferred income taxes in 2023.

Southern Power

Southern Power's effective tax rate was 14.8% for the nine months ended September 30, 2023 compared to 18.8% for the corresponding period in 2022. The effective tax rate decrease was primarily due to changes in state apportionment methodology resulting from tax legislation enacted by the State of Tennessee in May 2023.

Unrecognized Tax Benefits

Southern Company's and Georgia Power's unrecognized tax positions balances at September 30, 2023 were $167 million and $86 million, respectively, compared to $80 million for Southern Company at December 31, 2022. The increases from prior periods are primarily related to the amendment of certain 2019 through 2021 state tax filing positions related to tax credit utilization. If effective settlement of the positions is favorable, these positions would decrease Southern Company's and Georgia Power's effective tax rates. The ultimate outcome of this unrecognized tax benefit, of which a portion is expected to be resolved within the next 12 months, is dependent on acceptance by the state or expiration of related statute of limitations.

Subsequent to September 30, 2023, a statute of limitations expired related to a 2019 state tax filing position to exclude certain gains from 2019 dispositions from taxation in a certain unitary state. This $44 million tax position and related interest will be recognized in the fourth quarter 2023 and will decrease Southern Company's annual effective tax rate.

(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, 2023. The Southern Company system also provides certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis. In addition, the Southern Company system provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund other postretirement trusts to the extent required by their respective regulatory commissions. Southern Company Gas has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.

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

On each Registrant's condensed statements of income, the service cost component of net periodic benefit costs is included in other operations and maintenance expenses and all other components of net periodic benefit costs are included in other income (expense), net. Components of the net periodic benefit costs for the three and nine months ended September 30, 2023 and 2022 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 September 30, 2023
Pension Plans
Service cost	$	69	$	16	$	17	$	2	$	2	$	6
Interest cost	156		37		48		7		2		11
Expected return on plan assets	(307)		(75)		(97)		(13)		(4)		(22)
Amortization:
Prior service costs	—		—		—		—		—		(1)
Regulatory asset	—		—		—		—		—		4
Net (gain) loss	8		2		4		1		—		(1)
Net periodic pension income	$	(74)	$	(20)	$	(28)	$	(3)	$	—	$	(3)
Postretirement Benefits
Service cost	$	4	$	1	$	1	$	—	$	—	$	—
Interest cost	18		5		6		1		—		2
Expected return on plan assets	(21)		(9)		(7)		(1)		—		(2)
Amortization:
Prior service costs	—		—		1		—		—		—
Regulatory asset	—		—		—		—		—		2
Net gain	(4)		(1)		(1)		—		—		(1)
Net periodic postretirement benefit cost (income)	$	(3)	$	(4)	$	—	$	—	$	—	$	1
Nine Months Ended September 30, 2023
Pension Plans
Service cost	$	207	$	48	$	51	$	8	$	5	$	18
Interest cost	469		109		143		21		6		32
Expected return on plan assets	(922)		(223)		(289)		(41)		(12)		(65)
Amortization:
Prior service costs	—		—		1		—		—		(2)
Regulatory asset	—		—		—		—		—		11
Net (gain) loss	24		7		10		1		—		(3)
Net periodic pension income	$	(222)	$	(59)	$	(84)	$	(11)	$	(1)	$	(9)
Postretirement Benefits
Service cost	$	11	$	3	$	3	$	—	$	—	$	1
Interest cost	53		13		19		2		—		6
Expected return on plan assets	(62)		(26)		(22)		(1)		—		(5)
Amortization:
Prior service costs	1		—		1		—		—		—
Regulatory asset	—		—		—		—		—		5
Net gain	(10)		(2)		(3)		—		—		(3)
Net periodic postretirement benefit cost (income)	$	(7)	$	(12)	$	(2)	$	1	$	—	$	4

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(UNAUDITED)

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2022
Pension Plans
Service cost	$	103	$	25	$	26	$	5	$	2	$	9
Interest cost	102		24		31		5		2		7
Expected return on plan assets	(316)		(77)		(99)		(15)		(4)		(22)
Amortization:
Prior service costs	—		—		—		—		—		(1)
Regulatory asset	—		—		—		—		—		3
Net loss	60		16		18		2		1		2
Net periodic pension cost (income)	$	(51)	$	(12)	$	(24)	$	(3)	$	1	$	(2)
Postretirement Benefits
Service cost	$	6	$	2	$	2	$	1	$	1	$	—
Interest cost	10		3		4		—		—		1
Expected return on plan assets	(20)		(9)		(8)		—		—		(2)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		2
Net (gain)/loss	1		—		—		—		—		(1)
Net periodic postretirement benefit cost (income)	$	(4)	$	(4)	$	(2)	$	1	$	1	$	—
Nine Months Ended September 30, 2022
Pension Plans
Service cost	$	309	$	74	$	78	$	13	$	7	$	26
Interest cost	306		72		92		14		5		21
Expected return on plan assets	(949)		(229)		(298)		(44)		(12)		(68)
Amortization:
Prior service costs	—		—		1		—		—		(2)
Regulatory asset	—		—		—		—		—		11
Net loss	180		47		55		9		2		5
Net periodic pension cost (income)	$	(154)	$	(36)	$	(72)	$	(8)	$	2	$	(7)
Postretirement Benefits
Service cost	$	17	$	5	$	5	$	1	$	1	$	1
Interest cost	31		8		11		1		—		4
Expected return on plan assets	(60)		(25)		(21)		(1)		—		(6)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		5
Net (gain) loss	1		—		1		—		—		(2)
Net periodic postretirement benefit cost (income)	$	(12)	$	(12)	$	(4)	$	1	$	1	$	2

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(UNAUDITED)

(I) FAIR VALUE MEASUREMENTS

At September 30, 2023, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

	Fair Value Measurements Using:
At September 30, 2023	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)	$	7	$	73	$	—	$	—	$	80
Investments in trusts:(b)
Domestic equity	692		196		—		—		888
Foreign equity	131		154		—		—		285
U.S. Treasury and government agency securities	—		337		—		—		337
Municipal bonds	—		42		—		—		42
Pooled funds – fixed income	—		6		—		—		6
Corporate bonds	—		368		—		—		368
Mortgage and asset backed securities	—		85		—		—		85
Private equity	—		—		—		169		169
Cash and cash equivalents	3		—		—		—		3
Other	33		3		—		8		44
Cash equivalents and restricted cash	919		11		—		—		930
Other investments	9		34		8		—		51
Total	$	1,794	$	1,309	$	8	$	177	$	3,288
Liabilities:
Energy-related derivatives(a)	$	34	$	217	$	—	$	—	$	251
Interest rate derivatives	—		351		—		—		351
Foreign currency derivatives	—		192		—		—		192
Contingent consideration	5		—		19		—		24
Other	—		13		—		—		13
Total	$	39	$	773	$	19	$	—	$	831

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(UNAUDITED)

	Fair Value Measurements Using:
At September 30, 2023	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	$	—	$	26	$	—	$	—	$	26
Nuclear decommissioning trusts:(b)
Domestic equity	404		188		—		—		592
Foreign equity	131		—		—		—		131
U.S. Treasury and government agency securities	—		20		—		—		20
Municipal bonds	—		1		—		—		1
Corporate bonds	—		215		—		—		215
Mortgage and asset backed securities	—		22		—		—		22
Private equity	—		—		—		169		169
Other	10		—		—		8		18
Cash equivalents and restricted cash	489		11		—		—		500
Other investments	—		34		—		—		34
Total	$	1,034	$	517	$	—	$	177	$	1,728
Liabilities:
Energy-related derivatives	$	—	$	75	$	—	$	—	$	75
Georgia Power
Assets:
Energy-related derivatives	$	—	$	14	$	—	$	—	$	14
Nuclear decommissioning trusts:(b)
Domestic equity	288		1		—		—		289
Foreign equity	—		153		—		—		153
U.S. Treasury and government agency securities	—		317		—		—		317
Municipal bonds	—		41		—		—		41
Corporate bonds	—		153		—		—		153
Mortgage and asset backed securities	—		63		—		—		63
Other	23		3		—		—		26
Total	$	311	$	745	$	—	$	—	$	1,056
Liabilities:
Energy-related derivatives	$	—	$	83	$	—	$	—	$	83

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(UNAUDITED)

	Fair Value Measurements Using:
At September 30, 2023	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	$	—	$	24	$	—	$	—	$	24
Cash equivalents	3		—		—		—		3
Total	$	3	$	24	$	—	$	—	$	27
Liabilities:
Energy-related derivatives	$	—	$	44	$	—	$	—	$	44
Southern Power
Assets:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5
Cash equivalents	23		—		—		—		23
Total	$	23	$	5	$	—	$	—	$	28
Liabilities:
Energy-related derivatives	$	—	$	6	$	—	$	—	$	6
Foreign currency derivatives	—		42		—		—		42
Contingent consideration	5		—		19		—		24
Other	—		13		—		—		13
Total	$	5	$	61	$	19	$	—	$	85
Southern Company Gas
Assets:
Energy-related derivatives(a)	$	7	$	4	$	—	$	—	$	11
Non-qualified deferred compensation trusts:
Domestic equity	—		7		—		—		7
Foreign equity	—		1		—		—		1
Pooled funds – fixed income	—		6		—		—		6
Cash equivalents	3		—		—		—		3
Cash equivalents	294		—		—		—		294
Total	$	304	$	18	$	—	$	—	$	322
Liabilities:
Energy-related derivatives(a)	$	34	$	9	$	—	$	—	$	43
Interest rate derivatives	—		99		—		—		99
Total	$	34	$	108	$	—	$	—	$	142

(a)Excludes cash collateral of $49 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.

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(UNAUDITED)

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds, including reinvested interest and dividends and excluding the funds' expenses, increased (decreased) by the amounts shown in the table below for the three and nine months ended September 30, 2023 and 2022. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.

	Three Months Ended				Nine Months Ended
Fair value increases (decreases)	September 30, 2023		September 30, 2022		September 30, 2023		September 30, 2022
	(in millions)
Southern Company	$	(4)	$	(106)	$	211	$	(486)
Alabama Power	(36)		(53)		54		(245)
Georgia Power	32		(53)		157		(241)

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.

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(UNAUDITED)

Southern Power has contingent payment obligations related to two of its acquisitions whereby it is primarily obligated to make generation-based payments to the seller, commencing at the commercial operation of each facility and continuing through 2026 and 2035, respectively. The obligations are primarily categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility's generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.

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

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

At September 30, 2023, the fair value measurements of private market 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 $177 million and unfunded commitments related to the private market investments totaled $72 million. Private market investments include high-quality private equity funds across several market sectors, funds that invest in real estate assets, and a private credit fund. Private market funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.

At September 30, 2023, 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	$	58.8	$	11.2	$	15.8	$	1.6	$	2.7	$	8.1
Fair value	50.8		9.4		13.4		1.3		2.4		6.5

(*)The carrying amount of Southern Company Gas' long-term debt includes fair value adjustments from 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.

(J) DERIVATIVES

The Registrants are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. 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

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(UNAUDITED)

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.

Energy-Related Derivatives

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

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

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.

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(UNAUDITED)

At September 30, 2023, 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(*)	422	2030	2028
Alabama Power	109	2026	—
Georgia Power	104	2026	—
Mississippi Power	80	2027	—
Southern Power	8	2030	2024
Southern Company Gas(*)	121	2027	2028

(*)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 135.5 million mmBtu long natural gas positions and 14.2 million mmBtu short natural gas positions at September 30, 2023, which is also included in Southern Company's total volume.

In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 14 million mmBtu for Southern Company, which includes 4 million mmBtu for Alabama Power, 5 million mmBtu for Georgia Power, 2 million mmBtu for Mississippi Power, and 3 million mmBtu for Southern Power.

For cash flow hedges of energy-related derivatives, the estimated pre-tax losses expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2024 are $30 million for Southern Company, $25 million for Southern Company Gas, and immaterial for Southern Power.

Interest Rate Derivatives

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

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At September 30, 2023, the following interest rate derivatives were outstanding:

	Notional Amount		Weighted Average Interest Rate Paid	Interest Rate Received	Hedge Maturity Date	Fair Value Gain (Loss) at September 30, 2023
	(in millions)					(in millions)
Fair Value Hedges of Existing Debt
Southern Company parent	$	400	1-month SOFR + 0.80%	1.75%	March 2028	$	(56)
Southern Company parent	1,000		1-month SOFR + 2.48%	3.70%	April 2030	(196)
Southern Company Gas	500		1-month SOFR + 0.49%	1.75%	January 2031	(99)
Southern Company	$	1,900				$	(351)

For cash flow hedges of interest rate derivatives, the estimated pre-tax losses expected to be reclassified from accumulated OCI to interest expense for the 12-month period ending September 30, 2024 are $19 million for Southern Company and immaterial for the traditional electric operating companies and Southern Company Gas. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2052 for Southern Company, Alabama Power, and Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.

Foreign Currency Derivatives

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

At September 30, 2023, the following foreign currency derivatives were outstanding:

	Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at September 30, 2023
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	564	3.78%	€	500	1.85%	June 2026	$	(42)
Fair Value Hedges of Existing Debt
Southern Company parent	1,476		3.39%	1,250		1.88%	September 2027	(150)
Southern Company	$	2,040		€	1,750			$	(192)

For cash flow hedges of foreign currency derivatives, the estimated pre-tax losses expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2024 are $10 million for Southern Power.

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Derivative Financial Statement Presentation and Amounts

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

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

	At September 30, 2023				At December 31, 2022
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Southern Company
Energy-related derivatives designated as hedging instruments for regulatory purposes
Assets from risk management activities/Liabilities from risk management activities	$	34	$	134	$	123	$	121
Other deferred charges and assets/Other deferred credits and liabilities	36		77		52		44
Total derivatives designated as hedging instruments for regulatory purposes	70		211		175		165
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities	—		28		3		27
Other deferred charges and assets/Other deferred credits and liabilities	4		2		6		4
Interest rate derivatives:
Assets from risk management activities/Liabilities from risk management activities	—		80		12		62
Other deferred charges and assets/Other deferred credits and liabilities	—		271		—		240
Foreign currency derivatives:
Assets from risk management activities/Liabilities from risk management activities	—		35		—		34
Other deferred charges and assets/Other deferred credits and liabilities	—		157		—		182
Total derivatives designated as hedging instruments in cash flow and fair value hedges	4		573		21		549
Energy-related derivatives not designated as hedging instruments
Assets from risk management activities/Liabilities from risk management activities	5		8		13		13
Other deferred charges and assets/Other deferred credits and liabilities	1		2		2		1
Total derivatives not designated as hedging instruments	6		10		15		14
Gross amounts recognized	80		794		211		728
Gross amounts offset(a)	(37)		(86)		(70)		(111)
Net amounts recognized in the Balance Sheets(b)	$	43	$	708	$	141	$	617

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	At September 30, 2023				At December 31, 2022
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Alabama Power(c)
Energy-related derivatives designated as hedging instruments for regulatory purposes
Other current assets/Other current liabilities	$	15	$	46	$	42	$	21
Other deferred charges and assets/Other deferred credits and liabilities	11		29		20		18
Total derivatives designated as hedging instruments for regulatory purposes	26		75		62		39
Gross amounts offset	(17)		(17)		(24)		(24)
Net amounts recognized in the Balance Sheets	$	9	$	58	$	38	$	15
Georgia Power
Energy-related derivatives designated as hedging instruments for regulatory purposes
Other current assets/Other current liabilities	$	4	$	57	$	36	$	43
Other deferred charges and assets/Other deferred credits and liabilities	10		26		6		18
Total derivatives designated as hedging instruments for regulatory purposes	14		83		42		61
Energy-related derivatives not designated as hedging instruments
Other current assets/Other current liabilities	—		—		—		1
Gross amounts recognized	14		83		42		62
Gross amounts offset	(11)		(11)		(21)		(21)
Net amounts recognized in the Balance Sheets	$	3	$	72	$	21	$	41
Mississippi Power(c)
Energy-related derivatives designated as hedging instruments for regulatory purposes
Other current assets/Other current liabilities	$	9	$	22	$	33	$	24
Other deferred charges and assets/Other deferred credits and liabilities	15		22		26		8
Total derivatives designated as hedging instruments for regulatory purposes	24		44		59		32
Gross amounts offset	(17)		(17)		(17)		(17)
Net amounts recognized in the Balance Sheets	$	7	$	27	$	42	$	15

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	At September 30, 2023				At December 31, 2022
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	$	—	$	5	$	—	$	12
Other deferred charges and assets/Other deferred credits and liabilities	4		—		5		—
Foreign currency derivatives:
Other current assets/Other current liabilities	—		11		—		11
Other deferred charges and assets/Other deferred credits and liabilities	—		31		—		36
Total derivatives designated as hedging instruments in cash flow and fair value hedges	4		47		5		59
Energy-related derivatives not designated as hedging instruments
Other current assets/Other current liabilities	1		1		2		—
Other deferred charges and assets/Other deferred credits and liabilities	—		—		1		—
Total derivatives not designated as hedging instruments	1		1		3		—
Gross amounts recognized	5		48		8		59
Gross amounts offset	(1)		(1)		—		—
Net amounts recognized in the Balance Sheets	$	4	$	47	$	8	$	59
Southern Company Gas
Energy-related derivatives designated as hedging instruments for regulatory purposes
Other current assets/Other current liabilities	$	6	$	9	$	12	$	33
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	—		23		3		15
Other deferred charges and assets/Other deferred credits and liabilities	—		2		1		4
Interest rate derivatives:
Other current assets/Other current liabilities	—		21		—		14
Other deferred charges and assets/Other deferred credits and liabilities	—		78		—		72
Total derivatives designated as hedging instruments in cash flow and fair value hedges	—		124		4		105
Energy-related derivatives not designated as hedging instruments
Other current assets/Other current liabilities	4		7		11		12
Other deferred charges and assets/Other deferred credits and liabilities	1		2		1		1
Total derivatives not designated as hedging instruments	5		9		12		13
Gross amounts recognized	11		142		28		151
Gross amounts offset(a)	9		(40)		—		(41)
Net amounts recognized in the Balance Sheets(b)	$	20	$	102	$	28	$	110

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(UNAUDITED)

(a)Gross amounts offset includes cash collateral held on deposit in broker margin accounts of $49 million and $41 million at September 30, 2023 and December 31, 2022, respectively.

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

(c)Energy-related derivatives not designated as hedging instruments were immaterial for Alabama Power and Mississippi Power at December 31, 2022. There were no such instruments for Alabama Power and Mississippi Power at September 30, 2023.

At September 30, 2023 and December 31, 2022, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Company Gas
	(in millions)
At September 30, 2023:
Energy-related derivatives:
Other regulatory assets, current	$	(113)	$	(39)	$	(54)	$	(16)	$	(4)
Other regulatory assets, deferred	(48)		(19)		(18)		(11)		—
Other regulatory liabilities, current	23		8		1		4		10
Other regulatory liabilities, deferred	6		1		2		3		—
Total energy-related derivative gains (losses)	$	(132)	$	(49)	$	(69)	$	(20)	$	6
At December 31, 2022:
Energy-related derivatives:
Other regulatory assets, current	$	(71)	$	(8)	$	(26)	$	(13)	$	(24)
Other regulatory assets, deferred	(23)		(7)		(14)		(2)		—
Other regulatory liabilities, current	72		29		19		22		2
Other regulatory liabilities, deferred	31		9		2		20		—
Total energy-related derivative gains (losses)	$	9	$	23	$	(19)	$	27	$	(22)

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(UNAUDITED)

For the three and nine months ended September 30, 2023 and 2022, the pre-tax effects of cash flow and fair value hedge accounting on accumulated OCI for the applicable Registrants were as follows:

Gain (Loss) Recognized in OCI on Derivatives	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Southern Company
Cash flow hedges:
Energy-related derivatives	$	(4)	$	11	$	(55)	$	51
Interest rate derivatives	(3)		6		(12)		36
Foreign currency derivatives	(15)		(35)		(6)		(137)
Fair value hedges(*):
Foreign currency derivatives	27		20		28		18
Total	$	5	$	2	$	(45)	$	(32)
Georgia Power
Cash flow hedges:
Interest rate derivatives	$	—	$	—	$	(3)	$	31
Southern Power
Cash flow hedges:
Energy-related derivatives	$	—	$	(11)	$	(14)	$	(4)
Foreign currency derivatives	(15)		(35)		(6)		(137)
Total	$	(15)	$	(46)	$	(20)	$	(141)
Southern Company Gas
Cash flow hedges:
Energy-related derivatives	$	(4)	$	22	$	(41)	$	55
Interest rate derivatives	(4)		5		—		—
Total	$	(8)	$	27	$	(41)	$	55

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

For the three and nine months ended September 30, 2022, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for Alabama Power and there were no such effects in 2023.

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For the three and nine months ended September 30, 2023 and 2022, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows:

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Southern Company
Total cost of natural gas	$	102	$	294	$	1,199	$	1,840
Gain (loss) on energy-related cash flow hedges(a)	(4)		9		(32)		28
Total other operations and maintenance	1,424		1,527		4,352		4,568
Gain (loss) on energy-related cash flow hedges(a)	(1)		—		(2)		—
Total depreciation and amortization	1,143		922		3,365		2,728
Gain (loss) on energy-related cash flow hedges(a)	(5)		(1)		(18)		5
Total interest expense, net of amounts capitalized	(620)		(511)		(1,812)		(1,461)
Gain (loss) on interest rate cash flow hedges(a)	(22)		(7)		(31)		(19)
Gain (loss) on foreign currency cash flow hedges(a)	(3)		(3)		(8)		(16)
Gain (loss) on interest rate fair value hedges(b)	(47)		(102)		(50)		(300)
Total other income (expense), net	141		132		428		414
Gain (loss) on foreign currency cash flow hedges(a)(c)	(14)		(32)		(4)		(129)
Gain (loss) on foreign currency fair value hedges	(7)		(59)		19		(180)
Amount excluded from effectiveness testing recognized in earnings	(27)		(21)		(28)		(17)
Southern Power
Total depreciation and amortization	$	130	$	133	$	380	$	384
Gain (loss) on energy-related cash flow hedges(a)	(5)		(1)		(18)		5
Total interest expense, net of amounts capitalized	(32)		(32)		(98)		(105)
Gain (loss) on foreign currency cash flow hedges(a)	(3)		(3)		(8)		(16)
Total other income (expense), net	4		3		8		5
Gain (loss) on foreign currency cash flow hedges(a)(c)	(14)		(32)		(4)		(129)
Southern Company Gas
Total cost of natural gas	$	102	$	294	$	1,199	$	1,840
Gain (loss) on energy-related cash flow hedges(a)	(4)		9		(32)		28
Total other operations and maintenance	264		252		879		824
Gain (loss) on energy-related cash flow hedges(a)	(1)		—		(2)		—
Total interest expense, net of amounts capitalized	(77)		(65)		(226)		(187)
Gain (loss) on interest rate cash flow hedges(a)	(18)		(2)		(18)		(3)
Gain (loss) on interest rate fair value hedges(b)	(11)		(30)		(14)		(87)

(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.

The pre-tax effects of cash flow and fair value hedge accounting on income for interest rate derivatives were immaterial for the traditional electric operating companies for all periods presented.

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(UNAUDITED)

At September 30, 2023 and December 31, 2022, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:

	Carrying Amount of the Hedged Item				Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items	At September 30, 2023		At December 31, 2022		At September 30, 2023		At December 31, 2022
	(in millions)				(in millions)
Southern Company
Long-term debt	$	(2,873)	$	(2,927)	$	328	$	282
Southern Company Gas
Long-term debt	$	(402)	$	(415)	$	95	$	81

For the three and nine months ended September 30, 2023 and 2022, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows:

		Gain (Loss)
		Three Months Ended September 30,				Nine Months Ended September 30,
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2023		2022		2023		2022
		(in millions)				(in millions)
Energy-related derivatives:	Natural gas revenues(*)	$	—	$	3	$	—	$	(10)
	Cost of natural gas	7		(2)		36		(7)
Total derivatives in non-designated hedging relationships		$	7	$	1	$	36	$	(17)

(*)Excludes $14 million of gains for the nine months ended September 30, 2023, and immaterial amounts for all other periods presented, recorded in natural gas revenues associated with weather derivatives.

For the three and nine months ended September 30, 2023 and 2022, the pre-tax effects of energy-related derivatives not designated as hedging instruments were immaterial for the other Registrants.

Contingent Features

The Registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. At September 30, 2023, the Registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

For Southern Company, the fair value of foreign currency derivative liabilities and interest rate derivative liabilities with contingent features, and the maximum potential collateral requirements arising from the credit-risk-related contingent features at a rating below BBB- and/or Baa3, was $78 million at September 30, 2023. For Southern Power, the fair value of foreign currency derivative liabilities with contingent features, and the maximum potential collateral requirements arising from the credit-risk-related contingent features at a rating below BBB- and/or Baa3, was $20 million at September 30, 2023. For the traditional electric operating companies and Southern Power, energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial at September 30, 2023. 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

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(UNAUDITED)

require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade.

Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions and they may be required to post collateral based on the value of the positions in these accounts and the associated margin requirements. At September 30, 2023, cash collateral posted in these accounts was $18 million for Southern Power and immaterial for Alabama Power. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At September 30, 2023, cash collateral held on deposit in broker margin accounts was $49 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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(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 Acquisitions

Southern Power's asset acquisitions during the nine months ended September 30, 2023 are detailed in the following table:

Project Facility	Resource	Seller	Approximate Nameplate Capacity (MW)	Location	Southern Power Ownership Percentage	Expected COD	PPA Contract Period
Millers Branch(*)	Solar	EDF Renewables, Inc.	200	Haskell County, TX	100%	Fourth quarter 2025	20 years
South Cheyenne	Solar	Hanwha Q Cells USA Corp.	150	Laramie County, WY	100%	First quarter 2024	20 years

(*)The project includes an option to expand capacity up to an additional 300 MWs.

The aggregate purchase price for the two projects was $193 million, which is primarily recorded within construction work in progress on the balance sheet.

Southern Company Gas

On September 22, 2023, Southern Company Gas completed the sale of its California natural gas storage facility, resulting in an immaterial loss.

(L) SEGMENT AND RELATED INFORMATION

Southern Company

The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The traditional electric operating companies are vertically integrated utilities providing electric service in three Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy and battery energy storage projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through its natural gas distribution utilities and is involved in several other complementary businesses including gas pipeline investments and gas marketing services.

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 $156 million and $406 million for the three and nine months ended September 30, 2023, respectively, and $336 million and $673 million for the three and nine months ended September 30, 2022, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies and Southern Power were immaterial for all periods presented. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing distributed energy and resilience solutions and deploying microgrids for commercial, industrial, governmental, and utility customers, as well as investments in telecommunications. All other inter-segment revenues are not material.

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(UNAUDITED)

Financial data for business segments and products and services for the three and nine months ended September 30, 2023 and 2022 was as follows:

	Electric Utilities
	Traditional Electric Operating Companies		Southern Power		Eliminations		Total		Southern Company Gas		All Other		Eliminations		Consolidated
	(in millions)
Three Months Ended September 30, 2023
Operating revenues	$	5,674	$	653	$	(160)	$	6,167	$	689	$	154	$	(30)	$	6,980
Segment net income (loss)(a)(b)(c)	1,419		100		—		1,519		82		(179)		—		1,422
Nine Months Ended September 30, 2023
Operating revenues	$	14,145	$	1,686	$	(417)	$	15,414	$	3,417	$	499	$	(122)	$	19,208
Segment net income (loss)(a)(b)(c)(d)	2,852		288		—		3,140		475		(490)		(4)		3,121
At September 30, 2023
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	144	$	—	$	5,161
Total assets	99,464		13,090		(568)		111,986		24,823		2,370		(858)		138,321
Three Months Ended September 30, 2022
Operating revenues	$	6,938	$	1,180	$	(691)	$	7,427	$	857	$	135	$	(41)	$	8,378
Segment net income (loss)(a)(b)	1,445		95		—		1,540		83		(152)		1		1,472
Nine Months Ended September 30, 2022
Operating revenues	$	16,716	$	2,618	$	(1,391)	$	17,943	$	3,998	$	418	$	(127)	$	22,232
Segment net income (loss)(a)(b)	3,256		265		—		3,521		516		(415)		(11)		3,611
At December 31, 2022
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	144	$	—	$	5,161
Total assets	95,861		13,081		(659)		108,283		24,621		2,665		(678)		134,891

(a)Attributable to Southern Company.

(b)For the traditional electric operating companies, includes pre-tax charges (credits) to income at Georgia Power for the estimated probable loss associated with the construction of Plant Vogtle Units 3 and 4 of $160 million ($120 million after tax) for the three and nine months ended September 30, 2023 and $(70) million ($(52) million after tax) and $(18) million ($(13) million after tax) for the three and nine months ended September 30, 2022, respectively. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.

(c)For Southern Power, includes an $18 million pre-tax loss recovery ($9 million after tax and partnership allocations) for the three and nine months ended September 30, 2023 related to an arbitration interim award and a $16 million pre-tax gain ($12 million after tax) on the sale of spare parts for the nine months ended September 30, 2023. See Note (C) under "General Litigation Matters – Southern Power" for additional information.

(d)For Southern Company Gas, includes a pre-tax charge of approximately $38 million ($28 million after tax) associated with the disallowance of certain capital expenditures at Nicor Gas. See Note (B) under "Southern Company Gas" for additional information.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

Products and Services

	Electric Utilities' Revenues
	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2023	$	5,139	$	727	$	301	$	6,167
Three Months Ended September 30, 2022	5,961		1,197		269		7,427
Nine Months Ended September 30, 2023	$	12,597	$	1,930	$	887	$	15,414
Nine Months Ended September 30, 2022	14,363		2,798		782		17,943

	Southern Company Gas' Revenues
	Gas Distribution Operations		Gas Marketing Services		Other		Total
	(in millions)
Three Months Ended September 30, 2023	$	617	$	56	$	16	$	689
Three Months Ended September 30, 2022	748		85		24		857
Nine Months Ended September 30, 2023	$	2,989	$	376	$	52	$	3,417
Nine Months Ended September 30, 2022	3,513		420		65		3,998

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)

(UNAUDITED)

Southern Company Gas

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

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

Gas pipeline investments consists of joint ventures in natural gas pipeline investments including a 50% interest in SNG 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. See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.

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 a natural gas storage facility in Texas through its sale in November 2022 and a natural gas storage facility in California through its sale in September 2023. See Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) under "Southern Company Gas" for additional information.

Business segment financial data for the three months ended September 30, 2023 and 2022 was as follows:

	Gas Distribution Operations		Gas Pipeline Investments		Gas Marketing Services		Total		All Other		Eliminations		Consolidated
	(in millions)
Three Months Ended September 30, 2023
Operating revenues	$	619	$	8	$	56	$	683	$	8	$	(2)	$	689
Segment net income (loss)	70		24		2		96		(14)		—		82
Nine Months Ended September 30, 2023
Operating revenues	$	3,002	$	24	$	376	$	3,402	$	30	$	(15)	$	3,417
Segment net income(*)	352		73		59		484		(9)		—		475
Total assets at September 30, 2023	22,625		1,542		1,519		25,686		9,795		(10,658)		24,823
Three Months Ended September 30, 2022
Operating revenues	$	751	$	8	$	85	$	844	$	16	$	(3)	$	857
Segment net income (loss)	59		24		(2)		81		2		—		83
Nine Months Ended September 30, 2022
Operating revenues	$	3,533	$	24	$	420	$	3,977	$	43	$	(22)	$	3,998
Segment net income	365		76		65		506		10		—		516
Total assets at December 31, 2022	22,040		1,577		1,616		25,233		8,943		(9,555)		24,621

(*)For gas distribution operations, includes a pre-tax charge of approximately $38 million ($28 million after tax) associated with the disallowance of certain capital expenditures at Nicor Gas. See Note (B) under "Southern Company Gas" 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	101
Results of Operations	106
Southern Company	106
Alabama Power	115
Georgia Power	121
Mississippi Power	127
Southern Power	132
Southern Company Gas	136
Future Earnings Potential	142
Accounting Policies	147
Financial Condition and Liquidity	148

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), Southern Power, and Southern Company Gas and owns other direct and indirect subsidiaries. The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. Southern Company's reportable segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Southern Company Gas' reportable segments are gas distribution operations, gas pipeline investments, and gas marketing services. See Note (L) to the Condensed Financial Statements herein for additional information on segment reporting. Alabama Power, Georgia Power, and Mississippi Power each operate with one reportable business segment, since substantially all of their business is providing electric service to customers. Southern Power also operates its business with one reportable business segment, the sale of electricity in the competitive wholesale market. For additional information on the Registrants' primary business activities, see BUSINESS – "The Southern Company System" in Item 1 of the Form 10-K.

The Registrants continue to focus on several key performance indicators. For the traditional electric operating companies and Southern Company Gas, these indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, and execution of major construction projects. For Southern Power, these indicators include, but are not limited to, the equivalent forced outage rate and contract availability to evaluate operating results and help ensure its ability to meet its contractual commitments to customers. In addition, Southern Company and the Subsidiary Registrants focus on earnings per share and net income, respectively, as a key performance indicator.

Recent Developments

Alabama Power

On March 24, 2023, Alabama Power filed Rate CNP New Plant with the Alabama PSC to recover costs associated with the acquisition of the Central Alabama Generating Station. The filing reflected an annual increase in retail revenues of $78 million effective with June 2023 billings. Through May 2023, Alabama Power recovered substantially all costs associated with the Central Alabama Generating Station through Rate RSE, offset by revenues from a power sales agreement. On May 24, 2023, the Central Alabama Generating Station was placed into retail service.

On June 14, 2023, the Alabama PSC issued an order approving modifications to Alabama Power's Renewable Generation Certificate. The modifications authorized Alabama Power to procure an additional 2,400 MWs of renewable capacity and energy by June 14, 2029 and to market the related energy and environmental attributes to customers and other third parties. The modifications also increased the size of allowable renewable projects from 80 MWs to 200 MWs and increased the annual approval limit from 160 MWs to 400 MWs.

On July 11, 2023, the Alabama PSC issued an order authorizing Alabama Power to expand the existing authority of its reliability reserve to include certain production-related expenses that are intended to maintain reliability in periods between scheduled generating unit outages.

On August 18, 2023, Alabama Power notified the Alabama PSC of its intent to use a portion of its $166 million reliability reserve balance during 2023. The ultimate outcome of this matter cannot be determined at this time.

On October 3, 2023, the Alabama PSC issued an order modifying its December 2022 order and authorizing Alabama Power to (i) flow back in 2023 approximately $24 million of certain federal excess accumulated deferred income taxes resulting from the Tax Cuts and Jobs Act of 2017 and (ii) make available any remaining balance of excess accumulated deferred income taxes at the end of 2023 for the benefit of customers in 2024 and/or 2025. The ultimate outcome of this matter cannot be determined at this time.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

On November 1, 2023, Alabama Power placed Plant Barry Unit 8 in service. At September 30, 2023, project expenditures associated with Plant Barry Unit 8 totaled approximately $583 million.

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

Georgia Power

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

Georgia Power placed Plant Vogtle Unit 3 in service on July 31, 2023 and continues construction on Plant Vogtle Unit 4 (each with electric generating capacity of approximately 1,100 MWs), in which it 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 July 2023 and March 2024, respectively, is $10.8 billion.

Hot functional testing for Unit 4 was completed on May 1, 2023. On July 20, 2023, Southern Nuclear announced that all Unit 4 ITAACs had been submitted to the NRC, and, on July 28, 2023, the NRC published its 103(g) finding that the accepted criteria in the combined license for Unit 4 had been met, which allowed nuclear fuel to be loaded and start-up testing to begin. Fuel load for Unit 4 was completed on August 19, 2023. On October 6, 2023, Georgia Power announced that during the start-up and pre-operational testing for Plant Vogtle Unit 4, Southern Nuclear identified a motor fault in one of four reactor coolant pumps (RCPs) and has started the process to replace this RCP with an on-site spare RCP from inventory. Considering this remediation and the remaining pre-operational testing, Unit 4 is projected to be placed in service during the first quarter 2024. The projected schedule for Unit 4 significantly depends on the pace and success of replacing the RCP, which involves removing and re-installing commodities around the RCP. In addition, any findings related to the root cause of the motor fault on the single Unit 4 RCP could require engineering changes or remediation related to the other seven Unit 3 and Unit 4 RCPs. Any further delays could result in a later in-service date and cost increases.

During the first nine months of 2023, established construction contingency totaling $43 million was assigned to the base capital cost forecast for costs primarily associated with the Unit 3 schedule extension and completion of start-up and pre-operational testing, including continued need of support resources for Unit 3 testing, as well as additional craft and support resources and subcontract work for Unit 4.

Georgia Power and the other Vogtle Owners did not agree on the starting dollar amount for the determination of cost increases subject to the cost-sharing and tender provisions of the Global Amendments (as defined in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction – Joint Owner Contracts" herein). The other Vogtle Owners notified Georgia Power that they believed the project capital cost forecast approved by the Vogtle Owners in February 2022 triggered the tender provisions.

In June 2022 and July 2022, OPC and Dalton, respectively, notified Georgia Power of their purported exercises of their tender options. Georgia Power did not accept these purported tender exercises. In June 2022, OPC and MEAG Power each filed a separate lawsuit against Georgia Power in the Superior Court of Fulton County, Georgia seeking a declaratory judgment that the starting dollar amount is $17.1 billion and that the cost-sharing and tender provisions had been triggered. In July 2022, Georgia Power filed its answers in the lawsuits filed by MEAG Power and OPC and included counterclaims seeking a declaratory judgment that the starting dollar amount is $18.38 billion and that costs related to force majeure events are excluded prior to calculating the cost-sharing and tender provisions and when calculating Georgia Power's related financial obligations. In September 2022, Dalton filed complaints in each of these lawsuits.

Also in September 2022, Georgia Power and MEAG Power reached an agreement to resolve their dispute regarding the proper interpretation of the cost-sharing and tender provisions of the Global Amendments. Under the terms of the agreement, among other items, (i) MEAG Power will not exercise its tender option and will retain its full ownership interest in Plant Vogtle Units 3 and 4; (ii) Georgia Power will reimburse a portion of MEAG Power's costs of construction for Plant Vogtle Units 3 and 4 as such costs are incurred and with no further adjustment for force majeure costs, which payments will total approximately $92 million based on the current project capital cost forecast; and (iii) Georgia Power will reimburse 20% of MEAG Power's costs of construction with respect to any

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

amounts over the current project capital cost forecast, with no further adjustment for force majeure costs. In October 2022, MEAG Power and Georgia Power filed a notice of settlement and voluntary dismissal of the pending litigation described above, including Georgia Power's counterclaim, and Dalton dismissed its related complaint.

On October 5, 2023 and October 17, 2023, Georgia Power reached agreements with OPC and Dalton, respectively, to resolve its respective dispute with each of OPC and Dalton regarding the proper interpretation of the cost-sharing and tender provisions of the joint ownership agreements relating to the Global Amendments. Under the terms of the agreements with OPC and Dalton, among other items, (i) each of OPC and Dalton retracted its exercise of the tender option and will retain its full ownership interest in Plant Vogtle Units 3 and 4, (ii) Georgia Power made payments immediately after execution of the agreements of $308 million and $17 million to OPC and Dalton, respectively, representing payment for a portion of each of OPC's and Dalton's costs of construction for Plant Vogtle Units 3 and 4 previously incurred, (iii) Georgia Power will pay a portion of each of OPC's and Dalton's further costs of construction for Plant Vogtle Units 3 and 4 as such costs are incurred and with no further adjustment for force majeure costs, which payments will be in an aggregate amount of approximately $105 million and $6 million for OPC and Dalton, respectively, based on the current project capital cost forecast, and (iv) Georgia Power will pay 66% of each of OPC's and Dalton's costs of construction with respect to any amounts above the current project capital cost forecast, with no further adjustment for force majeure costs. On October 23, 2023, OPC, Dalton, and Georgia Power filed a stipulation of dismissal with prejudice of their litigation described above, including Georgia Power's counterclaims.

Georgia Power recorded pre-tax charges to income through the fourth quarter 2022 of $407 million ($304 million after tax) associated with the cost-sharing provisions of the Global Amendments, including the settlement with MEAG Power. Based on the current project capital cost forecast and the settlements with OPC and Dalton described above, Georgia Power recorded a pre-tax charge to income of approximately $160 million ($120 million after tax) in the third quarter 2023. These charges are included in the total project capital cost forecast and will not be recovered from retail customers.

The ultimate impact of these matters on the construction schedule and project capital cost forecast and related cost recovery 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.

Plant Vogtle Unit 3 and Common Facilities Rate Proceeding

In compliance with a Georgia PSC order approved in November 2021, Georgia Power increased annual retail base rates by $318 million effective August 1, 2023 based on the in-service date of July 31, 2023 for Plant Vogtle Unit 3. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

Plant Vogtle Units 3 and 4 Prudency Proceeding

On August 30, 2023, as provided for in the December 2017 Georgia PSC approval of the seventeenth VCM report, Georgia Power filed with the Georgia PSC an application to adjust rates to include reasonable and prudent Plant Vogtle Units 3 and 4 costs (Application). The Application provides the necessary support to justify the reasonableness, prudence, and recovery of $8.826 billion in total construction and capital costs, $1.07 billion in associated retail rate base items, and the operating costs related to the full operation and output of Plant Vogtle Units 3 and 4.

Also on August 30, 2023, the staff of the Georgia PSC filed a stipulated agreement (Prudency Stipulation) among Georgia Power, the staff of the Georgia PSC, and certain intervenors. If the Prudency Stipulation is approved, Georgia Power will recover $7.562 billion in total construction and capital costs and associated retail rate base items of $1.02 billion, which includes AFUDC financing costs above $4.418 billion (the Georgia PSC-certified amount) up to $7.562 billion.

The Prudency Stipulation also provides for the recovery of projected operations and maintenance expenses, depreciation expense, nuclear decommissioning accruals, and property taxes, net of projected production tax credits.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

After considering construction and capital costs already in retail base rates of $2.1 billion and $362 million of associated retail rate base items (approved by the Georgia PSC in November 2021), and upon achieving commercial operation of Unit 4, Georgia Power will include in retail rate base the remaining $5.462 billion of construction and capital costs as well as $656 million of associated retail rate base items.

If the Prudency Stipulation is approved by the Georgia PSC, annual retail base revenues will increase approximately $729 million and the average retail base rates will be adjusted by approximately 5% effective the first day of the month after Unit 4 achieves commercial operation.

Georgia Power expects the Georgia PSC to render a final decision on these matters on December 19, 2023. The ultimate outcome of these matters cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Georgia Power – Plant Vogtle Units 3 and 4 Prudency Proceeding" herein for additional information.

Rate Plans

In accordance with the terms of the 2022 ARP, on October 2, 2023, Georgia Power filed tariff adjustments to become effective January 1, 2024 that would result in a net increase in rates of $191 million pending approval by the Georgia PSC. The ultimate outcome of this matter cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Georgia Power – Rate Plans" herein for additional information.

Fuel Cost Recovery

On May 16, 2023, the Georgia PSC approved a stipulation agreement between Georgia Power and the staff of the Georgia PSC to increase annual fuel billings by 54%, or approximately $1.1 billion, effective June 1, 2023. The increase reflects a three-year recovery period for $2.2 billion of Georgia Power's under recovered fuel balance at May 31, 2023. Changes in fuel rates have no significant effect on Southern Company's or Georgia Power's net income but do impact the related operating cash flows. See Note (B) to the Condensed Financial Statements under "Georgia Power – Fuel Cost Recovery" herein for additional information.

Integrated Resource Plan

On October 27, 2023, Georgia Power filed an updated IRP (2023 IRP Update) with the Georgia PSC, which sets forth a plan to support the recent increase in the state of Georgia's projected energy needs since the 2022 IRP. The schedule for the Georgia PSC to consider the 2023 IRP Update has not been determined. Georgia Power has requested that the Georgia PSC evaluate the 2023 IRP Update by the end of April 2024. The ultimate outcome of this matter cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Georgia Power – Integrated Resource Plans" herein for additional information.

Mississippi Power

On October 27, 2023, the FERC approved a settlement agreement filed by Mississippi Power and Cooperative Energy on July 31, 2023 related to Mississippi Power's July 2022 request for a $23 million increase in annual wholesale base revenues under the MRA tariff. The settlement agreement provides for a $16 million increase in annual wholesale base revenues, effective September 14, 2022, and a refund to customers of approximately $6 million primarily related to the difference between the approved rates and interim rates.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

Southern Power

On September 20, 2023, Southern Power acquired 100% of the membership interests in the 200-MW Millers Branch solar project located in Haskell County, Texas from EDF Renewables Development, Inc. and is continuing development and construction. The facility's output is contracted under a 20-year PPA and commercial operation is expected to occur in the fourth quarter 2025. The project includes an option to expand capacity up to an additional 300 MWs.

On September 22, 2023, Southern Power acquired 100% of the membership interests in the 150-MW South Cheyenne solar project located in Laramie County, Wyoming from Hanwha Q Cells USA Corp. and is continuing construction. The facility's output is contracted under a 20-year PPA and commercial operation is expected to occur in the first quarter 2024.

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

At September 30, 2023, Southern Power's average investment coverage ratio for its generating assets, including those owned with various partners, based on the ratio of investment under contract to total investment using the respective facilities' net book value (or expected in-service value for facilities under construction) as the investment amount was 97% through 2027 and 91% through 2032, with an average remaining contract duration of approximately 13 years.

Southern Company Gas

On July 14, 2023, Atlanta Gas Light filed its annual GRAM update with the Georgia PSC. The filing requests an annual base rate increase of $53 million based on the projected 12-month period beginning January 1, 2024. Resolution of the GRAM filing is expected by December 31, 2023, with new rates effective January 1, 2024.

On August 28, 2023, the Virginia Commission approved a stipulation agreement related to Virginia Natural Gas' August 2022 general base rate case filing. The approved agreement provides for a $48 million increase in annual base rate revenues, including the recovery of investments under the SAVE program, an ROE of 9.70%, and an equity ratio of 49.06%. Interim rates became effective January 1, 2023, subject to refund, based on Virginia Natural Gas' original requested increase of approximately $69 million. Refunds to customers related to the difference between the approved rates effective September 1, 2023 and the interim rates will be completed later in the fourth quarter 2023.

On June 15, 2023, the Illinois Commission concluded its review of the Qualifying Infrastructure Plant (QIP) capital investments by Nicor Gas for calendar year 2019 under the QIP Rider, also referred to as Investing in Illinois, program. The Illinois Commission disallowed $32 million of the $415 million of capital investments commissioned in 2019, together with the related return on investment. Nicor Gas recorded a pre-tax charge to income in the second quarter 2023 of $38 million ($28 million after tax) associated with the disallowance of capital investments. The disallowance is reflected on the statement of income as an $8 million reduction to revenues and a $30 million increase in operating expenses. On August 3, 2023, the Illinois Commission denied a rehearing request filed by Nicor Gas. On August 24, 2023, Nicor Gas filed a notice of appeal with the Illinois Appellate Court. Nicor Gas defends these investments in infrastructure as prudently incurred. The Illinois Commission has not yet conducted its review for calendar years 2020 through 2022 or the nine months ended September 30, 2023. Any further disallowance by the Illinois Commission could be material.

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

RESULTS OF OPERATIONS

Southern Company

Net Income

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(50)	(3.4)	$(490)	(13.6)

Consolidated net income attributable to Southern Company in the third quarter 2023 was $1.4 billion ($1.30 per share) compared to $1.5 billion ($1.36 per share) for the corresponding period in 2022. The decrease was primarily due to an increase of $172 million in after-tax charges related to the construction of Plant Vogtle Units 3 and 4, higher depreciation and amortization, and higher interest expense, partially offset by an increase in retail electric revenues associated with warmer weather and rates and pricing, lower non-fuel operations and maintenance costs, a decrease in income tax expense, and an increase in other revenues.

Consolidated net income attributable to Southern Company for year-to-date 2023 was $3.1 billion ($2.86 per share) compared to $3.6 billion ($3.38 per share) for the corresponding period in 2022. The decrease was primarily due to an increase of $133 million in after-tax charges related to the construction of Plant Vogtle Units 3 and 4, higher depreciation and amortization, higher interest expense, and a decrease in retail electric revenues associated with milder weather in the first and second quarters of 2023 compared to the corresponding periods in 2022, partially offset by lower non-fuel operations and maintenance costs, an increase in other revenues, an increase in natural gas revenues from rate increases and continued infrastructure replacement, and a decrease in income tax expense.

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" for additional information.

Retail Electric Revenues

In the third quarter 2023, retail electric revenues were $5.1 billion compared to $6.0 billion for the corresponding period in 2022. For year-to-date 2023, retail electric revenues were $12.6 billion compared to $14.4 billion for the corresponding period in 2022. Details of the changes in retail electric revenues were as follows:

	Third Quarter 2023 vs. Third Quarter 2022				Year-To-Date 2023 vs. Year-To-Date 2022
	(change in millions)		(% change)		(change in millions)		(% change)
Rates and pricing	$	76	1.3	%	$	63	0.4	%
Sales decline	(28)		(0.5)		(48)		(0.3)
Weather	132		2.2		(194)		(1.4)
Fuel and other cost recovery	(1,002)		(16.8)		(1,587)		(11.0)
Retail electric revenues	$	(822)	(13.8)	%	$	(1,766)	(12.3)	%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2023 when compared to the corresponding periods in 2022 primarily due to base tariff increases in accordance with Georgia Power's 2022 ARP and an increase in Rate CNP Compliance revenues at Alabama Power, partially offset by lower contributions from commercial and industrial customers with variable demand-driven pricing and a decrease in the revenues recognized under the NCCR tariff, both at Georgia Power. In addition, in the third quarter and year-to-date 2023, revenues associated with Rate CNP Depreciation increased $94 million and $234 million, respectively, and were fully offset by customer bill credits related to the flowback of excess accumulated deferred income taxes at Alabama Power. See Note 2 to the financial statements under "Alabama Power" and "Georgia Power" in Item 8 of the Form 10-K for additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2023 when compared to the corresponding periods in 2022. Weather-adjusted residential KWH sales decreased 1.8% and 0.4% in the third quarter and year-to-date 2023, respectively, when compared to the corresponding periods in 2022 primarily due to decreased customer usage, partially offset by customer growth. Weather-adjusted commercial KWH sales increased 1.3% in both the third quarter and year-to-date 2023 when compared to the corresponding periods in 2022 primarily due to increased customer usage and customer growth. Industrial KWH sales decreased 2.3% and 2.1% in the third quarter and year-to-date 2023, respectively, when compared to the corresponding periods in 2022 primarily due to a decrease in the chemicals and forest products sectors. Also contributing to the year-to-date 2023 industrial KWH sales decrease was a decrease in the textiles sector.

Fuel and other cost recovery revenues decreased $1.0 billion and $1.6 billion in the third quarter and year-to-date 2023, respectively, compared to the corresponding periods in 2022 primarily due to lower 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. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.

Wholesale Electric Revenues

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(470)	(39.3)	$(868)	(31.0)

In the third quarter 2023, wholesale electric revenues were $0.7 billion compared to $1.2 billion for the corresponding period in 2022. The decrease was primarily due to a decrease of $452 million in energy revenues as a result of fuel and purchased power price decreases when compared to the corresponding period in 2022 and a net decrease in the volume of KWHs sold primarily associated with natural gas PPAs at Southern Power. In addition, a decrease in capacity revenues of $18 million primarily resulted from power sales agreements that ended in May 2023 at Alabama Power, partially offset by an increase related to new capacity contracts at Georgia Power.

For year-to-date 2023, wholesale electric revenues were $1.9 billion compared to $2.8 billion for the corresponding period in 2022. The decrease was primarily due to a decrease of $892 million in energy revenues as a result of fuel and purchased power price decreases when compared to the corresponding period in 2022 and a net decrease in the volume of KWHs sold primarily associated with natural gas PPAs at Southern Power. The decrease in energy revenues was partially offset by an increase in capacity revenues of $24 million primarily resulting from a net increase in capacity sales from natural gas PPAs at Southern Power and an increase related to new capacity contracts at Georgia Power.

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

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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.

Other Electric Revenues

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$18	9.7	$48	8.7

In the third quarter 2023, other electric revenues were $203 million compared to $185 million for the corresponding period in 2022. The increase was primarily due to increases of $10 million resulting from receipts of liquidated damages associated with generation facility production guarantees and an arbitration interim award at Southern Power, $10 million in retail solar program fees at Georgia Power, and $9 million in transmission revenues primarily associated with open access transmission tariff sales, partially offset by a decrease of $11 million in cogeneration steam revenue primarily associated with lower natural gas prices at Alabama Power.

For year-to-date 2023, other electric revenues were $602 million compared to $554 million for the corresponding period in 2022. The increase was primarily due to increases of $19 million resulting from receipts of liquidated damages associated with generation facility production guarantees and an arbitration interim award at Southern Power, $18 million in transmission revenues primarily associated with open access transmission tariff sales, $18 million in realized gains associated with price stability products for retail customers on variable demand-driven pricing tariffs at Georgia Power, and $18 million in outdoor lighting sales at Georgia Power, partially offset by a decrease of $23 million in cogeneration steam revenue primarily associated with lower natural gas prices at Alabama Power.

See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information.

Natural Gas Revenues

In the third quarter 2023, natural gas revenues were $0.7 billion compared to $0.9 billion for the corresponding period in 2022. For year-to-date 2023, natural gas revenues were $3.4 billion compared to $4.0 billion for the corresponding period in 2022. Details of the changes in natural gas revenues were as follows:

	Third Quarter 2023 vs. Third Quarter 2022				Year-To-Date 2023 vs. Year-To-Date 2022
	(change in millions)		(% change)		(change in millions)		(% change)
Infrastructure replacement programs and rate changes	$	9	1.1	%	$	97	2.4	%
Gas costs and other cost recovery	(181)		(21.1)		(645)		(16.1)
Gas marketing services	(22)		(2.6)		(44)		(1.1)
Other	26		3.0		11		0.3
Natural gas revenues	$	(168)	(19.6)	%	$	(581)	(14.5)	%

Revenues from infrastructure replacement programs and rate changes at the natural gas distribution utilities increased in the third quarter and year-to-date 2023 compared to the corresponding periods in 2022 primarily due to rate increases at the natural gas distribution utilities and continued investment in infrastructure replacement. The year-to-date 2023 increase was partially offset by a regulatory disallowance at Nicor Gas. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" herein for additional information.

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Revenues from gas costs and other cost recovery decreased in the third quarter and year-to-date 2023 compared to the corresponding periods in 2022 primarily due to lower natural gas cost recovery associated with lower natural gas prices, the timing of natural gas purchases, and the recovery of those costs from 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.

Revenues from gas marketing services decreased in the third quarter and year-to-date 2023 compared to the corresponding periods in 2022 primarily due to lower natural gas prices and lower variable price spreads.

Other Revenues

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$44	24.7	$143	27.6

In the third quarter 2023, other revenues were $222 million compared to $178 million for the corresponding period in 2022. For year-to-date 2023, other revenues were $662 million compared to $519 million for the corresponding period in 2022. The increases in the third quarter and year-to-date 2023 were primarily due to increases of $9 million and $41 million, respectively, in power delivery construction and maintenance projects at Georgia Power, $12 million and $40 million, respectively, related to distributed infrastructure projects at PowerSecure, $9 million and $26 million, respectively, primarily related to sales associated with commercial customers at Southern Linc, $4 million and $20 million, respectively, in unregulated sales of products and services at Alabama Power, and $11 million and $16 million, respectively, associated with energy conservation projects at Georgia Power.

Fuel and Purchased Power Expenses

	Third Quarter 2023 vs. Third Quarter 2022			Year-To-Date 2023 vs. Year-To-Date 2022
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	(1,056)	(43.6)	$	(1,873)	(35.7)
Purchased power	(438)		(67.9)	(605)		(47.1)
Total fuel and purchased power expenses	$	(1,494)		$	(2,478)

In the third quarter 2023, total fuel and purchased power expenses were $1.6 billion compared to $3.1 billion for the corresponding period in 2022. The decrease was due to a $1.2 billion decrease in the average cost of fuel and purchased power and a $262 million net decrease in the volume of KWHs generated and purchased.

For year-to-date 2023, total fuel and purchased power expenses were $4.1 billion compared to $6.5 billion for the corresponding period in 2022. The decrease was due to a $2.1 billion decrease in the average cost of fuel and purchased power and a $349 million net decrease in the volume of KWHs generated and purchased.

Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See 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:

	Third Quarter 2023	Third Quarter 2022	Year-To-Date 2023	Year-To-Date 2022
Total generation (in billions of KWHs)(a)(b)	53	50	141	141
Total purchased power (in billions of KWHs)	5	9	14	20
Sources of generation (percent)(a) —
Gas	54	54	54	50
Coal	21	21	18	22
Nuclear(b)	16	16	17	16
Hydro	2	2	3	4
Wind, Solar, and Other	7	7	8	8
Cost of fuel, generated (in cents per net KWH)—
Gas(a)	2.80	6.75	2.78	5.42
Coal	4.52	4.12	4.40	3.58
Nuclear(b)	0.79	0.71	0.74	0.72
Average cost of fuel, generated (in cents per net KWH)(a)(b)	2.84	5.05	2.71	4.07
Average cost of purchased power (in cents per net KWH)(c)	4.80	8.94	5.08	7.84

(a)Excludes Central Alabama Generating Station KWHs and associated cost of fuel through July 12, 2022 as its fuel was previously provided by the purchaser under a power sales agreement. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.

(b)Excludes KWHs generated from test period energy at Plant Vogtle Unit 3 prior to its in-service date. The related fuel costs are charged to CWIP in accordance with FERC guidance. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

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

Fuel

In the third quarter 2023, fuel expense was $1.4 billion compared to $2.4 billion for the corresponding period in 2022. The decrease was primarily due to a 58.5% decrease in the average cost of natural gas per KWH generated, partially offset by a 10.0% increase in the volume of KWHs generated by nuclear, a 9.7% increase in the average cost of coal per KWH generated, a 6.4% increase in the volume of KWHs generated by coal, and a 6.0% increase in the volume of KWHs generated by natural gas.

For year-to-date 2023, fuel expense was $3.4 billion compared to $5.2 billion for the corresponding period in 2022. The decrease was primarily due to a 48.7% decrease in the average cost of natural gas per KWH generated and a 20.4% decrease in the volume of KWHs generated by coal, partially offset by a 22.9% increase in the average cost of coal per KWH generated, an 11.0% decrease in the volume of KWHs generated by hydro, and a 9.0% increase in the volume of KWHs generated by natural gas.

Purchased Power

In the third quarter 2023, purchased power expense was $207 million compared to $645 million for the corresponding period in 2022. For year-to-date 2023, purchased power expense was $0.7 billion compared to $1.3 billion for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were primarily due to decreases of 46.3% and 35.2%, respectively, in the average cost per KWH purchased primarily due to a decrease in natural gas prices and decreases of 48.1% and 29.0%, respectively, in the volume of KWHs purchased.

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

Cost of Natural Gas

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(192)	(65.3)	$(641)	(34.8)

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 76% and 84% of the total cost of natural gas in the third quarter and year-to-date 2023, respectively.

In the third quarter 2023, cost of natural gas was $102 million compared to $294 million for the corresponding period in 2022. For year-to-date 2023, cost of natural gas was $1.2 billion compared to $1.8 billion for the corresponding period in 2022. The decreases reflect lower gas cost recovery as a result of decreases of 69% and 60% in natural gas prices in the third quarter and year-to-date 2023, respectively, compared to the corresponding periods in 2022.

Cost of Other Sales

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$34	37.0	$106	38.5

In the third quarter 2023, cost of other sales was $126 million compared to $92 million for the corresponding period in 2022. The increase was primarily due to increases of $12 million from unregulated power delivery construction and maintenance projects at Georgia Power, $7 million at Southern Linc primarily related to sales associated with commercial customers, $6 million related to distributed infrastructure projects at PowerSecure, and $5 million related to energy service contracts at Southern Company Gas.

For year-to-date 2023, cost of other sales was $381 million compared to $275 million for the corresponding period in 2022. The increase was primarily due to increases of $35 million from unregulated power delivery construction and maintenance projects at Georgia Power, $23 million at Southern Linc primarily related to sales associated with commercial customers, $21 million related to distributed infrastructure projects at PowerSecure, $20 million related to energy service contracts at Southern Company Gas, and $10 million in expenses related to unregulated products and services at Alabama Power.

Other Operations and Maintenance Expenses

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(103)	(6.7)	$(216)	(4.7)

In the third quarter 2023, other operations and maintenance expenses were $1.4 billion compared to $1.5 billion for the corresponding period in 2022. The decrease was primarily due to decreases of $88 million in transmission and distribution expenses primarily related to line maintenance, $45 million in storm damage recovery as authorized in Georgia Power's 2022 ARP, $22 million in technology infrastructure and application production costs, and $14 million in generation non-outage maintenance expenses and planned outages, partially offset by a $23 million

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AND RESULTS OF OPERATIONS (Continued)

increase in generation environmental projects primarily at Georgia Power and a $14 million gain recorded in the third quarter 2022 as a result of the early termination of the transition services agreement related to the 2019 sale of Gulf Power.

For year-to-date 2023, other operations and maintenance expenses were $4.4 billion compared to $4.6 billion for the corresponding period in 2022. The decrease was primarily due to decreases of $147 million in transmission and distribution expenses primarily related to line maintenance, $136 million in storm damage recovery as authorized in Georgia Power's 2022 ARP, $91 million in generation non-outage maintenance expenses and planned outages, and $32 million in expenses passed through to customers primarily related to bad debt and energy efficiency programs at Southern Company Gas, partially offset by a $47 million increase in technology infrastructure and application production costs, a $43 million increase in generation environmental projects primarily at Georgia Power, $30 million related to a regulatory disallowance at Nicor Gas, a $25 million decrease in nuclear property insurance refunds at Georgia Power and Alabama Power, a $16 million increase in employee compensation and benefits, and a $14 million gain recorded in the third quarter 2022 as a result of the early termination of the transition services agreement related to the 2019 sale of Gulf Power.

See Note (B) to the Condensed Financial Statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" herein for additional information on the regulatory disallowance at Nicor Gas and Note 2 to the financial statements under "Georgia Power – Storm Damage Recovery" in Item 8 of the Form 10-K for additional information.

Depreciation and Amortization

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$221	24.0	$637	23.4

In the third quarter 2023, depreciation and amortization was $1.1 billion compared to $0.9 billion for the corresponding period in 2022. For year-to-date 2023, depreciation and amortization was $3.4 billion compared to $2.7 billion for the corresponding period in 2022. The increases in the third quarter and year-to-date 2023 were primarily due to increases of $181 million and $544 million, respectively, resulting from higher depreciation rates at Alabama Power and Georgia Power and increases of $28 million and $74 million, respectively, from additional plant in service. See Notes 2 and 5 to the financial statements under "Alabama Power" and "Depreciation and Amortization," respectively, in Item 8 of the Form 10-K for additional information.

Taxes Other Than Income Taxes

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(11)	(3.1)	$3	0.3

In the third quarter 2023, taxes other than income taxes were $341 million compared to $352 million for the corresponding period in 2022. The decrease was primarily due to decreases of $15 million in municipal franchise fees resulting from lower retail revenues at Georgia Power, partially offset by an increase of $4 million in property taxes primarily at Georgia Power resulting from an increase in the assessed value of property.

For year-to-date 2023, taxes other than income taxes were $1.08 billion compared to $1.07 billion for the corresponding period in 2022. The increase was primarily due to increases of $26 million in property taxes primarily at Georgia Power resulting from an increase in the assessed value of property, $18 million in utility license taxes at Alabama Power, and $8 million in payroll taxes primarily at Southern Company Gas, largely offset by decreases of $33 million in municipal franchise fees resulting from lower retail revenues at Georgia Power and $15 million in revenue tax expenses at Southern Company Gas.

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Estimated Loss on Plant Vogtle Units 3 and 4

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$230	N/M	$178	N/M

Georgia Power recorded pre-tax charges (credits) to income for the estimated probable loss on Plant Vogtle Units 3 and 4 totaling $160 million and $(70) million in the third quarter 2023 and 2022, respectively, and $160 million and $(18) million for year-to-date 2023 and 2022, respectively. The charges (credits) reflected revisions to the total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.

Allowance for Equity Funds Used During Construction

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$7	11.9	$37	22.7

In the third quarter 2023, allowance for equity funds used during construction was $66 million compared to $59 million for the corresponding period in 2022. For year-to-date 2023, allowance for equity funds used during construction was $200 million compared to $163 million for the corresponding period in 2022. The increases were primarily associated with an increase in capital expenditures related to Plant Barry Unit 8 construction, as well as an increase in capital expenditures related to hydro production, both at Alabama Power. Also contributing to the increase for year-to-date 2023 was an increase in capital expenditures subject to AFUDC at Georgia Power. 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 – Certificates of Convenience and Necessity" for additional information.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$109	21.3	$351	24.0

In the third quarter 2023, interest expense, net of amounts capitalized was $620 million compared to $511 million for the corresponding period in 2022. For year-to-date 2023, interest expense, net of amounts capitalized was $1.8 billion compared to $1.5 billion for the corresponding period in 2022. The increases in the third quarter and year-to-date 2023 primarily reflect approximately $63 million and $222 million, respectively, related to higher interest rates and $48 million and $134 million, respectively, related to higher average outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.

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Other Income (Expense), Net

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$9	6.8	$14	3.4

For year-to-date 2023, other income (expense), net was $428 million compared to $414 million for the corresponding period in 2022. The increase was primarily due to a $29 million increase in interest income, a $13 million decrease in non-operating benefit-related expenses at Alabama Power, an $8 million gain on investments at Southern Holdings, and a $6 million decrease in non-operating marketing expenses at Georgia Power, partially offset by decreases of $30 million in non-service cost-related retirement benefits income and $13 million in customer charges related to contributions in aid of construction at Georgia Power. See Note (H) to the Condensed Financial Statements herein for additional information.

Income Taxes

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(117)	(28.3)	$(399)	(44.8)

In the third quarter 2023, income taxes were $297 million compared to $414 million for the corresponding period in 2022. For year-to-date 2023, income taxes were $492 million compared to $891 million for the corresponding period in 2022. The decreases were primarily due to lower pre-tax earnings, an increase in the flowback of certain excess deferred income taxes at Alabama Power, and a decrease in a valuation allowance on certain state tax credit carryforwards at Georgia Power in 2023, partially offset by a decrease in the flowback of certain excess deferred income taxes at Georgia Power that ended in 2022. Also contributing to the year-to-date 2023 decrease was an adjustment in the second quarter 2022 related to a prior year state tax credit carryforward at Georgia Power. See Note (G) to the Condensed Financial Statements herein for additional information.

Net Income (Loss) Attributable to Noncontrolling Interests

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(2)	(16.7)	$(13)	(23.6)

Substantially all noncontrolling interests relate to renewable projects at Southern Power. In the third quarter 2023, net income attributable to noncontrolling interests was $10 million compared to $12 million for the corresponding period in 2022. The decrease was primarily due to $7 million in higher HLBV loss allocations to Southern Power's wind tax equity partners, largely offset by an allocation of $6 million to Southern Power's equity partners related to an arbitration interim award.

For year-to-date 2023, net loss attributable to noncontrolling interests was $68 million compared to $55 million for the corresponding period in 2022. The increase was primarily due to $16 million in higher HLBV loss allocations to Southern Power's wind tax equity partners and $12 million in lower income allocations to Southern Power's equity partners, partially offset by $15 million in lower loss allocations to Southern Power's battery energy storage partners.

See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information.

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Alabama Power

Net Income

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$40	7.6	$(124)	(9.9)

Alabama Power's net income after dividends on preferred stock in the third quarter 2023 was $565 million compared to $525 million for the corresponding period in 2022. The increase was primarily due to a decrease in income tax expense and an increase in retail revenues associated with Rate CNP Compliance and warmer weather in Alabama Power's service territory in the third quarter 2023 compared to the corresponding period in 2022. These increases to income were partially offset by an increase in depreciation and amortization associated with a change in depreciation rates effective January 2023.

Alabama Power's net income after dividends on preferred stock for year-to-date 2023 was $1.13 billion compared to $1.26 billion for the corresponding period in 2022. The decrease was primarily due to an increase in depreciation rates effective January 2023, a decrease in retail revenues associated with milder weather in Alabama Power's service territory in the first and second quarters of 2023 compared to the corresponding periods in 2022, and an increase in capacity-related expenses. These decreases to income were partially offset by a decrease in income tax expense and an increase in Rate CNP Compliance revenues.

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

Retail Revenues

In the third quarter 2023, retail revenues were $1.86 billion compared to $2.01 billion for the corresponding period in 2022. For year-to-date 2023, retail revenues were $4.71 billion compared to $5.02 billion for the corresponding period in 2022. Details of the changes in retail revenues were as follows:

	Third Quarter 2023 vs. Third Quarter 2022				Year-To-Date 2023 vs.  Year-To-Date 2022
	(change in millions)		(% change)		(change in millions)		(% change)
Rates and pricing	$	62	3.1	%	$	178	3.5	%
Sales decline	(2)		(0.1)		(36)		(0.7)
Weather	35		1.7		(84)		(1.7)
Fuel and other cost recovery	(243)		(12.1)		(365)		(7.3)
Retail revenues	$	(148)	(7.4)	%	$	(307)	(6.2)	%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2023 when compared to the corresponding periods in 2022 primarily due to an increase in Rate CNP Compliance revenues. In addition, in the third quarter and year-to-date 2023, revenues associated with Rate CNP Depreciation increased $94 million and $234 million, respectively, and were fully offset by customer bill credits related to the flowback of excess accumulated deferred income taxes. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.

Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2023 when compared to the corresponding periods in 2022. Weather-adjusted residential KWH sales decreased 0.8% in the third quarter 2023 compared to the corresponding period in 2022 primarily due to decreased customer usage and remained flat for year-to-date 2023 when compared to the corresponding period in 2022. Weather-adjusted commercial KWH sales increased 1.1% and 0.8% in the third quarter and year-to-date 2023, respectively, when compared to the corresponding periods in 2022 primarily due to increases in customer usage and customer growth. Industrial KWH sales decreased 4.8% and 3.9% in the third quarter and year-to-date 2023, respectively, primarily due to decreases in

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the chemicals and forest products sectors. Also contributing to the industrial KWH sales decrease in the third quarter 2023 was a decrease in the primary metals sector.

Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2023 when compared to the corresponding periods in 2022 primarily as a result of lower fuel and purchased power costs.

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

Wholesale Revenues – Non-Affiliates

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(144)	(57.6)	$(164)	(31.4)

In the third quarter 2023, wholesale revenues from sales to non-affiliates were $106 million compared to $250 million for the corresponding period in 2022. The decrease was primarily due to a 47.0% decrease in the volume of KWHs sold as a result of power sales agreements that ended in May 2023 and a 19.8% decrease in the price of energy primarily as a result of lower natural gas prices in the third quarter 2023 compared to the corresponding period in 2022.

For year-to-date 2023, wholesale revenues from sales to non-affiliates were $358 million compared to $522 million for the corresponding period in 2022. The decrease was primarily due to a 20.4% decrease in the price of energy primarily as a result of lower natural gas prices and a 13.8% decrease in the volume of KWHs sold due to lower customer demand as a result of milder weather in 2023 compared to the corresponding period in 2022.

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

Wholesale Revenues – Affiliates

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(56)	(80.0)	$(127)	(74.7)

In the third quarter 2023, wholesale revenues from sales to affiliates were $14 million compared to $70 million for the corresponding period in 2022. For year-to-date 2023, wholesale revenues from sales to affiliates were $43 million compared to $170 million for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were primarily due to decreases of 60.6% and 45.6%, respectively, in the price of energy due to lower natural gas prices and 51.2% and 53.5%, respectively, in the volume of KWH sales due to lower customer demand as a result of milder weather in 2023 compared to the corresponding periods in 2022.

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. Energy revenues related to these transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.

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Other Revenues

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(13)	(11.2)	$(5)	(1.6)

In the third quarter 2023, other revenues were $103 million compared to $116 million for the corresponding period in 2022. For year-to-date 2023, other revenues were $311 million compared to $316 million for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were primarily due to decreases of $11 million and $23 million, respectively, in cogeneration steam revenue primarily associated with lower natural gas prices. The decrease for year-to-date 2023 was largely offset by a $20 million increase in unregulated sales of products and services.

Fuel and Purchased Power Expenses

	Third Quarter 2023 vs. Third Quarter 2022			Year-To-Date 2023 vs. Year-To-Date 2022
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	(264)	(39.6)	$	(386)	(27.6)
Purchased power – non-affiliates	(143)		(77.3)	(150)		(43.2)
Purchased power – affiliates	(33)		(29.2)	(67)		(25.8)
Total fuel and purchased power expenses	$	(440)		$	(603)

In the third quarter 2023, total fuel and purchased power expenses were $524 million compared to $964 million for the corresponding period in 2022. For year-to-date 2023, total fuel and purchased power expenses were $1.40 billion compared to $2.01 billion for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were due to decreases of $301 million and $540 million, respectively, in the average cost of fuel and purchased power and decreases of $139 million and $63 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 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:

	Third Quarter 2023	Third Quarter 2022	Year-To-Date 2023	Year-To-Date 2022
Total generation (in billions of KWHs)(a)	15	16	43	45
Total purchased power (in billions of KWHs)	3	4	8	9
Sources of generation (percent)(a) —
Coal	40	47	35	45
Gas	31	28	30	23
Nuclear	26	22	27	24
Hydro	3	3	8	8
Cost of fuel, generated (in cents per net KWH) —
Coal	3.57	3.89	3.48	3.40
Gas(a)	3.07	6.55	3.05	5.20
Nuclear	0.68	0.67	0.68	0.67
Average cost of fuel, generated (in cents per net KWH)(a)	2.64	3.91	2.51	3.13
Average cost of purchased power (in cents per net KWH)(b)	4.57	8.55	4.97	8.33

(a)Excludes Central Alabama Generating Station KWHs and associated cost of fuel through July 12, 2022 as its fuel was previously provided by the purchaser under a power sales agreement. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.

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

Fuel

In the third quarter 2023, fuel expense was $402 million compared to $666 million for the corresponding period in 2022. The decrease was primarily due to a 53.1% decrease in the average cost of natural gas per KWH generated, which excludes tolling agreements, and an 18.9% decrease in the volume of KWHs generated by coal.

For year-to-date 2023, fuel expense was $1.01 billion compared to $1.40 billion for the corresponding period in 2022. The decrease was primarily due to a 41.3% decrease in the average cost of natural gas per KWH generated, which excludes tolling agreements, and a 25.3% decrease in the volume of KWHs generated by coal, partially offset by a 23.4% increase in the volume of KWHs generated by natural gas and a 10.6% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall for year-to-date 2023 compared to the corresponding period in 2022.

Purchased Power – Non-Affiliates

In the third quarter 2023, purchased power expense from non-affiliates was $42 million compared to $185 million for the corresponding period in 2022. For year-to-date 2023, purchased power expense from non-affiliates was $197 million compared to $347 million for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were primarily due to decreases of 41.0% and 37.6%, respectively, in the average cost per KWH purchased due to lower purchase prices as a result of lower natural gas prices and decreases of 64.2% and 21.8%, respectively, in the volume of KWHs purchased due to a new PPA that began in July 2022 and ended in May 2023.

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

Purchased Power – Affiliates

In the third quarter 2023, purchased power expense from affiliates was $80 million compared to $113 million for the corresponding period in 2022. For year-to-date 2023, purchased power expense from affiliates was $193 million

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compared to $260 million for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were primarily due to decreases of 65.8% and 51.3%, respectively, in the average cost per KWH purchased due to lower purchase prices as a result of lower natural gas prices, partially offset by increases of 107.6% and 52.6%, respectively, in the volume of KWHs purchased due to the availability of lower cost gas generation in the Southern Company system.

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

Other Operations and Maintenance Expenses

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(7)	(1.7)	$5	0.4

In the third quarter 2023, other operations and maintenance expenses were $411 million compared to $418 million for the corresponding period in 2022. The decrease was primarily due to decreases of $15 million in transmission and distribution expenses related to line maintenance, $9 million in technology infrastructure and application production costs, and $9 million in certain employee compensation and benefit expenses. The decreases were largely offset by an increase of $26 million in planned outages and generation non-outage maintenance expenses.

For year-to-date 2023, other operations and maintenance expenses were $1.28 billion compared to $1.27 billion for the corresponding period in 2022. The increase was primarily due to a $14 million decrease in nuclear property insurance refunds and increases of $19 million in expenses related to unregulated products and services, $9 million in technology infrastructure and application production costs, and $9 million in customer accounts expenses primarily associated with bad debt expense. The increases were largely offset by decreases of $21 million in generation expenses primarily associated with planned outages and generation non-outage maintenance expenses, $15 million in certain employee compensation and benefit expenses, and $10 million in transmission and distribution related to line maintenance.

Depreciation and Amortization

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$131	59.5	$393	60.3

In the third quarter 2023, depreciation and amortization was $351 million compared to $220 million for the corresponding period in 2022. For year-to-date 2023, depreciation and amortization was $1.05 billion compared to $652 million for the corresponding period in 2022. The increases were primarily due to an increase in depreciation rates effective in 2023. See Notes 2 and 5 to the financial statements under "Alabama Power" and "Depreciation and Amortization," respectively, in Item 8 of the Form 10-K for additional information.

Taxes Other Than Income Taxes

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$4	3.8	$24	7.8

In the third quarter 2023, taxes other than income taxes were $110 million compared to $106 million for the corresponding period in 2022. For year-to-date 2023, taxes other than income taxes were $333 million compared to $309 million for the corresponding period in 2022. The increases were primarily due to an increase in utility license taxes.

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Allowance for Equity Funds Used During Construction

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$5	27.8	$14	27.5

In the third quarter 2023, allowance for equity funds used during construction was $23 million compared to $18 million for the corresponding period in 2022. For year-to-date 2023, allowance for equity funds used during construction was $65 million compared to $51 million for the corresponding period in 2022. The increases were primarily due to an increase in capital expenditures related to Plant Barry Unit 8 construction, as well as an increase in capital expenditures related to hydro production. See Note (B) to the Condensed Financial Statements under "Alabama Power – Certificates of Convenience and Necessity" herein for additional information.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$6	6.1	$33	11.9

In the third quarter 2023, interest expense, net of amounts capitalized was $104 million compared to $98 million for the corresponding period in 2022. For year-to-date 2023, interest expense, net of amounts capitalized was $311 million compared to $278 million for the corresponding period in 2022. The increases for the third quarter and year-to-date 2023 were primarily associated with increases of approximately $5 million and $25 million, respectively, related to higher average outstanding borrowings and $4 million and $15 million, respectively, related to higher interest rates. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" herein for additional information on borrowings.

Other Income (Expense), Net

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$16	15.8

For year-to-date 2023, other income (expense), net was $117 million compared to $101 million for the corresponding period in 2022. The increase was primarily due to a decrease in non-operating benefit-related expenses and an increase in interest income, partially offset by a decrease in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.

Income Taxes

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(87)	(52.4)	$(291)	(73.9)

In the third quarter 2023, income taxes were $79 million compared to $166 million for the corresponding period in 2022. For year-to-date 2023, income taxes were $103 million compared to $394 million for the corresponding period in 2022. The decreases were primarily due to an increase in the flowback of certain excess deferred income taxes and lower pre-tax earnings. See Note 2 to the financial statements under "Alabama Power – Excess Accumulated Deferred Income Tax Accounting Order" in Item 8 of the Form 10-K and Note (G) to the Condensed Financial Statements herein for additional information.

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Georgia Power

Net Income

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(78)	(9.1)	$(304)	(16.4)

Georgia Power's net income in the third quarter 2023 was $780 million compared to $858 million for the corresponding period in 2022. The decrease was primarily due to an increase of $172 million in after-tax charges related to the construction of Plant Vogtle Units 3 and 4, as well as higher interest expense, partially offset by an increase in retail revenues associated with warmer weather in the third quarter 2023 compared to the corresponding period in 2022 and lower non-fuel operations and maintenance costs. Also partially offsetting the net income reductions were the impacts of the 2022 ARP effective January 1, 2023, including increased retail rates, largely offset by higher depreciation and amortization.

For year-to-date 2023, net income was $1.55 billion compared to $1.85 billion for the corresponding period in 2022. The decrease was primarily due to a decrease in retail revenues associated with lower contributions from variable demand-driven pricing and milder weather in the first and second quarters of 2023 compared to the corresponding periods in 2022, an increase of $133 million in after-tax charges related to the construction of Plant Vogtle Units 3 and 4, and higher interest expense, partially offset by lower non-fuel operations and maintenance costs. Also partially offsetting the net income reductions were the impacts of the 2022 ARP effective January 1, 2023, including increased retail rates, largely offset by higher depreciation and amortization.

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" for additional information.

Retail Revenues

In the third quarter 2023, retail revenues were $3.00 billion compared to $3.70 billion for the corresponding period in 2022. For year-to-date 2023, retail revenues were $7.14 billion compared to $8.63 billion for the corresponding period in 2022. Details of the changes in retail revenues were as follows:

	Third Quarter 2023 vs. Third Quarter 2022				Year-To-Date 2023 vs.  Year-To-Date 2022
	(change in millions)		(% change)		(change in millions)		(% change)
Rates and pricing	$	17	0.4	%	$	(115)	(1.3)	%
Sales decline	(31)		(0.8)		(17)		(0.2)
Weather	88		2.4		(109)		(1.3)
Fuel cost recovery	(781)		(21.1)		(1,246)		(14.4)
Retail revenues	$	(707)	(19.1)	%	$	(1,487)	(17.2)	%

Revenues associated with changes in rates and pricing increased in the third quarter 2023 when compared to the corresponding period in 2022 primarily due to base tariff increases in accordance with the 2022 ARP, partially offset by lower contributions from commercial and industrial customers with variable demand-driven pricing and a decrease in revenues recognized under the NCCR tariff. Revenues associated with changes in rates and pricing decreased for year-to-date 2023 when compared to the corresponding period in 2022 primarily due to lower contributions from commercial and industrial customers with variable demand-driven pricing and a decrease in revenues recognized under the NCCR tariff, partially offset by base tariff increases in accordance with the 2022 ARP. See Note 2 to the financial statements under "Georgia Power – Rate Plans" and " – Nuclear Construction" in Item 8 of the Form 10-K for additional information.

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Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2023 when compared to the corresponding periods in 2022. Weather-adjusted residential KWH sales decreased 2.6% and 0.7% in the third quarter and year-to-date 2023, respectively, when compared to the corresponding periods in 2022 primarily due to decreased customer usage, partially offset by customer growth. Weather-adjusted commercial KWH sales increased 0.4% and 1.1% in the third quarter and year-to-date 2023, respectively, when compared to the corresponding periods in 2022 primarily due to customer growth. The increase in weather-adjusted commercial KWH sales in the third quarter 2023 was partially offset by decreased customer usage. Weather-adjusted industrial KWH sales decreased 1.3% in the third quarter 2023 when compared to the corresponding period in 2022 primarily due to decreases in the pipeline and chemicals sectors, partially offset by an increase in the paper sector. Weather-adjusted industrial KWH sales decreased 1.0% for year-to-date 2023 when compared to the corresponding period in 2022 primarily due to decreases in the textile and mining sectors, partially offset by increases in the paper and electronics sectors.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased in the third quarter and year-to-date 2023 when compared to the corresponding periods in 2022 due to lower 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 (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 – Fuel Cost Recovery" for additional information.

Wholesale Revenues

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$13	23.2	$(39)	(21.0)

In the third quarter 2023, wholesale revenues were $69 million compared to $56 million for the corresponding period in 2022. The increase was primarily due to a $22 million increase related to the volume of KWH sales associated with higher market demand and a $17 million increase related to new capacity contracts, partially offset by a $26 million decrease related to the average cost per KWH sold due to lower Southern Company system fuel and purchased power costs.

For year-to-date 2023, wholesale revenues were $147 million compared to $186 million for the corresponding period in 2022. The decrease was primarily due to a $41 million decrease related to the average cost per KWH sold due to lower Southern Company system fuel and purchased power costs and a $13 million decrease related to the volume of KWH sales associated with lower market demand, partially offset by a $19 million increase related to new capacity contracts.

Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Wholesale capacity revenues from PPAs are recognized in amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.

Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by

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the FERC. Energy revenues related to these transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.

Other Revenues

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$42	32.3	$113	28.0

In the third quarter 2023, other revenues were $172 million compared to $130 million for the corresponding period in 2022. For year-to-date 2023, other revenues were $516 million compared to $403 million for the corresponding period in 2022. The increases for the third quarter and year-to-date 2023 were primarily due to increases of $27 million and $78 million, respectively, in unregulated sales associated with power delivery construction and maintenance, outdoor lighting, and energy conservation projects, net increases of $7 million and $18 million, respectively, in realized gains associated with price stability products for retail customers on variable demand-driven pricing tariffs, and increases of $10 million in retail solar program fees. Also contributing to the increase for year-to-date 2023 was an $11 million increase in open access transmission tariff sales.

Fuel and Purchased Power Expenses

	Third Quarter 2023 vs. Third Quarter 2022			Year-To-Date 2023 vs. Year-To-Date 2022
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	(265)	(31.5)	$	(495)	(26.2)
Purchased power – non-affiliates	(173)		(56.9)	(303)		(43.3)
Purchased power – affiliates	(350)		(61.3)	(521)		(47.4)
Total fuel and purchased power expenses	$	(788)		$	(1,319)

In the third quarter 2023, total fuel and purchased power expenses were $0.9 billion compared to $1.7 billion for the corresponding period in 2022. For year-to-date 2023, total fuel and purchased power expenses were $2.4 billion compared to $3.7 billion for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were due to decreases of $689 million and $1.0 billion, respectively, related to the average cost of fuel and purchased power and net decreases of $99 million and $293 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 (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 – Fuel Cost Recovery" for additional information.

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AND RESULTS OF OPERATIONS (Continued)

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

	Third Quarter 2023	Third Quarter 2022	Year-To-Date 2023	Year-To-Date 2022
Total generation (in billions of KWHs)(a)	18	15	46	45
Total purchased power (in billions of KWHs)	9	11	23	27
Sources of generation (percent) —
Gas	47	53	51	48
Nuclear(a)	26	28	27	26
Coal	25	16	19	22
Hydro and other	2	3	3	4
Cost of fuel, generated (in cents per net KWH) —
Gas	2.99	6.10	3.07	4.99
Nuclear(a)	0.87	0.75	0.79	0.76
Coal	5.69	4.73	5.80	3.84
Average cost of fuel, generated (in cents per net KWH)(a)	3.11	4.32	2.98	3.56
Average cost of purchased power (in cents per net KWH)(b)	4.55	10.14	4.64	8.00

(a)Excludes KWHs generated from test period energy at Plant Vogtle Unit 3 prior to its in-service date. The related fuel costs are charged to CWIP in accordance with FERC guidance. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

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

Fuel

In the third quarter 2023, fuel expense was $576 million compared to $841 million for the corresponding period in 2022. The decrease was primarily due to a decrease of 51.0% in the average cost per KWH generated by natural gas, partially offset by increases of 78.6% in the volume of KWHs generated by coal, 20.3% in the average cost per KWH generated by coal, 16.0% in the average cost per KWH generated by nuclear, 8.8% in the volume of KWHs generated by nuclear, and 3.0% in the volume of KWHs generated by natural gas.

For year-to-date 2023, fuel expense was $1.39 billion compared to $1.89 billion for the corresponding period in 2022. The decrease was primarily due to decreases of 38.5% in the average cost per KWH generated by natural gas and 10.2% in the volume of KWHs generated by coal, partially offset by increases of 51.0% in the average cost per KWH generated by coal and 7.0% in the volume of KWHs generated by natural gas.

Purchased Power – Non-Affiliates

In the third quarter 2023, purchased power expense from non-affiliates was $131 million compared to $304 million for the corresponding period in 2022. For year-to-date 2023, purchased power expense from non-affiliates was $397 million compared to $700 million for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were primarily due to decreases of 38.1% and 37.8%, respectively, in the volume of KWHs purchased as Georgia Power and other Southern Company system units generally dispatched at a lower cost than available market resources and 45.1% and 24.1%, respectively, in the average cost per KWH purchased primarily due to lower natural gas prices.

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

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Purchased Power – Affiliates

In the third quarter 2023, purchased power expense from affiliates was $221 million compared to $571 million for the corresponding period in 2022. For year-to-date 2023, purchased power expense from affiliates was $579 million compared to $1.1 billion for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 reflect decreases of 60.0% and 49.8%, respectively, in the average cost per KWH purchased primarily due to lower natural gas prices. Also contributing to the decrease in the third quarter 2023 was a 5.5% decrease in the volume of KWHs purchased.

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

Other Operations and Maintenance Expenses

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(83)	(13.9)	$(181)	(10.7)

In the third quarter 2023, other operations and maintenance expenses were $512 million compared to $595 million for the corresponding period in 2022. The decrease was primarily due to decreases of $64 million in transmission and distribution expenses primarily associated with line maintenance, $45 million in storm damage recovery as authorized in the 2022 ARP, and $25 million in generation non-outage maintenance expenses. These decreases were partially offset by increases of $21 million in generation environmental projects and $20 million from unregulated power delivery construction and maintenance and energy conservation projects.

For year-to-date 2023, other operations and maintenance expenses were $1.51 billion compared to $1.69 billion for the corresponding period in 2022. The decrease was primarily due to decreases of $136 million in storm damage recovery as authorized in the 2022 ARP, $121 million in transmission and distribution expenses primarily associated with line maintenance, $74 million in generation non-outage maintenance expenses, and $14 million in certain employee compensation and benefit expenses. These decreases were partially offset by increases of $48 million from unregulated power delivery construction and maintenance and energy conservation projects, $41 million in generation environmental projects, and $39 million in technology infrastructure and application production costs, as well as a $12 million decrease in nuclear property insurance refunds.

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

Depreciation and Amortization

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$70	19.5	$182	17.1

In the third quarter 2023, depreciation and amortization was $429 million compared to $359 million for the corresponding period in 2022. For year-to-date 2023, depreciation and amortization was $1.25 billion compared to $1.07 billion for the corresponding period in 2022. The increases for the third quarter and year-to-date 2023 were primarily due to increases of $48 million and $142 million, respectively, resulting from higher depreciation rates as authorized in the 2022 ARP and $21 million and $51 million, respectively, associated with additional plant in service. Partially offsetting the increase for year-to-date 2023 was a decrease of $11 million in amortization of regulatory assets related to the retirement of certain generating units that ended in 2022.

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

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Taxes Other Than Income Taxes

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(11)	(7.1)	$(14)	(3.3)

In the third quarter 2023, taxes other than income taxes were $144 million compared to $155 million for the corresponding period in 2022. For year-to-date 2023, taxes other than income taxes were $406 million compared to $420 million for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were due to decreases of $15 million and $33 million, respectively, in municipal franchise fees resulting from lower retail revenues, partially offset by increases of $3 million and $21 million, respectively, in property taxes primarily resulting from an increase in the assessed value of property.

Estimated Loss on Plant Vogtle Units 3 and 4

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$230	N/M	$178	N/M

Georgia Power recorded pre-tax charges (credits) to income for the estimated probable loss on Plant Vogtle Units 3 and 4 totaling $160 million and $(70) million in the third quarter 2023 and 2022, respectively, and $160 million and $(18) million for year-to-date 2023 and 2022, respectively. The charges (credits) reflected revisions to the total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements herein and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.

Allowance for Equity Funds Used During Construction

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$19	18.6

For year-to-date 2023, allowance for equity funds used during construction was $121 million compared to $102 million for the corresponding period in 2022. The increase was primarily due to an increase in capital expenditures subject to AFUDC.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$43	35.0	$125	36.0

In the third quarter 2023, interest expense, net of amounts capitalized was $166 million compared to $123 million for the corresponding period in 2022. For year-to-date 2023, interest expense, net of amounts capitalized was $472 million compared to $347 million for the corresponding period in 2022. The increases for the third quarter and year-to-date 2023 were primarily associated with increases of approximately $20 million and $64 million, respectively, related to higher average outstanding borrowings and $19 million and $59 million, respectively, related to higher interest rates. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.

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Other Income (Expense), Net

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$9	25.0	$(15)	(10.7)

In the third quarter 2023, other income (expense), net was $45 million compared to $36 million for the corresponding period in 2022. The increase was primarily due to a $6 million decrease in non-operating marketing expenses.

For year-to-date 2023, other income (expense), net was $125 million compared to $140 million for the corresponding period in 2022. The decrease was primarily due to a decrease of $13 million in customer charges related to contributions in aid of construction and a $7 million charge in the second quarter 2023 under a stipulation agreement approved by the Georgia PSC related to Georgia Power's fuel cost recovery case, partially offset by a $6 million decrease in non-operating marketing expenses. See Note (B) to the Condensed Financial Statements herein under "Georgia Power – Fuel Cost Recovery" for additional information.

Income Taxes

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(26)	(11.5)	$(76)	(18.1)

In the third quarter 2023, income taxes were $200 million compared to $226 million for the corresponding period in 2022. For year-to-date 2023, income taxes were $345 million compared to $421 million for the corresponding period in 2022. The decreases were primarily due to lower pre-tax earnings largely resulting from higher charges associated with the construction of Plant Vogtle Units 3 and 4 and a decrease in a valuation allowance on certain state tax credit carryforwards in 2023, partially offset by the flowback of certain excess deferred income taxes that ended in 2022. Also contributing to the year-to-date 2023 decrease was an adjustment in the second quarter 2022 related to a prior year state tax credit carryforward. See Note (G) to the Condensed Financial Statements herein for additional information.

Mississippi Power

Net Income

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$13	21.0	$23	15.3

Mississippi Power's net income for the third quarter 2023 was $75 million compared to $62 million for the corresponding period in 2022. The increase was primarily due to an increase in revenues due to warmer weather in the third quarter 2023 when compared to the corresponding period in 2022.

Mississippi Power's net income for year-to-date 2023 was $173 million compared to $150 million for the corresponding period in 2022. The increase was primarily due to an increase in affiliate wholesale capacity revenues, partially offset by an increase in interest expense.

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Retail Revenues

In the third quarter 2023, retail revenues were $284 million compared to $250 million for the corresponding period in 2022. For year-to-date 2023, retail revenues were $747 million compared to $718 million for the corresponding period in 2022. Details of the changes in retail revenues were as follows:

	Third Quarter 2023 vs. Third Quarter 2022				Year-To-Date 2023 vs.  Year-To-Date 2022
	(change in millions)		(% change)		(change in millions)		(% change)
Rates and pricing	$	(3)	(1.2)	%	$	2	0.2	%
Sales growth	5		2.0		4		0.6
Weather	9		3.6		(1)		(0.1)
Fuel and other cost recovery	23		9.2		24		3.3
Retail revenues	$	34	13.6	%	$	29	4.0	%

Revenues associated with changes in rates and pricing decreased in the third quarter 2023 and increased year-to-date 2023 when compared to the corresponding periods in 2022. The third quarter 2023 decrease was primarily due to lower contributions from commercial and industrial customers with variable demand-driven pricing and the expiration of a PEP surcharge at the end of 2022 that became effective for the first billing cycle of April 2022, partially offset by higher revenues associated with a tolling arrangement accounted for as a sales-type lease. The year-to-date 2023 increase was primarily due to ECO Plan rates that became effective in May 2022 and higher revenues associated with a tolling arrangement accounted for as a sales-type lease, partially offset by the expiration of the PEP surcharge at the end of 2022 that became effective for the first billing cycle of April 2022. See Notes 2 and 9 to the financial statements under "Mississippi Power" and "Lessor," respectively, in Item 8 of the Form 10-K and Note (D) to the Condensed Financial Statements under "Lease Income" herein for additional information.

Revenues attributable to changes in sales increased in the third quarter and year-to-date 2023 when compared to the corresponding periods in 2022. Weather-adjusted residential KWH sales increased 0.9% in the third quarter 2023 when compared to the corresponding period in 2022 due to an increase in customer usage. Weather-adjusted residential KWH sales decreased 0.3% year-to-date 2023 when compared to the corresponding period in 2022 due to a decrease in customer usage. Weather-adjusted commercial KWH sales increased 11.8% and 6.4% in the third quarter and year-to-date 2023, respectively, when compared to the corresponding periods in 2022 due to sales growth associated with new commercial contracts. Industrial KWH sales increased 1.1% and 1.3% in the third quarter and year-to-date 2023, respectively, when compared to the corresponding periods in 2022 primarily due to an increase in the non-manufacturing sector, partially offset by a decrease in the chemicals sector.

Fuel and other cost recovery revenues increased in the third quarter and year-to-date 2023 when compared to the corresponding periods in 2022 primarily as a result of higher recoverable fuel costs. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel and emissions portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income. See Note 2 to the financial statements in Item 8 of the Form 10-K for additional information.

Wholesale Revenues – Non-Affiliates

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$17	28.3	$10	5.2

In the third quarter 2023, wholesale revenues from sales to non-affiliates were $77 million compared to $60 million for the corresponding period in 2022. The increase was primarily due to an $11 million increase associated with

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MRA customers and a $6 million increase associated with opportunity sales. The increase from MRA customers was primarily due to higher recoverable fuel costs and an increase in demand as a result of weather impacts.

For year-to-date 2023, wholesale revenues from sales to non-affiliates were $201 million compared to $191 million for the corresponding period in 2022. The increase was due to a $6 million increase associated with MRA customers and a $4 million increase associated with opportunity sales. The increase from MRA customers was primarily due to a rate increase under the MRA tariff effective September 2022 and higher recoverable fuel costs, partially offset by a decrease in demand as a result of weather impacts.

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

Wholesale Revenues – Affiliates

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(122)	(65.2)	$(178)	(53.0)

In the third quarter 2023, wholesale revenues from sales to affiliates were $65 million compared to $187 million for the corresponding period in 2022. The decrease was primarily due to a $141 million decrease associated with lower natural gas prices, partially offset by a $19 million increase associated with higher KWH sales.

For year-to-date 2023, wholesale revenues from sales to affiliates were $158 million compared to $336 million for the corresponding period in 2022. The decrease was primarily due to a $216 million decrease associated with lower natural gas prices, partially offset by a $29 million increase in capacity revenues resulting from an increase in pricing and volume of generation reserves and a $9 million increase associated with higher KWH sales.

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. Energy revenues related to these transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.

Fuel and Purchased Power Expenses

	Third Quarter 2023 vs. Third Quarter 2022			Year-To-Date 2023 vs. Year-To-Date 2022
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	(80)	(33.1)	$	(167)	(29.6)
Purchased power	(13)		(65.0)	(18)		(50.0)
Total fuel and purchased power expenses	$	(93)		$	(185)

In the third quarter 2023, total fuel and purchased power expenses were $169 million compared to $262 million for the corresponding period in 2022. For year-to-date 2023, total fuel and purchased power expenses were $416 million compared to $601 million for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were primarily due to decreases of $122 million and $203 million, respectively, related to the

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average cost of fuel and purchased power, partially offset by net increases of $29 million and $18 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 energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause.

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

	Third Quarter 2023	Third Quarter 2022	Year-To-Date 2023	Year-To-Date 2022
Total generation (in millions of KWHs)	5,783	5,093	14,123	13,650
Total purchased power (in millions of KWHs)	153	241	427	527
Sources of generation (percent) –
Gas	87	89	92	89
Coal	13	11	8	11
Cost of fuel, generated (in cents per net KWH) –
Gas	2.52	5.10	2.72	4.43
Coal	5.49	4.50	5.64	4.12
Average cost of fuel, generated (in cents per net KWH)	2.92	5.02	2.97	4.40
Average cost of purchased power (in cents per net KWH)	4.61	8.15	4.27	6.83

Fuel

In the third quarter 2023, fuel expense was $162 million compared to $242 million for the corresponding period in 2022. The decrease was due to a 50.6% decrease in the average cost of natural gas per KWH generated, partially offset by a 28.5% increase in the volume of KWHs generated by coal, a 22.0% increase in the average cost of coal per KWH generated, and a 13.5% increase in the volume of KWHs generated by natural gas.

For year-to-date 2023, fuel expense was $398 million compared to $565 million for the corresponding period in 2022. The decrease was due to a 38.6% decrease in the average cost of natural gas per KWH generated and a 21.7% decrease in the volume of KWHs generated by coal, partially offset by a 36.9% increase in the average cost of coal per KWH generated and a 7.5% increase in the volume of KWHs generated by natural gas.

Purchased Power

In the third quarter 2023, purchased power expense was $7 million compared to $20 million for the corresponding period in 2022. For year-to-date 2023, purchased power expense was $18 million compared to $36 million for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were due to decreases of 43.4% and 37.5%, respectively, in the average cost per KWH purchased primarily due to lower natural gas prices and decreases of 36.4% and 18.9%, respectively, in the volume of KWHs purchased.

Other Operations and Maintenance Expenses

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(2)	(2.3)	$6	2.4

For year-to-date 2023, other operations and maintenance expenses were $258 million compared to $252 million for the corresponding period in 2022. The increase was primarily due to increases of $5 million in generation expenses and $4 million in storm reserve accruals, partially offset by a decrease of $5 million in sales and use taxes associated with the Kemper County energy facility.

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See Notes 2 and 3 to the financial statements under "Mississippi Power – System Restoration Rider" and "Other Matters – Mississippi Power," respectively, in Item 8 of the Form 10-K and Notes (B) and (C) to the Condensed Financial Statements under "Mississippi Power – System Restoration Rider" and "Other Matters – Mississippi Power," respectively, herein for additional information.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$4	26.7	$11	26.2

In the third quarter 2023, interest expense, net of amounts capitalized was $19 million compared to $15 million for the corresponding period in 2022. For year-to-date 2023, interest expense, net of amounts capitalized was $53 million compared to $42 million for the corresponding period in 2022. The increases for the third quarter and year-to-date 2023 were associated with increases of approximately $2 million and $8 million, respectively, related to higher interest rates and $2 million and $4 million, respectively, related to higher average outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.

Income Taxes

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$1	5.9	$(3)	(7.9)

For year-to-date 2023, income taxes were $35 million compared to $38 million for the corresponding period in 2022. The decrease was primarily due to a decrease of $7 million associated with the flowback of certain excess deferred income taxes, largely offset by an increase of $5 million associated with higher pre-tax earnings. See Note (G) to the Condensed Financial Statements herein for additional information.

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Southern Power

Net Income Attributable to Southern Power

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$5	5.3	$23	8.7

Net income attributable to Southern Power in the third quarter 2023 was $100 million compared to $95 million for the corresponding period in 2022. The increase was primarily due to an arbitration interim award received for losses previously incurred, higher HLBV income associated with tax equity partnerships, and receipts of liquidated damages associated with generation facility production guarantees, partially offset by lower revenues driven by lower market prices of energy.

Net income attributable to Southern Power for year-to-date 2023 was $288 million compared to $265 million for the corresponding period in 2022. The increase was primarily due to an arbitration interim award received for losses previously incurred, a gain on the sale of spare parts, higher HLBV income associated with tax equity partnerships, and receipts of liquidated damages and insurance proceeds related to generation facility production and equipment, as well as changes in state apportionment methodology related to tax legislation enacted by the State of Tennessee. These increases were largely offset by lower revenues driven by lower market prices of energy.

See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information.

Operating Revenues

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(527)	(44.7)	$(932)	(35.6)

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

Natural Gas Capacity and Energy Revenue

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

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

Solar and Wind Energy Revenue

Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have capacity revenue. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy generated from the respective facility and sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is

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dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors.

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

Operating Revenues Details

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

	Third Quarter 2023		Third Quarter 2022		Year-To-Date 2023		Year-To-Date 2022
	(in millions)
PPA capacity revenues	$	134	$	131	$	360	$	344
PPA energy revenues	370		736		953		1,657
Total PPA revenues	504		867		1,313		2,001
Non-PPA revenues	131		304		327		590
Other revenues	18		9		46		27
Total operating revenues	$	653	$	1,180	$	1,686	$	2,618

In the third quarter 2023, total operating revenues were $653 million, reflecting a $527 million, or 44.7%, decrease from the corresponding period in 2022. The change in operating revenues was primarily due to the following:

•PPA energy revenues decreased $366 million, or 49.7%, primarily due to a $378 million decrease in sales under natural gas PPAs resulting from a $304 million decrease in the price of fuel and purchased power and a $75 million decrease in the volume of KWHs sold.

•Non-PPA revenues decreased $173 million, or 56.9%, primarily due to a $252 million decrease in the market price of energy, partially offset by a $76 million increase in the volume of KWHs sold through short-term sales.

•Other revenues increased $9 million, or 100.0%, primarily due to an arbitration interim award received for losses previously incurred. See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information.

For year-to-date 2023, total operating revenues were $1.7 billion, reflecting a $932 million, or 35.6%, decrease from the corresponding period in 2022. The change in operating revenues was primarily due to the following:

•PPA capacity revenues increased $16 million, or 4.7%, primarily due to a net increase in MW capacity under contract from natural gas PPAs and an increase associated with a change in rates from natural gas PPAs.

•PPA energy revenues decreased $704 million, or 42.5%, primarily due to a $706 million decrease in sales under natural gas PPAs resulting from a $577 million decrease in the price of fuel and purchased power and a $129 million decrease in the volume of KWHs sold.

•Non-PPA revenues decreased $263 million, or 44.6%, primarily due to a $522 million decrease in the market price of energy, partially offset by a $255 million increase in the volume of KWHs sold through short-term sales.

•Other revenues increased $19 million, or 70.4%, primarily due to receipts of liquidated damages associated with generation facility production guarantees, an arbitration interim award received for losses previously incurred, and business interruption insurance proceeds for damaged generation equipment. See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information.

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Fuel and Purchased Power Expenses

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

	Third Quarter 2023	Third Quarter 2022	Year-To-Date 2023	Year-To-Date 2022
	(in billions of KWHs)
Generation	12.9	12.8	36.9	36.7
Purchased power	0.8	1.2	2.4	2.3
Total generation and purchased power	13.7	14.0	39.3	39.0
Total generation and purchased power (excluding solar, wind, fuel cells, and tolling agreements)	8.5	8.8	24.7	23.2

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

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

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

	Third Quarter 2023 vs. Third Quarter 2022			Year-To-Date 2023 vs. Year-To-Date 2022
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	(409)	(67.6)	$	(748)	(58.7)
Purchased power	(111)		(77.1)	(146)		(62.7)
Total fuel and purchased power expenses	$	(520)		$	(894)

In the third quarter 2023, total fuel and purchased power expenses decreased $520 million, or 69.4%, compared to the corresponding period in 2022. Fuel expense decreased $409 million primarily due to a $421 million decrease associated with the average cost of fuel. Purchased power expense decreased $111 million due to a $61 million decrease associated with the average cost of purchased power and a $50 million decrease associated with the volume of KWHs purchased.

For year-to-date 2023, total fuel and purchased power expenses decreased $894 million, or 59.3%, compared to the corresponding period in 2022. Fuel expense decreased $748 million due to an $835 million decrease associated with the average cost of fuel, partially offset by an $87 million increase associated with the volume of KWHs generated. Purchased power expense decreased $146 million primarily due to a $152 million decrease associated with the average cost of purchased power.

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AND RESULTS OF OPERATIONS (Continued)

Other Operations and Maintenance Expenses

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(9)	(8.0)	$(5)	(1.5)

In the third quarter 2023, other operations and maintenance expenses were $104 million compared to $113 million for the corresponding period in 2022. For year-to-date 2023, other operations and maintenance expenses were $327 million compared to $332 million for the corresponding period in 2022. The decreases were primarily due to $11 million from an arbitration interim award received for losses previously incurred. The year-to-date 2023 decrease was largely offset by an increase in generation maintenance expenses. See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information.

Gain on Dispositions, Net

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$18	N/M

For year-to-date 2023, gain on dispositions, net was $20 million compared to $2 million for the corresponding period in 2022. The increase was primarily due to a $16 million gain on the sale of spare parts in 2023.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$(7)	(6.7)

For year-to-date 2023, interest expense, net of amounts capitalized was $98 million compared to $105 million for the corresponding period in 2022. The decrease was primarily due to lower average outstanding borrowings.

Income Taxes

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$3	8.3	$(11)	(22.4)

For year-to-date 2023, income tax expense was $38 million compared to $49 million for the corresponding period in 2022. The decrease was primarily due to a change in state apportionment methodology resulting from tax legislation enacted by the State of Tennessee in the second quarter 2023, partially offset by higher pre-tax earnings. See Note (G) to the Condensed Financial Statements herein for additional information.

Net Income (Loss) Attributable to Noncontrolling Interests

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(2)	(16.7)	$(13)	(23.6)

In the third quarter 2023, net income attributable to noncontrolling interests was $10 million compared to $12 million for the corresponding period in 2022. The decrease was primarily due to $7 million in higher HLBV loss allocations to wind tax equity partners, largely offset by an allocation of $6 million to equity partners related to an arbitration interim award received for losses previously incurred.

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For year-to-date 2023, net loss attributable to noncontrolling interests was $68 million compared to $55 million for the corresponding period in 2022. The increase was primarily due to $16 million in higher HLBV loss allocations to wind tax equity partners and $12 million in lower income allocations to equity partners, partially offset by $15 million in lower loss allocations to battery energy storage partners.

See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information.

Southern Company Gas

Operating Metrics

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

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.

Seasonality of Results

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

Net Income

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(1)	(1.2)	$(41)	(7.9)

Southern Company Gas' net income for year-to-date 2023 was $475 million compared to $516 million for the corresponding period in 2022. The decrease was primarily due to lower net income at gas distribution operations primarily as a result of a $28 million regulatory disallowance at Nicor Gas and a $6 million decrease in net income at gas marketing services primarily related to hedge losses. See Note (B) to the Condensed Financial Statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" herein for additional information.

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AND RESULTS OF OPERATIONS (Continued)

Natural Gas Revenues

In the third quarter 2023, natural gas revenues were $0.7 billion compared to $0.9 billion for the corresponding period in 2022. For year-to-date 2023, natural gas revenues were $3.4 billion compared to $4.0 billion for the corresponding period in 2022. Details of the changes in natural gas revenues were as follows:

	Third Quarter 2023 vs. Third Quarter 2022				Year-To-Date 2023 vs.  Year-To-Date 2022
	(change in millions)		(% change)		(change in millions)		(% change)
Infrastructure replacement programs and rate changes	$	9	1.1	%	$	97	2.4	%
Gas costs and other cost recovery	(181)		(21.1)		(645)		(16.1)
Gas marketing services	(22)		(2.6)		(44)		(1.1)
Other	26		3.0		11		0.3
Natural gas revenues	$	(168)	(19.6)	%	$	(581)	(14.5)	%

Revenues from infrastructure replacement programs and rate changes increased in the third quarter and year-to-date 2023 compared to the corresponding periods in 2022 primarily due to rate increases at the natural gas distribution utilities and continued investment in infrastructure replacement. The year-to-date 2023 increase was partially offset by a regulatory disallowance at Nicor Gas. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" herein for additional information.

Revenues from gas costs and other cost recovery decreased in the third quarter and year-to-date 2023 compared to the corresponding periods in 2022 primarily due to lower natural gas cost recovery associated with lower natural gas prices, the timing of natural gas purchases, and the recovery of those costs from customers. See "Cost of Natural Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.

Revenues from gas marketing services decreased in the third quarter and year-to-date 2023 compared to the corresponding periods in 2022 primarily due to lower natural gas prices and lower variable price spreads.

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

	Third Quarter							Year-to-Date
				2023 vs. normal		2023 vs. 2022					2023 vs. normal		2023 vs. 2022
	Normal(*)	2023	2022	warmer		warmer		Normal(*)	2023	2022	warmer		warmer
	(in thousands)							(in thousands)
Illinois	40	18	56	(55.0)	%	(67.9)	%	3,755	3,216	3,683	(14.4)	%	(12.7)	%
Georgia	3	—	—	—	%	—	%	1,461	1,029	1,361	(29.6)	%	(24.4)	%

(*)Normal represents the 10-year average from January 1, 2013 through September 30, 2022 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.

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AND RESULTS OF OPERATIONS (Continued)

The following table provides the number of customers served by Southern Company Gas at September 30, 2023 and 2022:

	September 30,
	2023		2022		2023 vs. 2022
	(in thousands, except market share %)				(% change)
Gas distribution operations	4,316		4,300		0.4	%
Gas marketing services
Energy customers(*)	656		598		9.7	%
Market share of energy customers in Georgia	29.9	%	28.3	%

(*)Gas marketing services' customers are primarily located in Georgia, Ohio, and Illinois.

Southern Company Gas anticipates customer growth and uses a variety of targeted marketing programs to attract new customers and to retain existing customers.

Cost of Natural Gas

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(192)	(65.3)	$(641)	(34.8)

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 76% and 84% of the total cost of natural gas in the third quarter and year-to-date 2023, respectively. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Southern Company Gas – Cost of Natural Gas" in Item 7 of the Form 10-K and "Natural Gas Revenues" herein for additional information.

In the third quarter 2023, cost of natural gas was $102 million compared to $294 million for the corresponding period in 2022. For year-to-date 2023, cost of natural gas was $1.2 billion compared to $1.8 billion for the corresponding period in 2022. The decreases reflect lower gas cost recovery as a result of decreases of 69% and 60% in natural gas prices in the third quarter and year-to-date 2023, respectively, compared to the corresponding periods in 2022.

The following table details the volumes of natural gas sold during both periods presented:

	Third Quarter				Year-to-Date
	2023	2022	2023 vs. 2022		2023	2022	2023 vs. 2022
Gas distribution operations (mmBtu in millions)
Firm	71	70	1.4	%	429	485	(11.5)	%
Interruptible	22	22	—		70	69	1.4
Total	93	92	1.1	%	499	554	(9.9)	%
Gas marketing services (mmBtu in millions)
Firm:
Georgia	3	3	—	%	21	24	(12.5)	%
Illinois	1	—	100.0		5	4	25.0
Other	3	2	50.0		9	8	12.5
Interruptible large commercial and industrial	2	3	(33.3)		10	11	(9.1)
Total	9	8	12.5	%	45	47	(4.3)	%

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Other Operations and Maintenance Expenses

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$12	4.8	$55	6.7

In the third quarter 2023, other operations and maintenance expenses were $264 million compared to $252 million for the corresponding period in 2022. The increase for the third quarter 2023 was primarily due to increases of $8 million in compensation and benefits, $5 million related to energy service contracts, and $4 million at gas marketing services primarily related to customer service and information. The increases were partially offset by a decrease of $12 million in expenses passed through to customers primarily related to bad debt and energy efficiency programs at gas distribution operations.

For year-to-date 2023, other operations and maintenance expenses were $879 million compared to $824 million for the corresponding period in 2022. The increase was primarily due to increases of $52 million in compensation and benefits, $30 million related to a regulatory disallowance at Nicor Gas, and an increase of $20 million related to energy service contracts, partially offset by a decrease of $32 million in expenses passed through to customers primarily related to bad debt and energy efficiency programs at gas distribution operations. See Note (B) to the Condensed Financial Statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" herein for additional information on the regulatory disallowance.

Depreciation and Amortization

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$5	3.6	$15	3.6

In the third quarter 2023, depreciation and amortization was $145 million compared to $140 million for the corresponding period in 2022. For year-to-date 2023, depreciation and amortization was $429 million compared to $414 million for the corresponding period in 2022. The increases were primarily due to continued infrastructure investments at the natural gas distribution utilities.

Taxes Other Than Income Taxes

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$(3)	(6.7)	$(5)	(2.4)

In the third quarter 2023, taxes other than income taxes was $42 million compared to $45 million for the corresponding period in 2022. For year-to-date 2023, taxes other than income taxes was $203 million compared to $208 million for the corresponding period in 2022. The decreases for the third quarter and year-to-date 2023 were primarily due to decreases of $3 million and $15 million, respectively, in revenue taxes. The year-to-date 2023 decrease was largely offset by increases of $8 million and $2 million in payroll and property taxes, respectively.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2023 vs. Third Quarter 2022		Year-To-Date 2023 vs. Year-To-Date 2022
(change in millions)	(% change)	(change in millions)	(% change)
$12	18.5	$39	20.9

In the third quarter 2023, interest expense, net of amounts capitalized was $77 million compared to $65 million for the corresponding period in 2022. For year-to-date 2023, interest expense, net of amounts capitalized was $226 million compared to $187 million for the corresponding period in 2022. The increases for the third quarter and year-to-date 2023 were primarily associated with increases of approximately $8 million and $31 million, respectively,

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related to higher interest rates and approximately $3 million and $7 million, respectively, related to higher outstanding debt. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings.

Segment Information

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

	2023						2022
	Operating Revenues		Operating Expenses		Net Income (Loss)		Operating Revenues		Operating Expenses		Net Income (Loss)
	(in millions)						(in millions)
Third Quarter
Gas distribution operations	$	619	$	485	$	70	$	751	$	629	$	59
Gas pipeline investments	8		2		24		8		3		24
Gas marketing services	56		53		2		85		87		(2)
All other	8		12		(14)		16		12		2
Intercompany eliminations	(2)		1		—		(3)		—		—
Consolidated	$	689	$	553	$	82	$	857	$	731	$	83
Year-to-Date
Gas distribution operations	$	3,002	$	2,386	$	352	$	3,533	$	2,922	$	365
Gas pipeline investments	24		7		73		24		8		76
Gas marketing services	376		292		59		420		327		65
All other	30		30		(9)		43		48		10
Intercompany eliminations	(15)		(5)		—		(22)		(19)		—
Consolidated	$	3,417	$	2,710	$	475	$	3,998	$	3,286	$	516

Gas Distribution Operations

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

With the exception of Atlanta Gas Light, Southern Company Gas' second largest utility that operates in a deregulated natural gas market and has a straight-fixed-variable rate design that minimizes the variability of its revenues based on consumption, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas, and general economic conditions that may impact customers' ability to pay for natural gas consumed. Southern Company Gas has various regulatory and other mechanisms, such as weather and revenue normalization mechanisms and weather derivative instruments, that limit its exposure to changes in customer consumption, including weather changes within typical ranges in its natural gas distribution utilities' service territories. See Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.

In the third quarter 2023, net income increased $11 million, or 18.6%, when compared to the corresponding period in 2022, as described further below:

•Operating revenues decreased $132 million primarily due to lower gas cost recovery, partially offset by rate increases and continued investment in infrastructure replacement. Gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas.

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•Operating expenses decreased $144 million primarily due to a $152 million decrease in cost of natural gas as a result of lower gas prices compared to 2022, partially offset by higher depreciation resulting from additional assets placed in service and an increase related to energy service contracts. The decrease in operating expenses also includes costs passed through directly to customers, primarily related to bad debt expenses, energy efficiency programs, and revenue taxes.

•Interest expense, net of amounts capitalized increased $7 million primarily due to higher interest rates and higher average outstanding debt.

For year-to-date 2023, net income decreased $13 million, or 3.6%, when compared to the corresponding period in 2022, as described further below:

•Operating revenues decreased $531 million primarily due to lower gas cost recovery, partially offset by rate increases and continued investment in infrastructure replacement. Gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas.

•Operating expenses decreased $536 million primarily due to a $599 million decrease in cost of natural gas as a result of lower gas prices and lower volumes sold compared to 2022, partially offset by higher depreciation resulting from additional assets placed in service, higher compensation and benefits, $30 million related to the regulatory disallowance at Nicor Gas, and a $20 million increase related to energy service contracts. The decrease in operating expenses also includes costs passed through directly to customers, primarily related to bad debt expenses, energy efficiency programs, and revenue taxes.

•Interest expense, net of amounts capitalized increased $32 million primarily due to higher interest rates and higher average outstanding debt.

•Income taxes decreased $13 million primarily as a result of the tax benefit resulting from the regulatory disallowance at Nicor Gas.

See Note (B) to the Condensed Financial Statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" herein for additional information.

Gas Pipeline Investments

Gas pipeline investments consists primarily of joint ventures in natural gas pipeline investments including SNG and Dalton Pipeline. See Note (E) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

Gas Marketing Services

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

In the third quarter 2023, net income increased $4 million, when compared to the corresponding period in 2022 primarily due to a $39 million decrease in cost of gas, largely offset by a $29 million decrease in operating revenue primarily due to lower price spreads and lower gas prices and a $4 million increase in operations and maintenance expenses primarily related to customer service and information.

For year-to-date 2023, net income decreased $6 million, or 9.2%, when compared to the corresponding period in 2022 primarily due to a $44 million decrease in operating revenue, primarily due to lower price spreads, lower gas prices, and lower volumes sold, as well as a $9 million increase in operations and maintenance expenses, largely offset by a $44 million decrease in cost of gas.

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All Other

All other includes natural gas storage businesses, a renewable natural gas business, AGL Services Company, and Southern Company Gas Capital, as well as various corporate operating expenses that are not allocated to the reportable segments and interest income (expense) associated with affiliate financing arrangements. All other included a natural gas storage facility in Texas through its sale in November 2022 and a natural gas storage facility in California through its sale in September 2023. 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 Company Gas" for additional information.

In the third quarter 2023, net income decreased $16 million when compared to the corresponding period in 2022, primarily due to a decrease in operating revenue and increases in operating expenses, interest expenses, and income taxes.

For year-to-date 2023, net income decreased $19 million when compared to the corresponding period in 2022. The decrease was primarily related to a decrease in operating revenue and increases in interest expenses and income taxes, partially offset by a decrease in operating expenses primarily related to lower depreciation in 2023, lower cost of gas, and lower taxes other than income taxes.

FUTURE EARNINGS POTENTIAL

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

For the traditional electric operating companies, these factors include the ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs during a time of increasing costs, including those related to projected long-term demand growth, stringent environmental standards, including CCR rules, safety, system reliability and resiliency, fuel, restoration following major storms, and capital expenditures, including constructing new electric generating plants and expanding and improving the transmission and distribution systems; continued customer growth; and the trends of higher inflation and reduced electricity usage per customer, especially in residential and commercial markets. For Georgia Power, other major factors are completing construction and start-up of Plant Vogtle Unit 4, meeting the related cost and schedule projections, and completing the related cost recovery proceedings for Plant Vogtle Units 3 and 4.

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 continue to be significantly affected by a series of demand and supply shocks that caused a global and national economic recession in 2020 and have been further impacted by the invasion of Ukraine and significant declines in labor force participation rates. The confluence of these disruptions has resulted in the highest levels of inflation globally in 40 years and driven a significant policy response by central banks across the global economy. The U.S. Federal Reserve has increased interest rates faster than any rate increase cycle in the last 40 years and to levels high enough to slow economic activity and reduce inflation rates, although target inflation levels have not yet been achieved. These actions and impacts, including increased costs for goods and services and borrowing costs, have led to a slowing of some economic activity and an increased risk of recession. Additionally, inflation remains elevated in part due to continued supply chain and labor market constraints. Electricity sales across all classes have recovered to pre-COVID-19 pandemic levels and customer growth at both the traditional electric operating companies and natural gas distribution utilities has remained strong. However, weakening economic activity increases the risk of slowing to declining energy sales. Additionally, the current economic environment has increased the uncertainty of future energy demand and operating costs. See RESULTS OF OPERATIONS herein for information on energy sales in the Southern Company system's service territory during the first nine months of 2023.

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AND RESULTS OF OPERATIONS (Continued)

The level of future earnings for Southern Power's competitive wholesale electric business depends on numerous factors including the parameters of the wholesale market and the efficient operation of its wholesale generating assets; Southern Power's ability to execute its growth strategy through the development, construction, or acquisition of renewable facilities and other energy projects while containing costs; regulatory matters; customer creditworthiness; total electric generating capacity available in Southern Power's market areas; Southern Power's ability to successfully remarket capacity as current contracts expire; renewable portfolio standards; continued availability of federal and state ITCs and PTCs, which could be impacted by future tax legislation; transmission constraints; cost of generation from units within the Southern Company power pool; and operational limitations. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" in Item 7 of the Form 10-K for information regarding the Inflation Reduction Act's expansion of the availability of federal ITCs and PTCs and Note (K) to the Condensed Financial Statements under "Southern Power" herein for information regarding acquisitions.

The level of future earnings for Southern Company Gas' primary business of distributing natural gas and its complementary businesses in the gas pipeline investments and gas marketing services sectors depends on numerous factors. These factors include the natural gas distribution utilities' ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs, including those related to projected long-term demand growth, safety, system reliability and resiliency, natural gas, and capital expenditures, including expanding and improving the natural gas distribution systems; the completion and subsequent operation of ongoing infrastructure and other construction projects; customer creditworthiness; and certain policies to limit the use of natural gas, such as the potential across certain parts of the U.S. for state or municipal bans on the use of natural gas or policies designed to promote electrification. The volatility of natural gas prices has an impact on Southern Company Gas' customer rates, its long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services business to capture value from locational and seasonal spreads. Additionally, changes in commodity prices, primarily driven by tight gas supplies, geopolitical events, and diminished gas production, subject a portion of Southern Company Gas' operations to earnings variability and may result in higher natural gas prices. Additional economic factors may contribute to this environment. The demand for natural gas may increase, which may cause natural gas prices to rise and drive higher volatility in the natural gas markets on a longer-term basis. Alternatively, a significant drop in oil and natural gas prices could lead to a consolidation of natural gas producers or reduced levels of natural gas production.

Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather; competition; developing new and maintaining existing energy contracts and associated load requirements with wholesale customers; customer energy conservation practices; the use of alternative energy sources by customers; government incentives to reduce overall energy usage; fuel, labor, and material prices in an environment of heightened inflation and material and labor supply chain disruptions; and the price elasticity of demand. Demand for electricity and natural gas in the Registrants' service territories is primarily driven by the pace of economic growth or decline that may be affected by changes in regional and global economic conditions, which may impact future earnings.

As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of, or the sale of interests in, certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company. In addition, Southern Power and Southern Company Gas regularly consider and evaluate joint development arrangements as well as acquisitions and dispositions of businesses and assets as part of their business strategies. See Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein for additional information.

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

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Environmental Matters

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

Environmental Laws and Regulations

Air Quality

On February 13, 2023, the EPA published a final rule disapproving 19 state implementation plans (SIPs), including the States of Alabama and Mississippi, under the interstate transport (good neighbor) provisions of the Clean Air Act for the 2015 Ozone National Ambient Air Quality Standards (NAAQS). On March 14, 2023 and March 15, 2023, the State of Mississippi and Mississippi Power, respectively, challenged the EPA's disapproval of the Mississippi SIP in the U.S. Court of Appeals for the Fifth Circuit. On May 11, 2023, the State of Mississippi and Mississippi Power filed a joint motion for stay of the EPA's disapproval of the Mississippi SIP, which was granted on June 8, 2023. On April 13, 2023 and April 14, 2023, the State of Alabama, Alabama Power, and PowerSouth Energy Cooperative challenged the EPA's disapproval of the Alabama SIP in the U.S. Court of Appeals for the Eleventh Circuit. On June 13, 2023, the State of Alabama, Alabama Power, and PowerSouth Energy Cooperative filed a joint motion for stay of the EPA's disapproval of the Alabama SIP, which was granted on August 17, 2023.

On June 5, 2023, the EPA published the 2015 Ozone NAAQS Good Neighbor federal implementation plans (FIP), which became effective on August 4, 2023. On June 16, 2023 and June 27, 2023, the State of Mississippi and Mississippi Power, respectively, challenged the FIP for Mississippi in the U.S. Court of Appeals for the Fifth Circuit. On June 30, 2023, the State of Mississippi and Mississippi Power filed in the U.S. Court of Appeals for the Fifth Circuit a joint motion for stay of the FIP for Mississippi and a request to hold the case in abeyance pending resolution of the Mississippi SIP disapproval case. On July 20, 2023, the U.S. Court of Appeals for the Fifth Circuit denied the motion for stay but granted the motion to hold the case in abeyance. On August 4, 2023, the State of Alabama, Alabama Power, and PowerSouth Energy Cooperative challenged the FIP for Alabama in the U.S. Court of Appeals for the Eleventh Circuit. On August 16, 2023, the State of Alabama, Alabama Power, and PowerSouth Energy Cooperative filed in the U.S. Court of Appeals for the Eleventh Circuit a joint motion requesting an abeyance of the case pending resolution of the Alabama SIP disapproval case, which was granted on August 30, 2023.

On July 31, 2023, the EPA published an Interim Final Rule that stays the implementation of the FIPs for states with judicially stayed SIP disapprovals, including Mississippi. On September 29, 2023, the EPA published an updated Interim Final Rule addressing judicial stays of states' interstate transport SIP disapprovals, including Alabama. The Interim Final Rule revises the existing regulations to maintain currently applicable trading programs for those states.

The ultimate impact of the rule and associated legal matters cannot be determined at this time; however, implementation of the FIPs will likely result in increased compliance costs for the traditional electric operating companies.

Water Quality

On March 29, 2023, the EPA published a proposed ELG Supplemental Rule revising certain effluent limits of the 2020 and 2015 ELG rules. The proposal imposes more stringent requirements for flue gas desulfurization wastewater, bottom ash transport water, and combustion residual leachate to be met no later than December 31, 2029. The EPA is also proposing that a limited number of facilities already achieving compliance with the 2020 ELG Reconsideration Rule be allowed to elect retirement or repowering by December 31, 2032 as opposed to meeting the new more stringent requirements. The proposal maintains the 2020 ELG Reconsideration Rule's permanent cessation of coal combustion subcategory allowing units to continue to operate until the end of 2028 without having to install additional technologies. A final rule is anticipated in 2024. The ultimate impact of this proposal cannot be determined at this time; however, it may result in significant compliance costs.

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In 2021, Alabama Power submitted its notice of planned participation (NOPP) to the Alabama Department of Environmental Management (ADEM), which included plans to retire Plant Barry Unit 5. Alabama Power subsequently indicated that it expected to retire Plant Barry Unit 5 in late 2023 or early 2024 subject to certain operating conditions. Alabama Power has continued to evaluate operating conditions relevant to the expected retirement of Plant Barry Unit 5 in late 2023 or early 2024 and now expects the unit to remain in service beyond these periods. Alabama Power plans to retire the unit on or before the NOPP compliance date of December 31, 2028. The ultimate impact of this matter cannot be determined at this time.

Coal Combustion Residuals

On May 18, 2023, the EPA published a proposal to establish two new categories of federally regulated CCR, legacy surface impoundments and CCR management units (CCRMUs). The EPA is proposing to define a legacy surface impoundment as a CCR surface impoundment that no longer receives CCR but contained both CCR and liquids on or after October 19, 2015 and that is located at an inactive electric generating facility. The EPA is proposing that owners and operators of legacy surface impoundments comply with all of the existing CCR Rule requirements with the exception of location restrictions and liner demonstrations. The proposal establishes accelerated compliance deadlines for legacy surface impoundments to meet regulatory requirements, including a requirement to initiate closure within 12 months after the effective date of the final rule. The EPA is also proposing to define CCRMUs as any area of land on which any non-containerized accumulation of CCR is received, placed, or otherwise managed at any time, that is not a CCR unit, including inactive CCR landfills and CCR units that closed prior to October 17, 2015. The EPA's proposal would require evaluations to be completed at both active facilities and inactive facilities with one or more legacy surface impoundment. CCRMUs must comply with the CCR Rule's provisions for groundwater monitoring, corrective action, closure, and post-closure activities. A final rule is anticipated in 2024. The ultimate impact of this proposal cannot be determined at this time; however, it may result in significant compliance costs.

On August 14, 2023, the EPA published a proposal to deny the ADEM's CCR permit program application. Alabama Power's permits to close its CCR facilities remain valid under state law. In the absence of an EPA-approved state permit program, CCR facilities in Alabama will remain subject to both the federal and state CCR rules.

Based on requirements for closure and monitoring of landfills and ash ponds pursuant to the CCR Rule and applicable state rules, the traditional electric operating companies have periodically updated, and expect to continue periodically updating, their related cost estimates and ARO liabilities for each CCR unit as additional information related to closure methodologies, schedules, and/or costs becomes available. Some of these updates have been, and future updates may be, material. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, results of operations, cash flows, and financial condition for Southern Company and the traditional electric operating companies could be materially impacted. See Note 6 to the financial statements in Item 8 of the Form 10-K and Notes (A) and (C) to the Condensed Financial Statements under "Asset Retirement Obligations" and "General Litigation Matters – Alabama Power," respectively, herein for additional information.

Greenhouse Gases

On May 23, 2023, the EPA published the proposed GHG standards and state plan guidelines for fossil fuel-fired power plants. The proposal includes GHG limits for both new and existing units based on technologies such as carbon capture and sequestration, low-GHG hydrogen co-firing, and natural gas co-firing. The proposed standards for new combustion turbines include subcategories for different operational uses including peaking, intermediate, and base load. Compliance with new source standards, once finalized, begins when the unit comes online. The EPA proposes a phased approach for intermediate and base load units that increases in stringency over time. The proposed state plan guidelines for existing units include subcategories based on unit type, retirement date, size, and capacity factor. The EPA is proposing a 24-month state plan submission deadline for the existing unit implementation and proposes to potentially allow some limited form of trading and averaging for the state plans. Existing source compliance is proposed to begin as early as January 1, 2030, depending on the unit type and

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subcategory. The EPA also proposes to simultaneously repeal the Affordable Clean Energy rule. A final rule is anticipated in 2024. The ultimate impact of this proposal cannot be determined at this time; however, it may result in significant compliance costs.

Regulatory Matters

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

Alabama Power

On July 14, 2023, Alabama Power issued a request for proposals of between 100 MWs and 1,200 MWs of capacity beginning no later than December 1, 2028, with consideration for commencement as early as 2025. Any purchases will depend upon the cost competitiveness of the respective offers, as well as other options available to Alabama Power, and would ultimately require approval by the Alabama PSC. 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 strategy continues to include developing and constructing new electric generating facilities, expanding and improving the electric transmission and electric and natural gas distribution systems, and undertaking projects to comply with environmental laws and regulations.

For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. The largest construction project currently underway in the Southern Company system is Plant Vogtle Unit 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 – Certificates of Convenience and Necessity" for information regarding Alabama Power's construction of Plant Barry Unit 8, which was placed in service on November 1, 2023.

See Note (K) to the Condensed Financial Statements under "Southern Power" herein for information relating to Southern Power's construction of renewable energy facilities.

Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and resiliency, reduce emissions, and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information on Southern Company Gas' construction program.

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

Income Tax Matters

In June 2023, the Internal Revenue Service issued temporary regulations related to the transferability of tax credits. Southern Company and certain subsidiaries are considering the sale of tax credits that are eligible to be transferred. See Note (G) to the Condensed Financial Statements herein for additional information. Additionally, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" in Item 7 of the Form 10-K for information regarding the Inflation Reduction Act's expansion of the availability of federal ITCs and PTCs.

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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.

Traditional Electric Operating Companies

See BUSINESS – "The Southern Company System – Traditional Electric Operating Companies" in Item 1 of the Form 10-K for information regarding the Southeast Energy Exchange Market (SEEM). On July 14, 2023, the U.S. Court of Appeals for the District of Columbia Circuit vacated the FERC's orders related to SEEM and remanded the proceeding to the FERC. 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)

On August 30, 2023, as provided for in the December 2017 Georgia PSC approval of the seventeenth VCM report, Georgia Power filed with the Georgia PSC an application to adjust rates to include reasonable and prudent Plant Vogtle Units 3 and 4 costs (Application). The Application provides the necessary support to justify the reasonableness, prudence, and recovery of $8.826 billion in total construction and capital costs, $1.07 billion in associated retail rate base items, and the operating costs related to the full operation and output of Plant Vogtle Units 3 and 4. Also on August 30, 2023, the staff of the Georgia PSC filed a stipulated agreement (Prudency Stipulation) among Georgia Power, the staff of the Georgia PSC, and certain intervenors. If the Prudency Stipulation is approved, Georgia Power will recover $7.562 billion in total construction and capital costs and associated retail rate base items of $1.02 billion, which includes AFUDC financing costs above $4.418 billion (the Georgia PSC-certified amount) up to $7.562 billion. Georgia Power expects the Georgia PSC to render a final decision on these matters on December 19, 2023.

As of September 30, 2023, Georgia Power revised its total project capital cost forecast to $10.8 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). This forecast includes construction contingency of $17 million and is based on the actual in-service date of July 2023 for Unit 3 and a projected in-service date of March 2024 for Unit 4.

On October 5, 2023 and October 17, 2023, Georgia Power reached agreements with OPC and Dalton, respectively, to resolve its respective dispute with each of OPC and Dalton regarding the proper interpretation of the cost-sharing and tender provisions of the joint ownership agreements relating to the Global Amendments. Under the terms of the agreements with OPC and Dalton, among other items, (i) each of OPC and Dalton retracted its exercise of the tender

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option and will retain its full ownership interest in Plant Vogtle Units 3 and 4, (ii) Georgia Power made payments immediately after execution of the agreements of $308 million and $17 million to OPC and Dalton, respectively, representing payment for a portion of each of OPC's and Dalton's costs of construction for Plant Vogtle Units 3 and 4 previously incurred, (iii) Georgia Power will pay a portion of each of OPC's and Dalton's further costs of construction for Plant Vogtle Units 3 and 4 as such costs are incurred and with no further adjustment for force majeure costs, which payments will be in an aggregate amount of approximately $105 million and $6 million for OPC and Dalton, respectively, based on the current project capital cost forecast, and (iv) Georgia Power will pay 66% of each of OPC's and Dalton's costs of construction with respect to any amounts above the current project capital cost forecast, with no further adjustment for force majeure costs.

Georgia Power recorded a pre-tax charge to income in the third quarter 2023 of approximately $160 million ($120 million after tax) associated with the cost-sharing provisions of the Global Amendments, including the settlements with OPC and Dalton, which is included in the total project capital cost forecast and will not be recovered from retail customers.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the in-service date beyond the March 2024 for Unit 4, including the current level of cost sharing described in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein, is estimated to result in additional base capital costs for Georgia Power of up to $25 million per month, as well as the related AFUDC and any additional related construction, support resources, or testing costs. See Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" and Note (B) to the Condensed Financial Statements herein under "Georgia Power – Plant Vogtle Units 3 and 4 Prudency Proceeding" and " – Nuclear Construction" for additional information.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" in Item 7 of the Form 10-K for additional information. The financial condition of each Registrant remained stable at September 30, 2023. The Registrants intend to continue to monitor their access to short-term and long-term capital markets as well as their bank credit arrangements to meet future capital and liquidity needs. See "Cash Requirements," "Sources of Capital," and "Financing Activities" herein for additional information.

At the end of the third quarter 2023, the market price of Southern Company's common stock was $64.72 per share (based on the closing price as reported on the NYSE) and the book value was $28.77 per share, representing a market-to-book ratio of 225%, compared to $71.41, $27.93, and 256%, respectively, at the end of 2022. Southern Company's common stock dividend for the third quarter 2023 was $0.70 per share compared to $0.68 per share in the third quarter 2022.

Cash Requirements

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

The Registrants' significant cash requirements include estimated capital expenditures associated with their construction programs and, for the traditional electric operating companies, operating cash flows related to fuel cost under recovery. The fuel cost under recovery balances are primarily the result of higher than forecasted prices for natural gas and purchased power. See Note (B) to the Condensed Financial Statements herein under "Georgia Power – Fuel Cost Recovery" for additional information.

The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel

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sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation and/or regulation; the cost, availability, and efficiency of construction labor, equipment, and materials; project scope and design changes; abnormal weather; delays in construction due to judicial or regulatory action; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures and AROs will be fully recovered. Additionally, expenditures associated with Southern Power's planned acquisitions may vary due to market opportunities and the execution of its growth strategy.

The construction program of Georgia Power includes Plant Vogtle Unit 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.

See Note (B) to the Condensed Financial Statements under "Georgia Power – Integrated Resource Plans" herein for information regarding Georgia Power's 2023 IRP Update, which includes requests that, if approved, would result in incremental cash requirements for capital expenditures and PPAs.

Southern Power's construction program includes the South Cheyenne and Millers Branch solar projects. The remaining aggregate construction costs for these projects are expected to be between $300 million and $375 million. The ultimate outcome of this matter cannot be determined at this time. See Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.

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, 2022.

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, hybrid, and/or equity issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings.

The Subsidiary Registrants plan to obtain the funds to meet their future capital needs from sources similar to those they used in the past, which were primarily from operating cash flows, external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. Operating cash flows provide a substantial portion of the Registrants' cash needs. Georgia Power intends to utilize a mix of senior note issuances, short-term floating rate bank loans, and commercial paper issuances to continue funding operating cash flows related to fuel cost under recovery.

The amount, type, and timing of any financings in 2023, as well as in subsequent years, will be contingent on investment opportunities and the Registrants' capital requirements and will depend upon prevailing market conditions, regulatory approvals (for certain of the Subsidiary Registrants), and other factors. See "Cash Requirements" and "Financing Activities" herein for additional information.

Southern Power utilizes tax equity partnerships as one of its financing sources, where the tax partner takes significantly all of the federal tax benefits. These tax equity partnerships are consolidated in Southern Power's financial statements and are accounted for using HLBV methodology to allocate partnership gains and losses. During the nine months ended September 30, 2023, Southern Power obtained tax equity funding for existing tax equity partnerships totaling $21 million. See Note 1 to the financial statements under "General" in Item 8 of the Form 10-K for additional information.

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By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. At September 30, 2023, the amount of subsidiary retained earnings restricted to dividend totaled $1.6 billion. This restriction did not impact Southern Company Gas' ability to meet its cash obligations, nor does management expect such restriction to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.

Certain Registrants' current liabilities frequently exceed their current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. The Registrants generally plan to refinance long-term debt as it matures. The following table shows the amount by which current liabilities exceeded current assets at September 30, 2023 for the applicable Registrants:

At September 30, 2023	Southern Company		Georgia Power		Mississippi Power		Southern Company Gas
	(in millions)
Current liabilities in excess of current assets	$	2,126	$	1,690	$	239	$	176

The Registrants believe the need for working capital can be adequately met by utilizing operating cash flows, as well as commercial paper, lines of credit, and short-term bank notes, as market conditions permit. In addition, under certain circumstances, the Subsidiary Registrants may utilize equity contributions and/or loans from Southern Company.

Bank Credit Arrangements

At September 30, 2023, the Registrants' unused committed credit arrangements with banks were as follows:

At September 30, 2023	Southern Company parent		Alabama Power		Georgia Power		Mississippi Power		Southern  Power(a)		Southern Company Gas(b)		SEGCO		Southern Company
	(in millions)
Unused committed credit	$	1,998	$	1,350	$	1,726	$	275	$	589	$	1,598	$	30	$	7,566

(a)At September 30, 2023, Southern Power also had two continuing letters of credit facilities for standby letters of credit, of which $25 million was unused. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.

(b)Includes $798 million and $800 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 certain revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. At September 30, 2023, outstanding variable rate demand revenue bonds of the traditional electric operating companies with allocated liquidity support totaled approximately $1.7 billion (comprised of approximately $818 million at Alabama Power, $819 million at Georgia Power, and $69 million at Mississippi Power). In addition, at September 30, 2023, Alabama Power and Georgia Power had approximately $120 million and $325 million, respectively, of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months. The variable rate demand revenue bonds and fixed rate revenue bonds required to be remarketed within the next 12 months are classified as long-term debt on the balance sheets as a result of available long-term committed credit.

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 September 30, 2023				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	$	1,726	6.0	%	$	2,069	5.9	%	$	2,615
Alabama Power	—		—		2		5.3		25
Georgia Power	1,250		6.2		1,534		6.0		1,910
Mississippi Power	20		5.5		41		5.5		76
Southern Power	359		5.6		88		5.9		359
Southern Company Gas:
Southern Company Gas Capital	$	75	5.5	%	$	211	5.5	%	$	440

(*)Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2023.

Analysis of Cash Flows

Net cash flows provided from (used for) operating, investing, and financing activities for the nine months ended September 30, 2023 and 2022 are presented in the following table:

Net cash provided from (used for):	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Nine Months Ended September 30, 2023
Operating activities	$	5,740	$	1,522	$	1,969	$	260	$	799	$	1,644
Investing activities	(6,721)		(1,546)		(3,376)		(280)		(224)		(1,226)
Financing activities	834		66		1,183		(12)		(451)		(102)
Nine Months Ended September 30, 2022
Operating activities	$	5,017	$	1,072	$	1,482	$	279	$	827	$	1,532
Investing activities	(5,952)		(1,641)		(2,653)		(219)		(128)		(1,239)
Financing activities	1,119		967		1,171		(72)		(603)		(313)

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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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

Southern Company

Net cash provided from operating activities increased $0.7 billion for the nine months ended September 30, 2023 as compared to the corresponding period in 2022 primarily due to increased fuel cost recovery and the timing of customer receivable collections, partially offset by the timing of vendor payments.

The net cash used for investing activities for the nine months ended September 30, 2023 was primarily related to the Subsidiary Registrants' construction programs.

The net cash provided from financing activities for the nine months ended September 30, 2023 was primarily related to net issuances of long-term debt, partially offset by common stock dividend payments, net repayments of short-term bank loans, and a reduction in commercial paper borrowings.

Alabama Power

Net cash provided from operating activities increased $450 million for the nine months ended September 30, 2023 as compared to the corresponding period in 2022 primarily due to an increase in fuel cost recovery and the timing of customer receivable collections, partially offset by the timing of vendor payments and fuel stock purchases.

The net cash used for investing activities for the nine months ended September 30, 2023 was primarily related to gross property additions, including approximately $66 million related to the construction of Plant Barry Unit 8. See Note (B) to the Condensed Financial Statements under "Alabama Power" herein for additional information.

The net cash provided from financing activities for the nine months ended September 30, 2023 was primarily related to capital contributions from Southern Company and issuances of revenue bonds and senior notes, largely offset by common stock dividend payments.

Georgia Power

Net cash provided from operating activities increased $487 million for the nine months ended September 30, 2023 as compared to the corresponding period in 2022 primarily due to increased fuel cost recovery, partially offset by the timing of vendor payments.

The net cash used for investing activities for the nine months ended September 30, 2023 was primarily related to gross property additions, including a total of approximately $590 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 Plant Vogtle Units 3 and 4.

The net cash provided from financing activities for the nine months ended September 30, 2023 was primarily related to capital contributions from Southern Company, net issuances of senior notes, and reofferings of pollution control revenue bonds which were previously held by Georgia Power, partially offset by common stock dividend payments and a net decrease in short-term borrowings.

Mississippi Power

Net cash provided from operating activities decreased $19 million for the nine months ended September 30, 2023 as compared to the corresponding period in 2022 primarily due to the timing of vendor payments, partially offset by the timing of customer receivable collections.

The net cash used for investing activities for the nine months ended September 30, 2023 was primarily related to gross property additions.

The net cash used for financing activities for the nine months ended September 30, 2023 was primarily related to common stock dividend payments, partially offset by the issuance of senior notes.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

Southern Power

Net cash provided from operating activities decreased $28 million for the nine months ended September 30, 2023 as compared to the corresponding period in 2022 primarily due to the timing of vendor payments and a change in the utilization of tax credits, partially offset by the timing of customer receivable collections.

The net cash used for investing activities for the nine months ended September 30, 2023 was primarily related to the acquisitions of the South Cheyenne and Millers Branch solar facilities and ongoing construction activities, partially offset by proceeds from the sale of equity investments. See Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.

The net cash used for financing activities for the nine months ended September 30, 2023 was primarily related to repayment of senior notes at maturity, common stock dividend payments, and net distributions to noncontrolling interests, partially offset by net proceeds from short-term debt.

Southern Company Gas

Net cash provided from operating activities increased $112 million for the nine months ended September 30, 2023 as compared to the corresponding period in 2022 primarily due to the timing of customer receivable collections, partially offset by the timing of vendor payments.

The net cash used for investing activities for the nine months ended September 30, 2023 was primarily related to construction of transportation and distribution assets recovered through base rates and infrastructure investment recovered through replacement programs at gas distribution operations.

The net cash used for financing activities for the nine months ended September 30, 2023 was primarily related to repayment of short-term borrowings and common stock dividend payments, partially offset by capital contributions from Southern Company and proceeds from other long-term debt.

Significant Balance Sheet Changes

Southern Company

Significant balance sheet changes for the nine months ended September 30, 2023 included:

•an increase of $4.1 billion in long-term debt (including securities due within one year) related to new issuances;

•an increase of $3.7 billion in total property, plant, and equipment primarily related to the Subsidiary Registrants' construction programs;

•a decrease of $0.9 billion in notes payable due to the repayment of short-term bank loans and a reduction in commercial paper borrowings;

•an increase of $0.8 billion in total stockholders' equity primarily related to net income, partially offset by common stock dividend payments;

•an increase of $0.7 billion in accumulated deferred income taxes primarily related to the expected utilization of ITCs in 2023, as well as an increase in property-related timing differences;

•a decrease of $0.6 billion in accounts payable primarily related to the timing of vendor payments; and

•a decrease of $0.5 billion in unbilled revenues as a result of seasonality.

See "Financing Activities" herein and Notes (B) and (G) 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)

Alabama Power

Significant balance sheet changes for the nine months ended September 30, 2023 included:

•an increase of $664 million in common stockholder's equity primarily due to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company;

•an increase of $553 million in long-term debt (including securities due within one year) primarily due to the issuance of revenue bonds and senior notes;

•an increase of $426 million in total property, plant, and equipment primarily related to the construction of Plant Barry Unit 8 and transmission and distribution facilities;

•a decrease of $401 million in other regulatory assets, deferred primarily due to a decrease in the under recovered fuel clause balance;

•a decrease of $299 million in deferred credits related to income taxes primarily due to the amortization of accumulated deferred income taxes; and

•a decrease of $264 million in other accounts payable primarily due to the timing of vendor payments.

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

Georgia Power

Significant balance sheet changes for the nine months ended September 30, 2023 included:

•an increase of $2.5 billion in total property, plant, and equipment primarily related to the construction of generation, transmission, and distribution facilities, including $944 million for Plant Vogtle Units 3 and 4;

•an increase of $2.0 billion in common stockholder's equity primarily due to capital contributions from Southern Company and net income, partially offset by dividends paid to Southern Company;

•an increase of $1.1 billion in long-term debt (including securities due within one year) primarily due to net issuances of senior notes;

•an increase of $556 million in other accounts payable primarily due to the timing of vendor payments;

•a decrease of $350 million in notes payable primarily due to repayments of short-term bank debt; and

•an increase of $321 million in customer accounts receivable, net primarily due to the timing of collections.

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

Mississippi Power

Significant balance sheet changes for the nine months ended September 30, 2023 included:

•an increase of $120 million in total property, plant, and equipment primarily related to the construction of transmission and distribution facilities;

•an increase of $99 million in long-term debt (including securities due within one year) primarily due to issuances of senior notes;

•a decrease of $45 million in other accounts payable due to the timing of vendor payments;

•decreases of $44 million in affiliated receivables and $42 million in affiliated accounts payable primarily due to fluctuations in affiliate sales/purchases and the timing of payments; and

•an increase of $43 million in common stockholder's equity related to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company.

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

Southern Power

Significant balance sheet changes for the nine months ended September 30, 2023 included:

•increases of $340 million in accumulated deferred income tax liabilities and $125 million in prepaid income taxes primarily related to the expected utilization of ITCs in 2023;

•a decrease of $292 million in long-term debt (including securities due within one year) primarily related to the repayment of senior notes at maturity;

•a decrease of $137 million in total property, plant, and equipment due to the continued depreciation of assets, partially offset by an increase in construction work in progress, primarily related to the acquisition of the South Cheyenne and Millers Branch solar facilities;

•an increase of $134 million in notes payable primarily due to net issuances of commercial paper; and

•an increase of $105 million in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Southern Power" herein.

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

Southern Company Gas

Significant balance sheet changes for the nine months ended September 30, 2023 included:

•an increase of $807 million in total property, plant, and equipment primarily related to the construction of transportation and distribution assets and additional infrastructure investment;

•a decrease of $777 million in total accounts receivable primarily related to decreases of $379 million in unbilled revenues and $374 million in customer accounts receivable as a result of seasonality;

•a decrease of $693 million in notes payable due to a reduction in commercial paper borrowings and the repayment of short-term bank loans;

•an increase of $615 million in long-term debt due to issuances by Southern Company Gas Capital and Nicor Gas;

•an increase of $436 million in common stockholder's equity related to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company;

•a decrease of $327 million in other accounts payable due to seasonality and the timing of vendor payments; and

•an increase of $316 million in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Southern Company Gas" herein.

See "Financing Activities – Southern Company Gas" herein and Note (B) 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)

Financing Activities

The following table outlines the Registrants' long-term debt financing activities for the first nine months of 2023:

	Issuances and Reofferings						Maturities and Redemptions
Company	Senior Notes		Revenue Bonds		Other Long- Term Debt		Senior Notes		Other Long- Term Debt(a)
	(in millions)
Southern Company parent	$	4,525	$	—	$	—	$	1,850	$	550
Alabama Power	200		326		28		—		1
Georgia Power	1,750		229		—		800		72
Mississippi Power	100		—		—		—		—
Southern Power	—		—		—		290		—
Southern Company Gas	500		—		154		—		—
Other	—		—		—		—		6
Elimination(b)	—		—		—		—		(3)
Southern Company	$	7,075	$	555	$	182	$	2,940	$	626

(a)Includes reductions in finance lease obligations resulting from cash payments under finance leases and, for Georgia Power, principal amortization payments totaling $64 million for FFB borrowings. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information.

(b)Represents reductions in affiliate finance lease obligations at Georgia Power, which are eliminated in Southern Company's consolidated financial statements.

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

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

Southern Company

During the first nine months of 2023, Southern Company issued approximately 1.9 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $26 million.

In January 2023, Southern Company redeemed all $550 million aggregate principal amount of its Series 2016B Junior Subordinated Notes due March 15, 2057.

In February 2023, Southern Company issued $1.5 billion aggregate principal amount of its Series 2023A 3.875% Convertible Senior Notes due December 15, 2025 (Series 2023A Convertible Senior Notes) in a private offering. In March 2023, Southern Company issued an additional $225 million aggregate principal amount of the Series 2023A Convertible Senior Notes upon the exercise by the initial purchasers of their over-allotment option. See Note (F) to the Condensed Financial Statements under "Convertible Senior Notes" herein for additional information.

In May 2023, Southern Company repaid at maturity $600 million aggregate principal amount of its 2021C Floating Rate Senior Notes.

Also in May 2023, Southern Company issued $750 million aggregate principal amount of Series 2023B 4.85% Senior Notes due June 15, 2028 and $750 million aggregate principal amount of Series 2023C 5.20% Senior Notes due June 15, 2033.

In July 2023, Southern Company repaid at maturity $1.25 billion aggregate principal amount of its 2.95% Senior Notes.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

In September 2023, Southern Company issued $600 million aggregate principal amount of Series 2023D 5.50% Senior Notes due March 15, 2029 and $700 million aggregate principal amount of Series 2023E 5.70% Senior Notes due March 15, 2034.

Alabama Power

During the first nine months of 2023, a subsidiary of Alabama Power borrowed $19 million under a $39 million long-term floating rate bank loan entered into in December 2022 with a maturity date of December 12, 2029.

In May 2023, Alabama Power issued $200 million aggregate principal amount of Series 2023A Floating Rate Senior Notes due May 15, 2073.

In August 2023, the Walker County Economic and Industrial Development Authority issued for the benefit of Alabama Power $228 million aggregate principal amount of Solid Waste Disposal Revenue Bonds (Alabama Power Company Plant Gorgas Project), First Series 2023 ($140 million aggregate principal amount) and Second Series 2023 ($88 million aggregate principal amount) due August 1, 2063. The proceeds from the revenue bonds are being used to finance certain solid waste disposal facilities at Plant Gorgas.

Also in August 2023, the Industrial Development Board of the Town of West Jefferson issued for the benefit of Alabama Power $98 million aggregate principal amount of Solid Waste Disposal Revenue Bonds (Alabama Power Company Plant Miller Project), Series 2023 due August 1, 2063. The proceeds from the revenue bonds are being used to finance certain solid waste disposal facilities at Plant Miller.

In September 2023, a subsidiary of Alabama Power assumed two fixed rate bank loans totaling $9 million, both maturing on August 30, 2028.

Georgia Power

In March 2023, Georgia Power reoffered to the public the following pollution control revenue bonds that previously had been purchased and were held by Georgia Power at December 31, 2022:

•approximately $28 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), Second Series 2006;

•approximately $89 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), Second Series 2009;

•approximately $49 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), First Series 2012;

•approximately $18 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), First Series 2013; and

•$46 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1996.

Also in March 2023, Georgia Power borrowed $100 million pursuant to a short-term uncommitted bank credit arrangement bearing interest at a mutually agreed upon rate and payable on demand. In April 2023, Georgia Power borrowed an additional $150 million under the arrangement. In May 2023, Georgia Power repaid the aggregate $250 million outstanding.

Also in March 2023, Georgia Power repaid at maturity a $200 million short-term floating rate bank loan entered into in March 2022.

In April 2023, Georgia Power repaid at maturity $100 million aggregate principal amount of its Series N 5.750% Senior Notes.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS (Continued)

Also in April 2023, Georgia Power repaid at maturity a $200 million short-term floating rate bank loan entered into in April 2022.

In May 2023, Georgia Power issued $750 million aggregate principal amount of Series 2023A 4.65% Senior Notes due May 16, 2028 and $1.0 billion aggregate principal amount of Series 2023B 4.95% Senior Notes due May 17, 2033.

In July 2023, Georgia Power repaid at maturity $700 million aggregate principal amount of its Series 2020A 2.10% Senior Notes.

Mississippi Power

In March 2023, Mississippi Power borrowed $50 million of short-term debt pursuant to its $125 million revolving credit arrangement, which it repaid in June 2023.

In June 2023, Mississippi Power issued in a private placement $65 million aggregate principal amount of Series 2023A 5.64% Senior Notes due July 15, 2026 and $35 million aggregate principal amount of Series 2023B 5.63% Senior Notes due July 15, 2033.

Southern Power

In January 2023, Southern Power borrowed $100 million pursuant to a short-term uncommitted bank credit arrangement bearing interest at a mutually agreed upon rate and payable on demand. During the second quarter 2023, Southern Power made net repayments of $50 million of the $100 million borrowed. Subsequent to September 30, 2023, Southern Power borrowed the remaining $50 million under the arrangement.

In September 2023, Southern Power repaid at maturity $290 million aggregate principal amount of its Series 2016C 2.75% Senior Notes.

Southern Company Gas

In February 2023, Nicor Gas repaid its $150 million and $50 million short-term floating rate bank loans entered into in February 2022 and March 2022, respectively.

During the first nine months of 2023, Southern Company Gas received cash advances totaling $29 million under a long-term financing agreement related to a construction contract.

In July 2023, Nicor Gas issued in a private placement $50 million aggregate principal amount of 5.28% Series First Mortgage Bonds due July 31, 2030 and $75 million aggregate principal amount of 5.43% Series First Mortgage Bonds due July 31, 2035. Subsequent to September 30, 2023, pursuant to the same agreement, Nicor Gas issued in a private placement $75 million aggregate principal amount of 5.67% Series First Mortgage Bonds due October 31, 2053 and $75 million aggregate principal amount of 5.77% Series First Mortgage Bonds due October 31, 2063.

In September 2023, Southern Company Gas Capital issued $500 million aggregate principal amount of Series 2023A 5.75% Senior Notes due September 15, 2033, guaranteed by Southern Company Gas.

Subsequent to September 30, 2023, Southern Company Gas Capital repaid at maturity $350 million aggregate principal amount of its 2.450% Senior Notes.

Credit Rating Risk

At September 30, 2023, 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, services 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 September 30, 2023 were as follows:

Credit Ratings	Southern Company(*)		Alabama Power		Georgia Power		Mississippi Power		Southern Power(*)		Southern Company Gas
	(in millions)
At BBB and/or Baa2	$	33	$	1	$	—	$	—	$	32	$	—
At BBB- and/or Baa3	415		2		60		1		353		—
At BB+ and/or Ba1 or below	2,084		411		939		315		1,275		16

(*)Southern Power has PPAs that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPAs require credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade. Southern Power had $106 million of cash collateral posted related to PPA requirements at September 30, 2023.

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

On August 2, 2023, S&P revised its credit rating outlook for Southern Company and its subsidiaries to positive from stable.

On September 26, 2023, Moody's upgraded Mississippi Power's senior unsecured long-term debt rating to A3 from Baa1 and revised its rating outlook to stable from positive.

Also on September 26, 2023, Moody's revised its ratings outlooks for Southern Company and Georgia Power to positive from stable.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk.

During the nine months ended September 30, 2023, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' disclosures about market risk. For an in-depth discussion of each Registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" in Item 7 of the Form 10-K and Note 1 to the financial statements under "Financial Instruments" and Notes 13 and 14 to the financial statements in Item 8 of the Form 10-K, as well as Notes (I) and (J) to the Condensed Financial Statements herein.

Item 4. Controls and Procedures.

(a)Evaluation of disclosure controls and procedures.

As of the end of the period covered by this Quarterly Report on Form 10-Q, Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas conducted separate evaluations under the supervision and with the participation of each company's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under 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 control over financial reporting.

There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the third quarter 2023 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 5. Other Information.

There were no adoptions, modifications, or terminations of "Rule 10b5-1 trading arrangements" or "non-Rule 10b5-1 trading arrangements," as defined in Item 408(a) of Regulation S-K, during the three months ended September 30, 2023 by the Registrants' directors and "officers," as defined in Rule 16a-1(f) under the Securities Exchange Act of 1934, as amended.

Item 6. Exhibits.

The exhibits below with an asterisk (*) preceding the exhibit number are filed herewith. The remaining exhibits have previously been filed with the SEC and are incorporated herein by reference. The exhibits marked with a pound sign (#) are management contracts or compensatory plans or arrangements.

	(3) Articles of Incorporation and By-Laws
	Alabama Power
*	(b)1	-	Amended and Restated By-laws of Alabama Power effective October 16, 2023, and as presently in effect.
	(4) Instruments Describing Rights of Security Holders, Including Indentures
	Southern Company
	(a)1	-	Thirtieth Supplemental Indenture to Senior Note Indenture dated as of September 8, 2023, providing for the issuance of the Series 2023D 5.50% Senior Notes due March 15, 2029. (Designated in Form 8-K dated September 5, 2023, File No. 1-3526, as Exhibit 4.4(a).)
	(a)2	-	Thirty-First Supplemental Indenture to Senior Note Indenture dated as of September 8, 2023, providing for the issuance of the Series 2023E 5.70% Senior Notes due March 15, 2034. (Designated in Form 8-K dated September 5, 2023, File No. 1-3526, as Exhibit 4.4(b).)
	Southern Company Gas
	(f)1	-	Southern Company Gas Capital Corporation's Series 2023A 5.75% Senior Notes due September 15, 2033, Form of Note. (Designated in Form 8-K dated September 11, 2023. File No. 1-14174 as Exhibit 4.1.)
	(f)2	-	Southern Company Gas' Guarantee related to the Series 2023A 5.75% Senior Notes due September 15, 2023, Form of Guarantee. (Designated in Form 8-K dated September 11, 2023. File No. 1-14174 as Exhibit 4.3.)
*	(f)3	-	Supplemental Indenture dated as of July 11, 2023 of Northern Illinois Gas Company to U.S. Bank Trust Company National Association under Indenture dated as of January 1, 1954.

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	(24) Power of Attorney and Resolutions
	Southern Company
	(a)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2022, File No. 1-3526 as Exhibit 24(a)1.)
	(a)2	-	Power of Attorney of Christopher C. Womack. (Designated in the Form 10-Q for the quarter ended June 30, 2023, File No. 1-3526 as Exhibit 24(a)2.)
	Alabama Power
	(b)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2022, File No. 1-3164 as Exhibit 24(b)1.)
	(b)2	-	Power of Attorney of Moses H. Feagin. (Designated in the Form 10-Q for the quarter ended March 31, 2023, File No. 1-3164 as Exhibit 24(b)2.)
	Georgia Power
	(c)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2022, File No. 1-6468 as Exhibit 24(c)1.)
	(c)2	-	Power of Attorney of Kimberly S. Greene. (Designated in the Form 10-Q for the quarter ended March 31, 2023, File No. 1-6468 as Exhibit 24(c)2.)
	Mississippi Power
	(d)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2022, File No. 001-11229 as Exhibit 24(d)1.)
	Southern Power
	(e)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2022, 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, 2022, File No. 1-14174 as Exhibit 24(f)1.)
	(f)2	-	Power of Attorney of James Y. Kerr II. (Designated in the Form 10-Q for the quarter ended March 31, 2023, 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.
	(101) Interactive Data Files
*	INS	-	Inline 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	-	Inline XBRL Taxonomy Extension Schema Document
*	CAL	-	Inline XBRL Taxonomy Calculation Linkbase Document
*	DEF	-	Inline XBRL Definition Linkbase Document
*	LAB	-	Inline XBRL Taxonomy Label Linkbase Document
*	PRE	-	Inline XBRL Taxonomy Presentation Linkbase Document
	(104) Cover Page Interactive Data File
*			Formatted as inline XBRL with applicable taxonomy extension information contained in Exhibits 101.

163

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

Date: November 1, 2023

164

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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	J. Jeffrey Peoples
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	Moses H. Feagin
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: November 1, 2023

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

Date: November 1, 2023

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MISSISSIPPI POWER COMPANY

SIGNATURES

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

	MISSISSIPPI POWER COMPANY
By	Anthony L. Wilson
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	Matthew P. Grice
	Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: November 1, 2023

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SOUTHERN POWER COMPANY

SIGNATURES

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

	SOUTHERN POWER COMPANY
By	Christopher Cummiskey
	Chairman and Chief Executive Officer
	(Principal Executive Officer)
By	Gary Kerr
	Senior Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: November 1, 2023

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SOUTHERN COMPANY GAS

SIGNATURES

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

	SOUTHERN COMPANY GAS
By	James Y. Kerr II
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	Grace A. Kolvereid
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: November 1, 2023

169

EX-3.B1

Exhibit 3(b)1

ALABAMA POWER COMPANY

AMENDED AND RESTATED

BY-LAWS

________

ARTICLE I

NAME, DURATION, PURPOSE AND LOCATION OF CORPORATION

Section 1. The name of this corporation is ALABAMA POWER COMPANY. Its duration is perpetual. Its purposes are expressed in the original certificate of incorporation of Alabama Power Company and the additions thereto and the amendments and changes which have been or which may be made therein from time to time; in the certificate of incorporation and the several amendments thereto of the corporations which have been or may hereafter be merged into or consolidated with this corporation; and the joint agreements of merger or consolidation heretofore made or which may hereafter be made with this corporation (the “Charter”). Its principal office and place of business shall be in Birmingham, Jefferson County, Alabama; but the corporation may also have offices in other counties, cities and towns in the State of Alabama, and in the City of New York, and in such other places beyond the State of Alabama as the board of directors may from time to time appoint, or the business of the corporation may require.

ARTICLE II

STOCKHOLDERS’ MEETINGS

Place or Manner of Meeting

Section 1. All meetings of the stockholders shall be held, either within or without the State of Alabama, at such place or in such manner as designated in the call for or notice of the meeting.

Annual Meeting

Section 2. The annual meeting of the stockholders shall be held on the fourth Friday in April in each year, if not a legal holiday, and if a legal holiday, then on the following Friday, or on such other date as shall be designated from time to time by the board of directors, when the stockholders entitled to vote shall elect by ballot a board of twenty-five directors to serve until the next annual

meeting of the stockholders and until their successors are elected or chosen and qualified and shall transact such other business as may come before the meeting.

Special Meetings

Section 3. Special meetings of stockholders for any purpose or purposes, unless otherwise prescribed by statute or by the Charter, may be called by (i) the president or the board of directors; (ii) the holders of not less than ten percent (10%) of all the votes entitled to be cast on any issue proposed to be considered at the proposed special meeting or if such holders sign, date and deliver to the corporation's president or secretary one or more written demands for the meeting describing the purpose or purposes for which it is to be held, who shall, within 21 days of the receipt of such demand, cause notice to be given of the meeting to be held within the minimum time following the notice prescribed in Section 4 below; or (iii) the holders of not less than ten percent (10%) of the votes entitled to be cast at the special meeting who signed a demand under clause (ii) above if notice was not given within the 21 days after such demand or the special meeting was not held in accordance with the notice.

Notice of Meeting

Section 4. Written notice of the time and place or manner of holding all meetings shall, unless waived, be given to each stockholder entitled to vote not less than ten or more than sixty days before the date of the meeting, either personally or by mail, to such address as appears on the books of the corporation, unless by statute other or further notice is required, and in this event the required statutory notice shall be given; and, in the case of special meetings, the purpose thereof shall be stated in the notice.

Stockholder List

Section 5. After fixing a record date for a meeting, the officer or entity designated by the corporation having charge of the stock transfer books of the corporation shall prepare an alphabetical list of the names of all its stockholders who are entitled to notice of a stockholders' meeting. The list must be arranged by voting group (and within each voting group by class or series of shares) and show the address of and number of shares held by each stockholder. The stockholders' list must be available for inspection by any stockholder, beginning two business days after notice of the meeting is given for which the list was prepared and continuing through the meeting, at the corporation's principal office. A stockholder, or his or her agent or attorney, is entitled on written demand to inspect and, for a proper purpose, to copy the list, during regular hours and at its expense, during the period it is available for inspection. The corporation shall

make the list available at the meeting, and any stockholder, or his or her agent or attorney, is entitled to inspect the list at any time during the meeting or any adjournment thereof. The stock transfer records of the corporation shall be prima facie evidence as to who are the stockholders entitled to examine the stockholders' list or transfer records or to vote at any meeting of stockholders.

Voting

Section 6. The voting rights of the stockholders shall be set forth in the Charter. Any stockholder entitled to vote may vote in person or by proxy appointed by an instrument in writing subscribed by such stockholder. The proxy holder need not be a stockholder. All elections shall be had and, subject to the provisions of the Charter, all questions decided by a majority vote of the stock voting at the meeting in person or by proxy and entitled to vote thereat.

Quorum

Section 7. Subject to the provisions of the Charter, the holders of a majority of the stock issued and outstanding and entitled to vote at the meeting, present in person or represented by proxy, shall be requisite to constitute a quorum at all meetings of the stockholders for the transaction of business. If, however, such majority shall not be present or represented at any meeting, the stockholders present in person or by proxy and so entitled to vote, shall have power to adjourn the meeting until the requisite amount of stock shall be represented; and at such adjourned meeting any business may be transacted as at the original meeting. Every meeting of the stockholders may be adjourned from time to time until its business is completed.

Action Without a Meeting

Section 8. Any action required or permitted to be taken at any meeting of the stockholders may be taken without a meeting, if the action is taken by all stockholders entitled to vote on the action and evidenced by one or more consents in writing, setting forth the action so taken, signed by all stockholders entitled to vote on the action and delivered to the corporation for inclusion in the minutes for filing with the corporate records. Action taken is effective when the last stockholder signs the consent, unless the consent specifies a different effective date. Such consent shall have the same effect as a unanimous vote.

ARTICLE III

DIRECTORS

Election Of

Section 1. The property and business of the corporation shall be managed by its board of directors, the members of which shall be elected by the stockholders as aforesaid.

Eligibility

Section 2. Directors shall be natural persons of the age of at least twenty-five (25) but need not be residents of the State of Alabama or stockholders of the corporation.

A person being a full time executive employee of the corporation or its parent company or any affiliated company when first elected a director of the corporation (hereinafter sometimes referred to as an “employee-director”) shall not be eligible for election as a director when they cease to be an executive employee; whether by reason of resignation, retirement or other cause. Any employee-director shall resign as a director effective on the date they cease to be an executive employee.

A person not an employee-director shall not be eligible for election or re-election as a director of the corporation(1) after the director's 72nd birthday (2) after permanent separation from the business or professional organization with which the director was primarily associated when elected a director, (3) after other material change in the director's primary occupation or executive position from that which the director pursued or held when elected a director, or (4) after moving the director's principal residence outside the state in which the director was a resident when elected, whichever event first occurs. The application to an individual of any provision of this paragraph may be waived by the board of directors. Any such waiver shall only be effective on a year-to-year basis.

Compensation

Section 3. Directors, other than “employee-directors”, shall receive directors’ fees in the amounts and by the method fixed by the board of directors. All directors shall be reimbursed for actual expenses incurred in connection with their attendance of meetings of the board of directors. Nothing herein contained shall be construed to preclude any director from serving the corporation in any other capacity and receiving compensation therefor.

ARTICLE IV

BOARD OF DIRECTORS

Meetings of the Board

Section 1. The directors may hold their meetings either within or outside the State of Alabama at such places as they may from time to time determine and as authorized by the laws of the State of Alabama.

Annual Meeting

Section 2. The annual meeting of the board of directors shall be held as soon as practicable after the annual meeting of the stockholders, for the purpose of electing officers and for the transaction of such other business as may come before the meeting; at least three days’ notice of the time and place of holding the meeting to be given to each member of the board.

Regular Meetings

Section 3. Regular meetings of the board may be held without notice at such time and place as may from time to time be appointed by the board.

Special Meetings

Section 4. Special meetings of the board may be called by the president, on two days' notice to each director, by delivered letter, by e-mail, or by personal communication either over the telephone or otherwise. Special meetings shall be called by the secretary in like manner and on like notice, on the written request of one-third of the directors for the time being in office.

Quorum

Section 5. At all meetings of the board of directors, a majority of the directors in office shall be necessary and sufficient to constitute a quorum for the transaction of business, except as otherwise provided in Section 15 of this Article IV, and the act of a majority of the directors present at any meeting at which there is a quorum shall be the act of the board of directors, except as may be otherwise specifically permitted or provided by statute or by the Charter or by these by-laws. A director is, unless established to the contrary, presumed present for quorum purposes for the remainder of the meeting at which the director has been present for any purpose. A director who is present at a meeting of the board or any committee of the board when corporate action is taken is deemed to assent to the

action taken place unless (i) the director objects at the beginning of the meeting (or promptly upon arrival) to holding it or transacting business at the meeting or, as to a matter required under the Charter or these by-laws to be included in the notice of the purpose of the meeting, the director objects before action is taken on the matter; (ii) the director's dissent or abstention from action taken is entered in the minutes of the meeting; or (iii) the director delivers written notice of his dissent or abstention to the presiding officer of the meeting before its adjournment or to the corporation immediately after adjournment of the meeting. The right of dissent or abstention is not available to a director who votes in favor of the action taken.

If at any meeting of the board there shall be less than a quorum present, a majority of those present may adjourn the meeting from time to time until a quorum is obtained and no further notice thereof need be given other than by announcement at the meeting which shall be so adjourned.

Meetings by Conference Telephone, etc

Section 6.Meetings of the board of directors and of any committee thereof may be held by means of a conference telephone or other communication by which all directors participating may simultaneously hear each other during the meeting. Participation by such means shall constitute presence in person at any such meeting.

Action Without a Meeting

Section 7. Any action required or permitted to be taken at any meeting of the board of directors or of any committee thereof may be taken without a meeting, if the action is taken by all members of the board and evidenced by one or more consents in writing, setting forth the action so taken, shall be signed by each member of the board or committee, as the case may be, and included in the minutes or filed with the corporate records reflecting the action taken. Action taken is effective when the last director signs the consent, unless the consent specifies a different effective date. Such consent shall have the same effect as a unanimous vote.

General Powers

Section 8. In addition to the powers and authority by these by-laws expressly conferred on it, the board may exercise all such powers of the corporation and do all such lawful acts and things as are not by statute or by the Charter or by these by-laws, directed or required to be exercised or done by the stockholders.

Specific Powers

Section 9. Without prejudice to the general powers conferred by Section 8 of this Article IV, the board of directors shall in addition thereto have the following specific powers, that is to say:

(a) From time to time to make and change rules and regulations not inconsistent with these by-laws for the management of the property and business of the corporation;

(b) To purchase or otherwise acquire for the corporation any property, rights, privileges or franchises which the corporation is authorized to acquire, at such prices or consideration and generally on such terms and conditions as the board shall think fit; and at its discretion to pay for the same either wholly or partly in money, stock or other securities or property of the corporation;

(c) To sell, exchange or otherwise dispose of any property of the corporation less than all, for such price or consideration, and generally on such terms and conditions as the board thinks fit; and at its discretion to accept in whole or partial payment therefor, money, stock or other securities or properties;

(d) To appoint and at the discretion of the board to remove or suspend such officers, agents or employees, permanently or temporarily, as it may think fit, and to determine their duties, and to require bonds in such instances and in such amounts and with such sureties as it may think fit;

(e) To appoint any person or corporation to accept and hold in trust for the corporation any property belonging to the corporation or in which it is interested, or for any other purpose, and to execute all such deeds and instruments and perform such acts as may be requisite in relation to any such trust;

(f) To determine who shall be authorized on behalf of the corporation to sign bills, notes, receipts, acceptances, endorsements, checks, releases, contracts and documents;

(g) To authorize the execution and delivery of notes and other evidences of indebtedness of the corporation for money borrowed or other indebtedness incurred by the corporation; and to authorize the execution, certification,

delivery and sale of the mortgage bonds of the corporation, from time to time upon such terms and conditions as the board may approve; and

(h) To delegate any of the powers of the board in the course of the current business of the corporation, to any standing or special committee or to any officer or agent, or to appoint any persons to be agents of the corporation, with such powers and upon such terms as the board thinks fit.

Record of Proceedings

Section 10. The board of directors shall cause a record of its proceedings and of all board meetings to be properly kept by the secretary of the corporation or by a secretary pro tempore. The records shall be verified by the signature of the person acting as secretary.

Books of Account

Section 11. The board of directors shall cause regular and correct books of account to be kept, and to be balanced and certified by some public accountant at least once every year.

Election of Officers

Section 12. The board of directors at its annual meeting shall elect from their own number a president and shall elect a secretary. In addition, the board of directors at its annual meeting or any other meeting duly held from time to time may elect vice presidents, a treasurer and such other officers as the board shall deem necessary or appropriate.

Books, Papers, Etc.

Section 13. The property and funds, books, correspondence and papers of the corporation, in the possession or control of any officer or agent thereof, shall at all times be subject to the inspection of the board of directors, the executive committee or a committee appointed for the purpose at a general meeting of the holders of the common stock. The minutes, including the resolutions and proceedings of the board, shall be produced when required by the stockholders at any general meeting.

Vacancies

Section 14. If a vacancy occurs on the board: (i) the board of directors may fill the vacancy, except that the directors shall not have the power to fill a vacancy

resulting from an increase in the number of directors or (ii) if the directors remaining in office constitute fewer than a quorum of the board, they may fill the vacancy, if it is one that the directors are authorized to fill, by the affirmative vote of a majority of all the directors remaining in office. A director elected to fill a vacancy shall be elected to serve until the next annual meeting of stockholders. If there are no directors in office, then the stockholders may hold a special meeting to elect directors.

ARTICLE V

EXECUTIVE AND OTHER COMMITTEES

Executive Committee

Section 1. The board of directors may, by resolution adopted by a majority of the whole board in office, designate no fewer than three (3) of the directors to constitute an executive committee, of which the president shall be a member. Three members of such committee shall constitute a quorum. The president shall act as chairman of the executive committee. During the intervals between the meetings of the board, the executive committee shall have and may exercise all the powers of the board of directors in the management of the property and business of the corporation and shall have power to authorize the seal of the corporation to be affixed to all instruments that may require it, all except as otherwise provided by law.

Other Standing Committees

Section 2. The board of directors may also, by resolution or resolutions adopted by a majority of the whole board in office, designate one or more other standing committees as it deems necessary and desirable. Each such committee shall consist of at least two directors of the corporation and shall have and may exercise the powers of the board of directors in the management of the business and affairs of the corporation to the extent provided in such resolution or resolutions and these by-laws. The board of directors shall designate the name of and appoint the chairman of each such committee. A majority of the members of each such committee shall constitute a quorum. To the extent specified by the board or in the Charter or by-laws, each committee may exercise the authority of the board of directors, shall have and may exercise all the authority of the board of directors in the management of the business and affairs of the corporation; except that no such committee shall have the authority of the board of directors with reference to (1) authorizing distributions, (2) approving or proposing to stockholders actions requiring approval by stockholders, (3) filling vacancies on the board of directors or on any of its committees, (4) amending the Charter, (5)

adopting, amending or repealing these by-laws, or restating the Certificate of Incorporation, (6) approving a plan of merger not requiring stockholder approval, (7) authorizing or approving reacquisition of shares, except according to formula or method prescribed by the board of directors, or (8) authorizing or approving the issuance or sale or contract for sale of shares, or determining the designation and relative rights, except that the board of directors may authorize a committee (or senior executive officer of the corporation) to do so within limits specifically prescribed by the board of directors.

Advisory Committees

Section 3. The board of directors may also, by resolution or resolutions adopted by a majority of the whole board in office, designate one or more advisory committees as it deems necessary and desirable. Each such committee shall consist of at least two directors of the corporation and shall advise the board of directors on the matter or matters provided in such resolution or resolutions. The board of directors shall designate the name of and appoint the chairman of each such committee. Each such committee shall prepare and deliver reports to the board of directors as the board of directors or the chairman thereof requests. A majority of the members of each such committee shall constitute a quorum.

Election of Committee Members

Section 4. The members of the executive committee,other standing committees, and the advisory committees shall be elected at the annual meeting of the board of directors or as soon thereafter as is practicable. The members of all such committees shall hold office until the next annual meeting of the board of directors and until their respective successors are elected. The board of directors shall have the power to fill vacancies in, to change the membership of and to dissolve any such committee.

Meetings and Minutes

Section 5. The executive committee and the other committees shall meet at such time and place as their respective chairman may appoint. Notice of each meeting of the executive committee and the other committees may be given by telephone, or electronic transmission or in writing specifying the place, day and hour thereof. If given in writing, such notice may be served personally at least one hour before such meeting or as otherwise provided in these by-laws. The executive committee and each of the other standing committees shall maintain regular minutes of their respective proceedings; each of the advisory committees shall maintain memoranda of their respective meetings. All actions taken by the executive committee or any of the other standing committees shall be reported to

the board of directors at its next succeeding meeting and shall be subject to amendment, revision or alteration by the board of directors, provided, however, that the rights or acts of third parties shall not be affected by such amendment, revision or alteration. The members of the executive committee and the other committees shall be entitled to such fees and expenses as may be fixed by the board of directors.

ARTICLE VI

OFFICERS

Enumeration of Officers

Section 1. The officers of the corporation shall be chosen by the board of directors, except as herein provided. The full time executive officers shall include a president and may include one or more vice presidents, all as the board of directors may from time to time determine. The administrative officers shall include a secretary and may include one or more vice presidents in charge of particular work or divisions of the corporation, a treasurer, a comptroller and such assistant secretaries, assistant treasurers and assistant comptrollers as the board of directors may from time to time determine. Two or more offices may be held by the same person, except that the same person may not serve as president and as secretary. Officers other than the chairman and the president need not be members of the board.

Chairman

Section 2. The chairman of the board shall preside at all meetings of the board of directors and stockholders. The chairman shall perform and do all acts incident to the position of chairman of the board and such other duties as may be assigned to the chairman from time to time by the board of directors. The chairman shall be an ex-officio member of the executive committee of the board of directors; provided, however, that it shall not be necessary to considerthe chairman’s membership in the determination of quorum.

President

Section 3. The president shall be the chief executive officer of the corporation, a member and chairman of the executive committee. Subject to the control of the board of directors, the executive committee or the committees of the board having authority, the president shall be vested with authority to act for the corporation in all matters and shall have general charge of the corporation and the general supervision of its affairs. Subject to the limitations stated, the

president shall have full power and authority to do and perform in the name of the corporation all acts necessary or proper to be done and performed, and to delegate to the vice presidents such part of the president's authority as may be appropriate. In the absence or inability to act of the chairman of the board, the president shall act in their stead. In the event the office of the chairman of the board has not been filled by the board of directors, or in the event it is specifically provided for by the board, the president shall have the powers and duties attributed to the office of the chairman of the board.

Vice Presidents

Section 4. The vice presidents shall perform such of the duties of the president on behalf of the corporation as may be respectively assigned to them from time to time by the board of directors or the president. One or more vice presidents may be designated as either “executive vice president” or “senior vice president”.

Secretary

Section 5. The secretary shall, unless otherwise directed, attend all sessions of the board and all meetings of the stockholders and act as clerk thereof, and record all votes and the minutes of all proceedings in a book to be kept for that purpose; and shall perform like duties for standing committees when required. The secretary shall give or cause to be given notice of all meetings of the stockholders and of the board of directors and of standing committees when required, and shall perform such other duties as may be prescribed by the board of directors or the chief executive officer under whose supervisionthe secretary shall act. The secretary shall keep in safe custody the seal of the corporation and, when authorized, affix the same to any instrument requiring a seal and attest the signature thereof when directed or required to do so.

Treasurer

Section 6. The treasurer shall have the custody of the corporation funds and securities and shall be accountable for the receipts and disbursements in books belonging to the corporation, and shall deposit all moneys and other valuable effects in the name and to the credit of the corporation in such depositories as may be designated by the board of directors.

Section 7. The treasurer shall disburse funds of the corporation as may be ordered by the board, taking proper vouchers for such disbursements, and shall render to the president and to the board of directors at the regular meetings of the board or whenever the board may require it, an account of all transactions as

treasurer and of the financial condition of the corporation and shall perform such other duties as may be assigned from time to time.

Comptroller

Section 8. The comptroller shall have charge of all books and accounts of the corporation, and shall keep full and accurate accounts of receipts and disbursements in books belonging to the corporation, and shall perform such other duties as may be assigned from time to time.

Assistant Secretaries, Assistant Treasurers

and Assistant Comptrollers

Section 9. One or more assistant secretaries, assistant treasurers and assistant comptrollers may be elected by the board of directors or appointed by the chief executive officer to hold office until the next annual meeting of the board of directors and until their successors are elected or appointed, but may be removed at any time. They shall perform any of or all of the duties of secretary, treasurer or comptroller, as the case may be, and such other duties as may be assigned from time to time.

Duties of Officers May Be Delegated

Section 10. In case of the absence of any officer of the corporation, or for any other reason the board may deem sufficient, the board may delegate the powers or duties of such officers to any other officer or to any director, for the time being.

Term of Office

Section 11. The officers of the corporation shall hold office until the next succeeding annual meeting of the board of directors or until their successors are elected and qualified. Any officer elected or appointed by the board of directors may be removed at any time by the affirmative vote of a majority of the whole board of directors. All officers, agents and employees other than officers appointed by the board, shall hold office at the discretion of the officer appointing them, but shall be subject to removal by the board of directors or the executive committee at any time.

ARTICLE VII

VACANCIES

Section 1. If the office of the president, vice president, secretary, treasurer, comptroller or other officer or agent elected by the board, becomes vacant by reason of death, resignation, retirement, disqualification, removal from office or otherwise, the directors then in office although less than a quorum, by a majority vote may choose a successor or successors who shall hold office for the unexpired term in respect of which such vacancy occurred.

ARTICLE VIII

Transactions with Directors, Officers and Certain Entities

Section 1. No contract or transaction between a corporation and one or more of its directors or officers, or between a corporation and any other corporation, partnership, association, or other entity in which one or more of its directors or officers, are directors or officers, or have a financial interest, shall be void or voidable solely for this reason, or solely because the director or officer is present at or participates in the meeting of the board of directors or committee which authorizes the contract or transaction, or solely because the director's or officer's votes are counted for that purpose, if the transaction was in compliance with Alabama Code 10A-2A-8.60.

ARTICLE IX

CAPITAL STOCK

Certificates

Section 1. Unless determined otherwise by the board of directors, the certificates of stock of the corporation shall be numbered and shall be entered on the stock certificate books of the corporation as they are issued. They shall exhibit the holder’s name and number of shares and shall be signed by the president or a vice president and the secretary or an assistant secretary or the treasurer or an assistant treasurer, and shall bear the corporate seal, which may be facsimile, engraved or printed. To the extent permitted under Alabama law, the signature of any such president, vice president, secretary, assistant secretary, treasurer or assistant treasurer upon such certificate may be facsimile, engraved or printed. In any case, when such officer or officers who shall have signed, or whose facsimile

signature or signatures shall have been placed upon such certificate shall cease to be such either because of death, resignation or otherwise before such certificate isdelivered by the corporation, such certificate may nevertheless be issued and delivered by the corporation with the same effect as if such officer or officers had not ceased to be such. No certificate shall be issued unless the stock represented thereby is fully paid.

Transfer

Section 2. The transfer of all classes of stock shall be made and registered only by the person named in the certificate, or by attorney lawfully constituted in writing, upon surrender of such certificate and payment of all taxes; and the corporation shall keep in the hands of an agent or other person designated for that purpose a true statement or book showing who are the holders of the stock of the corporation and all transfers and hypothecations thereof; and the corporation may by its board of directors appoint one or more transfer agents or transfer clerks and registrars, and may require all stock certificates and certificates representing any rights or options to be signed by such transfer agents or transfer clerks acting on behalf of the corporation and by such registrars.

Record Date

Section 3. For the purpose of determining stockholders entitled to notice of a stockholders' meeting, to demand a special meeting, to vote, or to take any other action, the board of directors of the corporation may fix the record date but not to exceed, in any case, seventy (70) days before the meeting or action requiring a determination of stockholders. A determination of stockholders entitled to notice of or to vote at a stockholders' meeting is effective for any adjournment of the meeting unless the board fixes a new record date, which it must do if the meeting is adjourned to a date more than one hundred twenty (120) days after the date fixed for the original meeting.

Record Holder

Section 4. The corporation shall be entitled to treat the holder of record of any share of stock as the holder in fact thereof, and accordingly shall not be bound to recognize any equitable or other claim to or interest in such share or shares on the part of any other person, whether or not it shall have express or other notice thereof, save as expressly provided by the laws of Alabama.

Lost, Destroyed and Mutilated Certificates

Section 5. The holder of any share of stock shall immediately notify the corporation of any loss, destruction or mutilation of the certificate therefor, and the board may, in its discretion, and after the expiration of such period of time as it may determine to be advisable, cause a new certificate or certificates for shares of stock to be issued, upon the surrender of the mutilated certificate, or in case of loss or destruction of the certificate, upon proof satisfactory to the board of such loss or destruction. The board may, in its sole discretion, require the owner of the lost, destroyed or mutilated certificate, or his legal representatives, to give the corporation a bond, in such sum and with such surety or sureties as it may direct, to indemnify the corporation against any claim that may be made against it on account of the alleged loss, destruction or mutilation of any such certificate or the issuance of such new certificate.

Dividends

Section 6. Subject to the provisions of the Charter, dividends upon the capital stock of the corporation when earned, may be declared by the board of directors at any regular meeting, or any special meeting. Before paying any dividend or making any distribution of profits, there may be set aside out of the surplus or net profits of the corporation such sum or sums as the board of directors from time to time in its absolute discretion may determine to be proper, as a reserve fund to meet contingencies or for equalizing dividends or for repairing or maintaining any property of the corporation or for such other purpose as the board shall think proper.

Annual Reports to Stockholders

Section 7. The board of directors shall cause the corporation to furnish to each of its stockholders who request a financial statement, its annual financial statements, which may be consolidated or combined statements of the corporation and one or more of its subsidiaries, including a balance sheet as of the end of such fiscal year, a statement of income for such fiscal year and a statement of changes in stockholders equity. Such financial statement shall be prepared in accordance with generally accepted accounting principles, or, if the books of the corporation are not maintained on that basis, may be prepared either on the same basis used by the corporation for filing its United States income tax returns or as required by appropriate regulatory agencies. The financial statement shall be accompanied by a report of the president, the officer of the corporation in charge of its financial records or a certified public accountant stating whether, in his opinion, the financial statements of the corporation present fairly the financial position of the corporation and the results of its operations in

accordance with generally accepted accounting principles and, if not, describing the basis of their preparation and giving his opinion of the fairness of the presentation of the data shown by them, in accordance with accounting procedures generally used in the trade, industry or business conducted by the corporation. Such financial statements shall be mailed or delivered to each shareholder who requests a statement within 120 days after the close of each fiscal year.

ARTICLE X

CORPORATE SEAL

Section 1. The seal of the corporation shall be circular in form and shall have inscribed thereon the name of the corporation followed by the word “Alabama,” and shall have the word “Seal” inscribed in the center thereof.

ARTICLE XI

FISCAL YEAR

Section 1. The fiscal year shall begin with the first day of January in each year.

ARTICLE XII

NOTICES

Section 1. Whenever under the provision of these by-laws notice is required to be given to any director, officer or stockholder, it shall not be construed to mean personal notice, but such written notice may be given by mail or private carrier, with postage thereon prepaid, or by e-mail transmission or other similar electronic means of communication providing evidence of transmission addressed to such stockholder, officer or director, at such address as it appears on the books of the corporation, or in default of other address, to such stockholder, director or officer at the general post office at the principal office of the corporation in the State of Alabama. Written notice to the corporation’s stockholders is effective when mailed, if mailed postpaid and correctly addressed to the stockholder's address shown on the books of the corporation. Notice to directors may also be given in person, or by telephone, telecopy or facsimile transmission. Any stockholder, director or officer may waive any notice required to be given either by statute or under these by-laws; and all meetings of

stockholders and directors may be held without notice, if waived, at such time and place as may be fixed.

ARTICLE XIII

AMENDMENTS

Section 1.    Except as otherwise provided by law, these by-laws may be altered, amended or repealed by a majority of the board of directors present at any meeting thereof.

ARTICLE XIV

INDEMNIFICATION AND RELATED MATTERS

Section 1. Each person who is or was a director, officer or employee of the corporation holding one or more positions of management through and inclusive of department managers or other employees explicitly designated in writing by the president or a vice president of the Company (such individuals being hereinafter referred to as ”indemnified parties”) and who was or is a party or was or is threatened to be made a party to any threatened, pending or completed claim, action, suit or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he is or was a director of the corporation or officer or employee of the corporation, or is or was serving at the request of the corporation as a director, officer, employee, agent or trustee of another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, shall be indemnified by the corporation as a matter of right against any and all expenses (including attorneys’ fees) actually and reasonably incurred by such person and against any and all claims, judgments, fines, penalties, liabilities and amounts paid in settlement actually incurred by them in defense of such claim, action, suit or proceeding, including appeals, to the full extent permitted by applicable law. The indemnification provided by this Section shall inure to the benefit of the heirs, executors and administrators of such person.

Expenses (including attorneys’ fees) incurred by an indemnified party with respect to the defense of any such claim, action, suit or proceeding may be advanced by the corporation prior to the final disposition of such claim, action, suit or proceeding, as authorized by the board of directors in the specific case, upon receipt of an undertaking by or on behalf of such person entitled to be indemnified by the corporation under this Section or otherwise; provided, however, that the advancement of such expenses shall not be deemed to be

indemnification unless and until it shall ultimately be determined that such person is entitled to be indemnified by the corporation.

The corporation may purchase and maintain insurance at the expense of the corporation on behalf of any person who is or was a director, officer, employee or agent of the corporation, or any person who is or was serving at the request of the corporation as a director (or the equivalent), officer, employee, agent or trustee of another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, against any liability or expense (including attorneys’ fees) asserted against a director or officer and incurred by them in any such capacity, or arising out of their status as such, whether or not the corporation would have the power to indemnify them against such liability or expense under this Section or otherwise.

Without limiting the generality of the foregoing provisions of this Section, no present or future director or officer of the corporation, or their heirs, executors, or administrators, shall be liable for any act, omission, step, or conduct taken or had in good faith, which is required, authorized, or approved by any order or orders issued pursuant to the Public Utility Holding Company Act of 2005, the Federal Power Act, or any federal or state statue or municipal ordinance regulating the corporation or its parent by reason of their being holding or investment companies, public utility companies, public utility holding companies, or subsidiaries of public utility holding companies. In any action, suit, or proceeding based on any act, omission, step, or conduct, as in this paragraph described, the provisions hereof shall be brought to the attention of the court. In the event that the foregoing provisions of this paragraph are found by the court not to constitute a valid defense on the grounds of not being applicable to the particular class of plaintiff, each such director and officer, and their heirs, executors, and administrators, shall be reimbursed for, or indemnified against, all expenses and liabilities incurred by them or imposed on them, in connection with, or arising out of, any such action, suit, or proceeding based on any act, omission, step, or conduct taken or had in good faith as in this paragraph described. Such expenses and liabilities shall include, but shall not be limited to, judgments, court costs, and attorneys’ fees.

The foregoing rights shall not be exclusive of any other rights to which any such director or officer or employee may otherwise be entitled and shall be available whether or not the director or officer or employee continues to be a director or officer or employee at the time of incurring any such expenses and liabilities.

ARTICLE XV

SEVERABILITY AND RULES OF CONSTRUCTION

Section 1. If any word, clause or provision of the by-laws or any indemnification made under Article XV hereof shall for any reason be determined to be invalid, the provisions of the by-laws shall not otherwise be affected thereby but shall remain in full force and effect.

As amended October 16, 2023

EX-4.F3

Exhibit 4(f)3

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

Supplemental Indenture

Made as of July 11, 2023, to be Effective July 31, 2023
____________________

Northern Illinois Gas Company

to

U.S. Bank Trust Company, National Association

Trustee under Indenture dated as of

January 1, 1954

and

Supplemental Indentures Thereto

____________________

FIRST MORTGAGE BONDS 5.28% SERIES DUE JULY 31, 2030

FIRST MORTGAGE BONDS 5.43% SERIES DUE JULY 31, 2035

FIRST MORTGAGE BONDS 5.67% SERIES DUE OCTOBER 31, 2053

FIRST MORTGAGE BONDS 5.77% SERIES DUE OCTOBER 31, 2063

This Supplemental Indenture, made as of July 11, 2023 and effective July 31, 2023, between Northern Illinois Gas Company, a corporation organized and existing under the laws of the State of Illinois (hereinafter called the “Company”), and U.S. Bank Trust Company, National Association (hereinafter called the “Trustee”), as successor Trustee under an Indenture dated as of January 1, 1954, as modified by the Indenture of Adoption, dated February 9, 1954 and the Indenture of Release, dated February 9, 1954, and as supplemented by Supplemental Indentures dated (or made effective) April 1, 1956, June 1, 1959, July 1, 1960, June 1, 1963, July 1, 1963, August 1, 1964, August 1, 1965, May 1, 1966, August 1, 1966, July 1, 1967, June 1, 1968, December 1, 1969, August 1, 1970, June 1, 1971, July 1, 1972, July 1, 1973, April 1, 1975, April 30, 1976 (two Supplemental Indentures bearing that date), July 1, 1976, August 1, 1976, December 1, 1977, January 15, 1979, December 1, 1981, March 1, 1983, October 1, 1984, December 1, 1986, March 15, 1988, July 1, 1988, July 1, 1989, July 15, 1990, August 15, 1991, July 15, 1992, February 1, 1993, March 15, 1993, May 1, 1993, July 1, 1993, August 15, 1994, October 15, 1995, May 10, 1996, August 1, 1996, June 1, 1997, October 15, 1997, February 15, 1998, June 1, 1998, February 1, 1999, February 1, 2001, May 15, 2001, August 15, 2001, December 15, 2001, December 1, 2003 (three Supplemental Indentures bearing that date), December 15, 2006, August 15, 2008, July 30, 2009, February 1, 2011, October 26, 2012, June 23, 2016, August 10, 2017, August 16, 2018, August 30, 2019, August 31, 2020 and August 31, 2021, such Indenture dated as of January 1, 1954, as so modified and supplemented, being hereinafter called the “Indenture.”

Witnesseth:

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

Whereas, the Company desires, by this Supplemental Indenture, to create four additional series of bonds to be issuable under the Indenture, such bonds to be designated, respectively, (a) “First Mortgage Bonds 5.28% Series due July 31, 2030” (hereinafter called the “2030 Series”), (b) “First Mortgage Bonds 5.43% Series due July 31, 2035” (hereinafter called the “2035 Series”), (c) “First Mortgage Bonds 5.67% Series due October 31, 2053” (hereinafter called the “2053 Series”) and (d) “First Mortgage Bonds 5.77% Series due October 31, 2063” (hereinafter called the “2063 Series”; the 2030 Series, the 2035 Series, the 2053 Series and the 2063 Series, hereinafter called, collectively, the “bonds of this Supplemental Indenture”), and the terms and provisions to be contained in the bonds of this Supplemental Indenture or to be otherwise applicable thereto to be as set forth in this Supplemental Indenture; and

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

[Remainder of Page Intentionally Left Blank]

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(Form of Face of Bond of 2030 Series)

NO. RU-2023-A-__	$________
Ill. Commerce Commission No. 6935	CUSIP No. ___________

Northern Illinois Gas Company

First Mortgage Bond 5.28% Series due July 31, 2030

Northern Illinois Gas Company, an Illinois corporation (hereinafter called the “Company”), for value received, hereby promises to pay to                      or registered assigns, the sum of                           Dollars, on July 31, 2030, and to pay to the registered owner hereof interest on said sum from the date hereof until said sum shall be paid, at the rate of 5.28% per annum, payable semi-annually on the thirty-first day of January and the thirty-first day of July in each year, beginning on January 31, 2024. Both the principal of and the interest on this bond shall be payable at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of the registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York, in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts. Any installment of interest on this bond may, at the Company’s option, be paid by mailing checks for such interest payable to or upon the written order of the person entitled thereto to the address of such person as it appears on the registration books.

So long as there is no existing default in the payment of interest on this bond, the interest so payable on any interest payment date will be paid to the person in whose name this bond is registered on January 15 or July 15 (whether or not a business day), as the case may be, next preceding such interest payment date. If and to the extent that the Company shall default in the payment of interest due on such interest payment date, such defaulted interest shall be paid to the person in whose name this bond is registered on the record date fixed, in advance, by the Company for the payment of such defaulted interest.

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

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

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

Dated: July 31, 2023

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

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(Form of Trustee’s Certificate of Authentication)

This bond is one of the bonds of the 2030 Series designated therein, referred to and described in the within-mentioned Supplemental Indenture dated as of July 11, 2023, effective July 31, 2023.

U.S. Bank Trust Company, National Association,
   Trustee

By:_________________________________

                      Authorized Officer

Dated: July 31, 2023

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(Form of Reverse Side of Bond of 2030 Series)

This bond is one, of the series hereinafter specified, of the bonds issued and to be issued in series from time to time under and in accordance with and secured by an Indenture dated as of January 1, 1954, to U.S. Bank Trust Company, National Association, as Trustee, as supplemented by certain indentures supplemental thereto, executed and delivered to the Trustee; and this bond is one of a series of such bonds, designated “Northern Illinois Gas Company First Mortgage Bond 5.28% Series due July 31, 2030” (herein called “bonds of this Series”), the issuance of which is provided for by a Supplemental Indenture dated as of July 11, 2023, effective July 31, 2023 (hereinafter called the “Supplemental Indenture”), executed and delivered by the Company to the Trustee. The term “Indenture”, as hereinafter used, means said Indenture dated as of January 1, 1954, and all indentures supplemental thereto (including, without limitation, the Supplemental Indenture) from time to time in effect. Reference is made to the Indenture for a description of the property mortgaged and pledged, the nature and extent of the security, the rights of the holders and registered owners of said bonds, of the Company and of the Trustee in respect of the security, and the terms and conditions governing the issuance and security of said bonds.

Any transferee, by its acceptance of a bond registered in its name (or the name of its nominee), shall be deemed to have made the representation set forth in Section 6.2 of the Bond Purchase Agreement dated as of July 11, 2023 among the Company and the purchasers listed on Schedule A attached thereto, as amended, restated, supplemented or otherwise modified from time to time.

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

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

- 5 -

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

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

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

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

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

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

(End of Form of Bond of 2030 Series)

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(Form of Face of Bond of 2035 Series)

NO. RU-2023-B-__	$________
Ill. Commerce Commission No. 6936	CUSIP No. ___________

Northern Illinois Gas Company

First Mortgage Bond 5.43% Series due July 31, 2035

Northern Illinois Gas Company, an Illinois corporation (hereinafter called the “Company”), for value received, hereby promises to pay to                      or registered assigns, the sum of                           Dollars, on July 31, 2035, and to pay to the registered owner hereof interest on said sum from the date hereof until said sum shall be paid, at the rate of 5.43% per annum, payable semi-annually on the thirty-first day of January and the thirty-first day of July in each year, beginning on January 31, 2024. Both the principal of and the interest on this bond shall be payable at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of the registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York, in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts. Any installment of interest on this bond may, at the Company’s option, be paid by mailing checks for such interest payable to or upon the written order of the person entitled thereto to the address of such person as it appears on the registration books.

So long as there is no existing default in the payment of interest on this bond, the interest so payable on any interest payment date will be paid to the person in whose name this bond is registered on January 15 or July 15 (whether or not a business day), as the case may be, next preceding such interest payment date. If and to the extent that the Company shall default in the payment of interest due on such interest payment date, such defaulted interest shall be paid to the person in whose name this bond is registered on the record date fixed, in advance, by the Company for the payment of such defaulted interest.

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

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

- 7 -

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

Dated: July 31, 2023

	Northern Illinois Gas Company By:__________________________________________ Executive Vice President, Chief Financial Officer and Treasurer
ATTEST: ______________________________________ Corporate Secretary

- 8 -

(Form of Trustee’s Certificate of Authentication)

This bond is one of the bonds of the 2035 Series designated therein, referred to and described in the within-mentioned Supplemental Indenture dated as of July 11, 2023, effective July 31, 2023.

U.S. Bank Trust Company, National Association,
   Trustee

By:_________________________________

                      Authorized Officer

Dated: July 31, 2023

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(Form of Reverse Side of Bond of 2035 Series)

This bond is one, of the series hereinafter specified, of the bonds issued and to be issued in series from time to time under and in accordance with and secured by an Indenture dated as of January 1, 1954, to U.S. Bank Trust Company, National Association, as Trustee, as supplemented by certain indentures supplemental thereto, executed and delivered to the Trustee; and this bond is one of a series of such bonds, designated “Northern Illinois Gas Company First Mortgage Bond 5.43% Series due July 31, 2035” (herein called “bonds of this Series”), the issuance of which is provided for by a Supplemental Indenture dated as of July 11, 2023, effective July 31, 2023 (hereinafter called the “Supplemental Indenture”), executed and delivered by the Company to the Trustee. The term “Indenture”, as hereinafter used, means said Indenture dated as of January 1, 1954, and all indentures supplemental thereto (including, without limitation, the Supplemental Indenture) from time to time in effect. Reference is made to the Indenture for a description of the property mortgaged and pledged, the nature and extent of the security, the rights of the holders and registered owners of said bonds, of the Company and of the Trustee in respect of the security, and the terms and conditions governing the issuance and security of said bonds.

Any transferee, by its acceptance of a bond registered in its name (or the name of its nominee), shall be deemed to have made the representation set forth in Section 6.2 of the Bond Purchase Agreement dated as of July 11, 2023 among the Company and the purchasers listed on Schedule A attached thereto, as amended, restated, supplemented or otherwise modified from time to time.

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

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

- 10 -

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

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

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

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

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

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

(End of Form of Bond of 2035 Series)

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(Form of Face of Bond of 2053 Series)

NO. RU-2023-C-__	$________
Ill. Commerce Commission No. 6937	CUSIP No. ___________

Northern Illinois Gas Company

First Mortgage Bond 5.67% Series due October 31, 2053

Northern Illinois Gas Company, an Illinois corporation (hereinafter called the “Company”), for value received, hereby promises to pay to                      or registered assigns, the sum of                           Dollars, on October 31, 2053, and to pay to the registered owner hereof interest on said sum from the date hereof until said sum shall be paid, at the rate of 5.67% per annum, payable semi-annually on the thirtieth day of April and the thirty-first day of October in each year, beginning on April 30, 2024. Both the principal of and the interest on this bond shall be payable at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of the registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York, in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts. Any installment of interest on this bond may, at the Company’s option, be paid by mailing checks for such interest payable to or upon the written order of the person entitled thereto to the address of such person as it appears on the registration books.

So long as there is no existing default in the payment of interest on this bond, the interest so payable on any interest payment date will be paid to the person in whose name this bond is registered on April 15 or October 15 (whether or not a business day), as the case may be, next preceding such interest payment date. If and to the extent that the Company shall default in the payment of interest due on such interest payment date, such defaulted interest shall be paid to the person in whose name this bond is registered on the record date fixed, in advance, by the Company for the payment of such defaulted interest.

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

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

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

Dated: October 31, 2023

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

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(Form of Trustee’s Certificate of Authentication)

This bond is one of the bonds of the 2053 Series designated therein, referred to and described in the within-mentioned Supplemental Indenture dated as of July 11, 2023, effective July 31, 2023.

U.S. Bank Trust Company, National Association,
   Trustee

By:_________________________________

                      Authorized Officer

Dated: October 31, 2023

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(Form of Reverse Side of Bond of 2053 Series)

This bond is one, of the series hereinafter specified, of the bonds issued and to be issued in series from time to time under and in accordance with and secured by an Indenture dated as of January 1, 1954, to U.S. Bank Trust Company, National Association, as Trustee, as supplemented by certain indentures supplemental thereto, executed and delivered to the Trustee; and this bond is one of a series of such bonds, designated “Northern Illinois Gas Company First Mortgage Bond 5.67% Series due October 31, 2053” (herein called “bonds of this Series”), the issuance of which is provided for by a Supplemental Indenture dated as of July 11, 2023, effective July 31, 2023 (hereinafter called the “Supplemental Indenture”), executed and delivered by the Company to the Trustee. The term “Indenture”, as hereinafter used, means said Indenture dated as of January 1, 1954, and all indentures supplemental thereto (including, without limitation, the Supplemental Indenture) from time to time in effect. Reference is made to the Indenture for a description of the property mortgaged and pledged, the nature and extent of the security, the rights of the holders and registered owners of said bonds, of the Company and of the Trustee in respect of the security, and the terms and conditions governing the issuance and security of said bonds.

Any transferee, by its acceptance of a bond registered in its name (or the name of its nominee), shall be deemed to have made the representation set forth in Section 6.2 of the Bond Purchase Agreement dated as of July 11, 2023 among the Company and the purchasers listed on Schedule A attached thereto, as amended, restated, supplemented or otherwise modified from time to time.

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

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

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

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

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

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

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

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

(End of Form of Bond of 2053 Series)

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(Form of Face of Bond of 2063 Series)

NO. RU-2023-D-__	$________
Ill. Commerce Commission No. 6938	CUSIP No. ___________

Northern Illinois Gas Company

First Mortgage Bond 5.77% Series due October 31, 2063

Northern Illinois Gas Company, an Illinois corporation (hereinafter called the “Company”), for value received, hereby promises to pay to                      or registered assigns, the sum of                           Dollars, on October 31, 2063, and to pay to the registered owner hereof interest on said sum from the date hereof until said sum shall be paid, at the rate of 5.77% per annum, payable semi-annually on the thirtieth day of April and the thirty-first day of October in each year, beginning on April 30, 2024. Both the principal of and the interest on this bond shall be payable at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of the registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York, in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts. Any installment of interest on this bond may, at the Company’s option, be paid by mailing checks for such interest payable to or upon the written order of the person entitled thereto to the address of such person as it appears on the registration books.

So long as there is no existing default in the payment of interest on this bond, the interest so payable on any interest payment date will be paid to the person in whose name this bond is registered on April 15 or October 15 (whether or not a business day), as the case may be, next preceding such interest payment date. If and to the extent that the Company shall default in the payment of interest due on such interest payment date, such defaulted interest shall be paid to the person in whose name this bond is registered on the record date fixed, in advance, by the Company for the payment of such defaulted interest.

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

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

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

Dated: October 31, 2023

	Northern Illinois Gas Company By:__________________________________________ Executive Vice President, Chief Financial Officer and Treasurer
ATTEST: ______________________________________ Corporate Secretary

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(Form of Trustee’s Certificate of Authentication)

This bond is one of the bonds of the 2063 Series designated therein, referred to and described in the within-mentioned Supplemental Indenture dated as of July 11, 2023, effective July 31, 2023.

U.S. Bank Trust Company, National Association,
   Trustee

By:_________________________________

                      Authorized Officer

Dated: October 31, 2023

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(Form of Reverse Side of Bond of 2063 Series)

This bond is one, of the series hereinafter specified, of the bonds issued and to be issued in series from time to time under and in accordance with and secured by an Indenture dated as of January 1, 1954, to U.S. Bank Trust Company, National Association, as Trustee, as supplemented by certain indentures supplemental thereto, executed and delivered to the Trustee; and this bond is one of a series of such bonds, designated “Northern Illinois Gas Company First Mortgage Bond 5.77% Series due October 31, 2063” (herein called “bonds of this Series”), the issuance of which is provided for by a Supplemental Indenture dated as of July 11, 2023, effective July 31, 2023 (hereinafter called the “Supplemental Indenture”), executed and delivered by the Company to the Trustee. The term “Indenture”, as hereinafter used, means said Indenture dated as of January 1, 1954, and all indentures supplemental thereto (including, without limitation, the Supplemental Indenture) from time to time in effect. Reference is made to the Indenture for a description of the property mortgaged and pledged, the nature and extent of the security, the rights of the holders and registered owners of said bonds, of the Company and of the Trustee in respect of the security, and the terms and conditions governing the issuance and security of said bonds.

Any transferee, by its acceptance of a bond registered in its name (or the name of its nominee), shall be deemed to have made the representation set forth in Section 6.2 of the Bond Purchase Agreement dated as of July 11, 2023 among the Company and the purchasers listed on Schedule A attached thereto, as amended, restated, supplemented or otherwise modified from time to time.

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

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

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

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

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

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

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

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

(End of Form of Bond of 2063 Series)

and

WHEREAS, all acts and things necessary to make this Supplemental Indenture, when duly executed and delivered, a valid, binding and legal instrument in accordance with its terms, and for the purposes herein expressed, have been done and performed, and the execution and delivery of this Supplemental Indenture have in all respects been duly authorized.

Now Therefore, in consideration of the premises and of the sum of one dollar paid by the Trustee to the Company, and for other good and valuable consideration, the receipt of which is hereby acknowledged, for the purpose of securing the due and punctual payment of the principal of and the interest and premium, if any, on all bonds which shall be issued under the Indenture,

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and for the purpose of securing the faithful performance and observance of all the covenants and conditions set forth in the Indenture and in all indentures supplemental thereto, the Company by these presents does grant, bargain, sell, transfer, assign, pledge, mortgage, warrant and convey unto U.S. Bank Trust Company, National Association, as Trustee, and its successor or successors in the trust hereby created, all property, real and personal (other than property expressly excepted from the lien and operation of the Indenture), which, at the actual date of execution and delivery of this Supplemental Indenture, is solely used or held for use in the operation by the Company of its gas utility system and in the conduct of its gas utility business and all property, real and personal, used or useful in the gas utility business (other than property expressly excepted from the lien and operation of the Indenture) acquired by the Company after the actual date of execution and delivery of this Supplemental Indenture or (subject to the provisions of Section 16.03 of the Indenture) by any successor corporation after such execution and delivery, and it is further agreed by and between the Company and the Trustee as follows:

ARTICLE I.

Bonds of this Supplemental Indenture

Section 1.The bonds of this Supplemental Indenture shall, as hereinbefore recited, be designated as the Company’s (a) “First Mortgage Bonds 5.28% Series due July 31, 2030”, (b) “First Mortgage Bonds 5.43% Series due July 31, 2035”, (c) “First Mortgage Bonds 5.67% Series due October 31, 2053”, and (d) “First Mortgage Bonds 5.77% Series due October 31, 2063”, as applicable. The bonds of the 2030 Series which may be issued and outstanding shall not exceed $50,000,000 in aggregate principal amount, exclusive of bonds of such series authenticated and delivered pursuant to Section 4.12 of the Indenture. The bonds of the 2035 Series which may be issued and outstanding shall not exceed $75,000,000 in aggregate principal amount, exclusive of bonds of such series authenticated and delivered pursuant to Section 4.12 of the Indenture. The bonds of the 2053 Series which may be issued and outstanding shall not exceed $75,000,000 in aggregate principal amount, exclusive of bonds of such series authenticated and delivered pursuant to Section 4.12 of the Indenture. The bonds of the 2063 Series which may be issued and outstanding shall not exceed $75,000,000 in aggregate principal amount, exclusive of bonds of such series authenticated and delivered pursuant to Section 4.12 of the Indenture.

Section 2.The bonds of this Supplemental Indenture shall be registered bonds without coupons, and the form of each series of such bonds, and of the Trustee’s certificate of authentication to be endorsed on all bonds of this Supplemental Indenture, shall be substantially as hereinbefore recited, respectively.

Section 3.The bonds of this Supplemental Indenture shall be issued in the denomination of $500,000 each and in such integral multiple or multiples thereof (except for one bond per holder and registered owner as may be necessary to reflect any principal amount in excess of $500,000 not evenly divisible by $500,000) as shall be determined and authorized by the Board of Directors of the Company or by any officer of the Company authorized by the Board of Directors to make such determination, the authorization of the denomination of any bond to be conclusively evidenced by the execution thereof on behalf of the Company. The bonds of the 2030 Series shall be numbered RU-2023-A-1 and consecutively upwards, or in such other appropriate manner as shall be determined and authorized by the Board of Directors of the Company. The bonds of the 2035 Series shall be numbered RU-2023-B-1 and consecutively upwards, or in such other appropriate manner as shall be determined and authorized by the Board of Directors of the Company. The bonds of the

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2053 Series shall be numbered RU-2023-C-1 and consecutively upwards, or in such other appropriate manner as shall be determined and authorized by the Board of Directors of the Company. The bonds of the 2063 Series shall be numbered RU-2023-D-1 and consecutively upwards, or in such other appropriate manner as shall be determined and authorized by the Board of Directors of the Company.

The bonds of the 2030 Series shall be dated July 31, 2023, except that each bond issued on or after the respective first payment of interest thereon shall be dated as of the date of the interest payment date thereof to which interest shall have been paid on the bonds of such series next preceding the date of issue, unless issued on an interest payment date to which interest shall have been so paid, in which event such bonds shall be dated as of the date of issue; provided, however, that bonds issued on or after January 15 and before the next succeeding January 31 or on or after July 15 and before the next succeeding July 31 shall be dated the next succeeding interest payment date if interest shall have been paid to such date. The bonds of the 2035 Series shall be dated July 31, 2023, except that each bond issued on or after the respective first payment of interest thereon shall be dated as of the date of the interest payment date thereof to which interest shall have been paid on the bonds of such series next preceding the date of issue, unless issued on an interest payment date to which interest shall have been so paid, in which event such bonds shall be dated as of the date of issue; provided, however, that bonds issued on or after January 15 and before the next succeeding January 31 or on or after July 15 and before the next succeeding July 31 shall be dated the next succeeding interest payment date if interest shall have been paid to such date. The bonds of the 2053 Series shall be dated October 31, 2023, except that each bond issued on or after the respective first payment of interest thereon shall be dated as of the date of the interest payment date thereof to which interest shall have been paid on the bonds of such series next preceding the date of issue, unless issued on an interest payment date to which interest shall have been so paid, in which event such bonds shall be dated as of the date of issue; provided, however, that bonds issued on or after April 15 and before the next succeeding April 30 or on or after October 15 and before the next succeeding October 31 shall be dated the next succeeding interest payment date if interest shall have been paid to such date. The bonds of the 2063 Series shall be dated October 31, 2023, except that each bond issued on or after the respective first payment of interest thereon shall be dated as of the date of the interest payment date thereof to which interest shall have been paid on the bonds of such series next preceding the date of issue, unless issued on an interest payment date to which interest shall have been so paid, in which event such bonds shall be dated as of the date of issue; provided, however, that bonds issued on or after April 15 and before the next succeeding April 30 or on or after October 15 and before the next succeeding October 31 shall be dated the next succeeding interest payment date if interest shall have been paid to such date. The bonds of the 2030 Series shall mature on July 31, 2030 and shall bear interest at the rate of 5.28% per annum until the principal thereof shall be paid. The bonds of the 2035 Series shall mature on July 31, 2035 and shall bear interest at the rate of 5.43% per annum until the principal thereof shall be paid. The bonds of the 2053 Series shall mature on October 31, 2053 and shall bear interest at the rate of 5.67% per annum until the principal thereof shall be paid. The bonds of the 2063 Series shall mature on October 31, 2063 and shall bear interest at the rate of 5.77% per annum until the principal thereof shall be paid. Interest on the bonds of this Supplemental Indenture shall be calculated on the basis of a 360-day year consisting of twelve 30-day months. Interest on the bonds of the 2030 Series shall be payable semi-annually on the thirty-first day of January and the

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thirty-first day of July in each year, beginning January 31, 2024. Interest on the bonds of the 2035 Series shall be payable semi-annually on the thirty-first day of January and thethirty-first day of July in each year, beginning January 31, 2024. Interest on the bonds of the 2053 Series shall be payable semi-annually on the thirtieth day of April and the thirty-first day of October in each year, beginning April 30, 2024. Interest on the bonds of the 2063 Series shall be payable semi-annually on the thirtieth day of April and the thirty-first day of October in each year, beginning April 30, 2024. So long as there is no existing default in the payment of interest on the bonds of this Supplemental Indenture, such interest shall be payable to the person in whose name each such bond is registered on the respective record date (whether or not a business day), as the case may be, next preceding the respective interest payment dates; provided, however, if and to the extent that the Company shall default in the payment of interest due on such interest payment date, such defaulted interest shall be paid to the person in whose name each such bond is registered on the record date fixed, in advance, by the Company for the payment of such defaulted interest.Interest will accrue on overdue interest installments at the rate of (i) 5.28% per annum, with respect to the bonds of the 2030 Series, (ii) 5.43% per annum, with respect to the bonds of the 2035 Series, (iii) 5.67% per annum, with respect to the bonds of the 2053 Series, and (iv) 5.77% per annum, with respect to the bonds of the 2063 Series.

The principal of and interest and premium, if any, on the bonds of this Supplemental Indenture shall be payable in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts, and shall be payable at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of the registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York. Any installment of interest on the bonds of this Supplemental Indenture may, at the Company’s option, be paid by mailing checks for such interest payable to or upon the written order of the person entitled thereto to the address of such person as it appears on the registration books. The bonds of this Supplemental Indenture shall be registrable, transferable and exchangeable in the manner provided in Sections 4.08 and 4.09 of the Indenture, at either of such offices or agencies.

Section 4.    The bonds of this Supplemental Indenture, upon the mailing of notice and in the manner provided in Section 7.01 of the Indenture (except that no published notice shall be required for the bonds of this Supplemental Indenture) and with the effect provided in Section 7.02 thereof, shall be redeemable at the option of the Company, as a whole at any time or in part from time to time, at a redemption price equal to 100% of the principal amount of the bonds of this Supplemental Indenture to be redeemed plus accrued and unpaid interest of the principal amount being redeemed to the date of redemption plus the Make-Whole Amount applicable thereto, as calculated by the Company. “Make-Whole Amount” means, with respect to any bond of this Supplemental Indenture, an amount equal to the excess, if any, of the Discounted Value of the Remaining Scheduled Payments with respect to the Called Principal of such bond of this Supplemental Indenture over the amount of such Called Principal, provided that the Make-Whole Amount may in no event be less than zero. For the purposes of determining the Make-Whole Amount, the following terms have the following meanings:

“Called Principal” means, with respect to any bond of this Supplemental Indenture, the principal of such bond of this Supplemental Indenture that is to be redeemed.

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“Discounted Value” means, with respect to the Called Principal of any bond of this Supplemental Indenture, the amount obtained by discounting all Remaining Scheduled Payments with respect to such Called Principal from their respective scheduled due dates to the Settlement Date with respect to such Called Principal, in accordance with accepted financial practice and at a discount factor (applied on the same periodic basis as that on which interest on the bond of this Supplemental Indenture is payable) equal to the Reinvestment Yield with respect to such Called Principal.

“Reinvestment Yield” means, with respect to the Called Principal of any bond of this Supplemental Indenture, the sum of (x) 0.50% plus (y) the yield to maturity implied by the “Ask Yield(s)” reported as of 10:00 a.m. (New York City time) on the second Business Day preceding the Settlement Date with respect to such Called Principal, on the display designated as “Page PX1” (or such other display as may replace Page PX1) on Bloomberg Financial Markets for the most recently issued actively traded on-the-run U.S. Treasury securities (“Reported”) having a maturity equal to the Remaining Average Life of such Called Principal as of such Settlement Date. If there are no such U.S. Treasury securities Reported having a maturity equal to such Remaining Average Life, then such implied yield to maturity will be determined by (a) converting U.S. Treasury bill quotations to bond equivalent yields in accordance with accepted financial practice and (b) interpolating linearly between the “Ask Yields” Reported for the applicable most recently issued actively traded on-the-run U.S. Treasury securities with the maturities (1) closest to and greater than such Remaining Average Life and (2) closest to and less than such Remaining Average Life. The Reinvestment Yield shall be rounded to the number of decimal places as appears in the interest rate of the applicable bond.

If such yields are not Reported or the yields Reported as of such time are not ascertainable (including by way of interpolation), then “Reinvestment Yield” means, with respect to the Called Principal of any bond of this Supplemental Indenture, the sum of (x) 0.50% plus (y) the yield to maturity implied by the U.S. Treasury constant maturity yields reported, for the latest day for which such yields have been so reported as of the second Business Day preceding the Settlement Date with respect to such Called Principal, in Federal Reserve Statistical Release H.15 (or any comparable successor publication) for the U.S. Treasury constant maturity having a term equal to the Remaining Average Life of such Called Principal as of such Settlement Date. If there is no such U.S. Treasury constant maturity having a term equal to such Remaining Average Life, such implied yield to maturity will be determined by interpolating linearly between (1) the U.S. Treasury constant maturity so reported with the term closest to and greater than such Remaining Average Life and (2) the U.S. Treasury constant maturity so reported with the term closest to and less than such Remaining Average Life. If there is no available U.S. Treasury greater than such Remaining Average Life to be used for linear interpolation, and if there is no such U.S. Treasury constant maturity having a term equal to two years either side of such Remaining Average Life, the yield to maturity will be determined by the available U.S. Treasury whose maturity is “closest” to the Remaining Average Life. The selection of this “closest" U.S. Treasury will be confirmed by an “intermediary”, which will be appointed by PNC Capital Markets LLC or its successor. The intermediary will be selected from a pool of various experts and market makers in the applicable markets applicable to U.S.

- 25 -

Treasuries. The Reinvestment Yield shall be rounded to the number of decimal places as appears in the interest rate of the applicable bond.

“Remaining Average Life” means, with respect to any Called Principal, the number of years obtained by dividing (a) such Called Principal into (b) the sum of the products obtained by multiplying (1) the principal component of each Remaining Scheduled Payment with respect to such Called Principal by (2) the number of years, computed on the basis of a 360-day year comprised of twelve 30-day months and calculated to the nearest two decimal places, that will elapse between the Settlement Date with respect to such Called Principal and the scheduled due date of such Remaining Scheduled Payment.

“Remaining Scheduled Payments” means, with respect to the Called Principal of any bond of this Supplemental Indenture, all payments of such Called Principal and interest thereon that would be due after the Settlement Date with respect to such Called Principal if no payment of such Called Principal were made prior to its scheduled due date, provided that if such Settlement Date is not a date on which interest payments are due to be made under the terms of the bond of this Supplemental Indenture, then the amount of the next succeeding scheduled interest payment will be reduced by the amount of interest accrued to such Settlement Date and required to be paid on such Settlement Date pursuant to the terms of this Supplemental Indenture.

“Settlement Date” means, with respect to the Called Principal of any bond of this Supplemental Indenture, the date on which such Called Principal is to be redeemed.

Section 5.  No sinking fund is to be provided for the bonds of this Supplemental Indenture.

Article II

Miscellaneous Provisions

Section 1.    This Supplemental Indenture is executed by the Company and the Trustee pursuant to the provisions of Section 4.02 of the Indenture and the terms and conditions hereof shall be deemed to be a part of the terms and conditions of the Indenture for any and all purposes. The Indenture, as heretofore modified and supplemented and as supplemented by this Supplemental Indenture, is in all respects ratified and confirmed.

Section 2.    This Supplemental Indenture shall bind and, subject to the provisions of Article XVI of the Indenture, inure to the benefit of the respective successors and assigns of the parties hereto.

Section 3.    Although this Supplemental Indenture is made as of July 11, 2023, effective July 31, 2023, it shall be effective only from and after the actual time of its execution and delivery by the Company and the Trustee on the date indicated by their respective acknowledgements hereto.

- 26 -

Section 4.    This Supplemental Indenture may be simultaneously executed in any number of counterparts, and all such counterparts executed and delivered, each as an original, shall constitute but one and the same instrument.

Section 5.    The recitals herein are deemed to be those of the Company and not of the Trustee. The Trustee makes no representations as to the validity or sufficiency of this Supplemental Indenture.

- 27 -

In Witness Whereof, Northern Illinois Gas Company has caused this Supplemental Indenture to be executed in its name by its Executive Vice President, Chief Financial Officer and Treasurer and its corporate seal to be hereunto affixed and attested by its Corporate Secretary, and U.S. Bank Trust Company, National Association, as Trustee under the Indenture, has caused this Supplemental Indenture to be executed in its name by one of its authorized officers and attested by one of its authorized officers, all as of the day and year first above written.

Northern Illinois Gas Company By: /s/Grace A. Kolvereid______________     Name: Grace A. Kolvereid         Title:   Executive Vice President, Chief                 Financial Officer and Treasurer
	ATTEST: By:/s/Barbara P. Christopher___________     Name: Barbara P. Christopher     Title:   Corporate Secretary

[Signature Page to 2023 Supplemental Indenture]

U.S. Bank Trust Company, National Association, as Trustee By: /s/Jack Ellerin ______________     Name:   Jack Ellerin     Title:     Vice President
	ATTEST: By: /s/J. David Dever______________ Name:   J. David Dever Title:     Senior Vice President

[Signature Page to 2023 Supplemental Indenture]

STATE OF GEORGIA            }      SS:

COUNTY OF GWINNETT    }

I, Margaret Moodie, a Notary Public in the State aforesaid, DO HEREBY CERTIFY that Grace A. Kolvereid, Executive Vice President, Chief Financial Officer and Treasurer of Northern Illinois Gas Company, an Illinois corporation, one of the parties described in and which executed the foregoing instrument, and Barbara P. Christopher, Corporate Secretary of said corporation, who are both personally known to me to be the same persons whose names are subscribed to the foregoing instrument as such Executive Vice President, Chief Financial Officer and Treasurer and Corporate Secretary, respectively, and who are both personally known to me to be the Executive Vice President, Chief Financial Officer and Treasurer and Corporate Secretary, respectively, of said corporation, personally appeared before me this day and severally acknowledged that they signed, sealed, executed and delivered said instrument as their free and voluntary act as such Executive Vice President, Chief Financial Officer and Treasurer and Corporate Secretary, respectively, of said corporation, and as the free and voluntary act of said corporation, for the uses and purposes therein set forth.

GIVEN under my hand and notarial seal as of the date listed below.

Dated: July 11, 2023

/s/Margaret Moodie

Notary Public

My Commission expires: February 25, 2027.

State of Georgia      )

                                ): ss

County of Fulton     )

On the 12th day of July in the year 2023, before me, the undersigned, personally appeared, Jack Ellerin, a Vice President of U.S. Bank Trust Company, National Association, and J. David Dever, a Senior Vice President of U.S. Bank Trust Company, National Association, personally known to me or proved to me on the basis of satisfactory evidence to be the individuals whose names are subscribed to the within instrument and acknowledged to me that they executed the same in their respective capacities, and that by their signatures on the instrument, the individuals executed the instrument.

/s/Felicia H. Powell    

Felicia H. Powell

Notary Public

State of Georgia

County of Fulton

My commission expires: June 20, 2026

RECORDING DATA

This Supplemental Indenture was recorded on the following dates in the office of the Recorder of Deeds in certain counties in the State of Illinois, as follows:

County	Document No.	Date Recorded
Cook	2320815024	07/27/2023
Adams	2023R-04033	07/14/2023
Boone	2023R02730	07/14/2023
Bureau	2023R02256	07/14/2023
Carroll	2023R-1374	07/14/2023
Champaign	2023R09607	07/14/2023
DeKalb	2023004766	07/19/2023
DeWitt	265190	07/14/2023
DuPage	R2023-044182	07/14/2023
Ford	2023-281634	07/17/2023
Grundy	620439	07/14/2023
Hancock	2023-1532	07/17/2023
Henderson	2023185999	07/14/2023
Henry	20-2303079	07/14/2023
Iroquois	23R1950	07/14/2023
Jo Daviess	427434	07/14/2023
Kane	2023K023567	07/14/2023
Kankakee	202306369	07/14/2023
Kendall	202300007716	07/14/2023
Lake	7986357	07/25/2023
LaSalle	2023-07005	07/17/2023
Lee	2023002273	07/14/2023
Livingston	2023R-02513	07/14/2023
McHenry	2023R0017028	07/14/2023
McLean	2023-00009355	07/19/2023
Mercer	2023-408508	07/14/2023
Ogle	202302992	07/14/2023
Piatt	380672	07/17/2023
Pike	2023-1397	07/14/2023
Rock Island	2023-08650	07/14/2023
Stephenson	202300196724	07/14/2023
Tazewell	202300008768	07/17/2023
Vermillion	23-04057	07/14/2023
Whiteside	2023-03456	07/17/2023
Will	R2023035293	07/14/2023
Winnebago	2023015659	07/14/2023
Woodford	2302316	07/14/2023

EX-31.A1

Exhibit 31(a)1

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Christopher C. Womack, certify that:

1.I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 1, 2023

/s/Christopher C. Womack

Christopher C. Womack

President and
Chief Executive Officer

EX-31.A2

Exhibit 31(a)2

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Daniel S. Tucker, certify that:

1.I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 1, 2023

/s/Daniel S. Tucker

Daniel S. Tucker

Executive Vice President and Chief Financial Officer

EX-31.B1

Exhibit 31(b)1

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, J. Jeffrey Peoples, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Alabama Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 1, 2023

/s/J. Jeffrey Peoples

J. Jeffrey Peoples

Chairman, President and Chief Executive Officer

EX-31.B2

Exhibit 31(b)2

ALABAMA 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 Alabama Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 1, 2023

/s/Moses H. Feagin

Moses H. Feagin

Executive Vice President, Chief Financial Officer
and Treasurer

EX-31.C1

Exhibit 31(c)1

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Kimberly S. Greene, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Georgia Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 1, 2023

/s/Kimberly S. Greene

Kimberly S. Greene

Chairman, President and Chief Executive Officer

EX-31.C2

Exhibit 31(c)2

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Aaron P. Abramovitz, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Georgia Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 1, 2023

/s/Aaron P. Abramovitz

Aaron P. Abramovitz

Executive Vice President, Chief Financial Officer and Treasurer

EX-31.D1

Exhibit 31(d)1

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Anthony L. Wilson, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Mississippi Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 1, 2023

/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, Matthew P. Grice, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Mississippi Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 1, 2023

/s/Matthew P. Grice

Matthew P. Grice

Vice President, Treasurer and
Chief Financial Officer

EX-31.E1

Exhibit 31(e)1

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Christopher Cummiskey, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Southern Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 1, 2023

/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, Gary Kerr, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Southern Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 1, 2023

/s/Gary Kerr

Gary Kerr

Senior Vice President, Chief
Financial Officer and Treasurer

EX-31.F1

Exhibit 31(f)1

SOUTHERN COMPANY GAS

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, James Y. Kerr II, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Southern Company Gas;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 1, 2023

/s/James Y. Kerr II

James Y. Kerr II

Chairman, President and Chief

 Executive Officer

EX-31.F2

Exhibit 31(f)2

SOUTHERN COMPANY GAS

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Grace A. Kolvereid, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Southern Company Gas;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 1, 2023

/s/Grace A. Kolvereid

Grace A. Kolvereid

Executive Vice President, Chief Financial
Officer and Treasurer

EX-32.A

Exhibit 32(a)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of The Southern Company for the quarter ended September 30, 2023, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)such Quarterly Report on Form 10-Q of The Southern Company for the quarter ended September 30, 2023, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in such Quarterly Report on Form 10-Q of The Southern Company for the quarter ended September 30, 2023, fairly presents, in all material respects, the financial condition and results of operations of The Southern Company.

/s/Christopher C. Womack

Christopher C. Womack

President and
Chief Executive Officer

/s/Daniel S. Tucker

Daniel S. Tucker

Executive Vice President and
Chief Financial Officer

November 1, 2023

EX-32.B

Exhibit 32(b)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended September 30, 2023, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)such Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended September 30, 2023, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in such Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended September 30, 2023, fairly presents, in all material respects, the financial condition and results of operations of Alabama Power Company.

/s/J. Jeffrey Peoples

J. Jeffrey Peoples

Chairman, President and Chief Executive Officer

/s/Moses H. Feagin

Moses H. Feagin

Executive Vice President,
Chief Financial Officer and Treasurer

November 1, 2023

EX-32.C

Exhibit 32(c)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended September 30, 2023, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)such Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended September 30, 2023, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in such Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended September 30, 2023, fairly presents, in all material respects, the financial condition and results of operations of Georgia Power Company.

/s/Kimberly S. Greene

Kimberly S. Greene

Chairman, President and Chief Executive Officer

/s/Aaron P. Abramovitz

Aaron P. Abramovitz

Executive Vice President, Chief Financial Officer and Treasurer

November 1, 2023

EX-32.D

Exhibit 32(d)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended September 30, 2023, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)such Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended September 30, 2023, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in such Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended September 30, 2023, 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/Matthew P. Grice

Matthew P. Grice

Vice President, Treasurer and
Chief Financial Officer

November 1, 2023

EX-32.E

Exhibit 32(e)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended September 30, 2023, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)such Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended September 30, 2023, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in such Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended September 30, 2023, 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/Gary Kerr

Gary Kerr

Senior Vice President, Chief Financial Officer and Treasurer

November 1, 2023

EX-32.F

Exhibit 32(f)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Southern Company Gas for the quarter ended September 30, 2023, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)such Quarterly Report on Form 10-Q of Southern Company Gas for the quarter ended September 30, 2023, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in such Quarterly Report on Form 10-Q of Southern Company Gas for the quarter ended September 30, 2023, fairly presents, in all material respects, the financial condition and results of operations of Southern Company Gas.

/s/James Y. Kerr II

James Y. Kerr II

Chairman, President and Chief Executive Officer

/s/Grace A. Kolvereid

Grace A. Kolvereid

Executive Vice President, Chief Financial

Officer and Treasurer

November 1, 2023

XML

Cover Page	9 Months Ended
	Sep. 30, 2023 shares
Document Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2023
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 Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)	1,090,619,349
Entity Central Index Key	0000092122
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Common Stock, par value $5 per share
Document Information [Line Items]
Title of 12(b) Security	Common Stock, par value $5 per share
Trading Symbol	SO
Security Exchange Name	NYSE
Series 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
Series 2020A 4.95% Junior Subordinated Notes due 2080
Document Information [Line Items]
Title of 12(b) Security	Series 2020A 4.95% Junior Subordinated Notes due 2080
Trading Symbol	SOJD
Security Exchange Name	NYSE
Series 2020C 4.20% Junior Subordinated Notes due 2060
Document Information [Line Items]
Title of 12(b) Security	Series 2020C 4.20% Junior Subordinated Notes due 2060
Trading Symbol	SOJE
Security Exchange Name	NYSE
Series 2021B 1.875% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2081
Document Information [Line Items]
Title of 12(b) Security	Series 2021B 1.875% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2081
Trading Symbol	SO 81
Security Exchange Name	NYSE
ALABAMA POWER CO
Document Information [Line Items]
Entity File Number	1-3164
Entity Registrant Name	Alabama Power Company
Entity Tax Identification Number	63-0004250
Entity Incorporation, State or Country Code	AL
Entity Address, Address Line One	600 North 18th Street
Entity Address, City or Town	Birmingham
Entity Address, State or Province	AL
Entity Address, Postal Zip Code	35203
City Area Code	205
Local Phone Number	257-1000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)	30,537,500
Entity Central Index Key	0000003153
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 Small Business	false
Entity Emerging Growth Company	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 Small Business	false
Entity Emerging Growth Company	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 Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)	1,000
Entity Central Index Key	0001160661
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 Small Business	false
Entity Emerging Growth Company	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) - Southern - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Operating Revenues:
Total operating revenues	$ 6,980	$ 8,378	$ 19,208	$ 22,232
Operating Expenses:
Other operations and maintenance	1,424	1,527	4,352	4,568
Depreciation and amortization	1,143	922	3,365	2,728
Taxes other than income taxes	341	352	1,076	1,073
Estimated loss on Plant Vogtle Units 3 and 4	160	(70)	160	(18)
Total operating expenses	4,870	6,185	14,589	17,000
Operating Income	2,110	2,193	4,619	5,232
Other Income and (Expense):
Allowance for equity funds used during construction	66	59	200	163
Earnings from equity method investments	32	28	110	109
Interest expense, net of amounts capitalized	(620)	(511)	(1,812)	(1,461)
Other income (expense), net	141	132	428	414
Total other income and (expense)	(381)	(292)	(1,074)	(775)
Earnings Before Income Taxes	1,729	1,901	3,545	4,457
Income taxes	297	414	492	891
Net Income	1,432	1,487	3,053	3,566
Dividends on preferred stock of subsidiaries	0	3	0	10
Net income (loss) attributable to noncontrolling interests	10	12	(68)	(55)
Net Income	$ 1,422	$ 1,472	$ 3,121	$ 3,611
Earnings per share -
Basic (in dollars per share)	$ 1.30	$ 1.36	$ 2.86	$ 3.38
Diluted (in dollars per share)	$ 1.29	$ 1.35	$ 2.84	$ 3.36
Average number of shares of common stock outstanding — (in millions)
Basic (in shares)	1,092	1,082	1,092	1,070
Diluted (in shares)	1,099	1,088	1,098	1,076
Retail electric revenues
Operating Revenues:
Total operating revenues	$ 5,139	$ 5,961	$ 12,597	$ 14,363
Wholesale electric revenues
Operating Revenues:
Total operating revenues	727	1,197	1,930	2,798
Other electric revenues
Operating Revenues:
Total operating revenues	203	185	602	554
Natural Gas
Operating Revenues:
Total operating revenues	689	857	3,417	3,998
Other revenues
Operating Revenues:
Total operating revenues	222	178	662	519
Operating Expenses:
Total cost of sales	126	92	381	275
Fuel
Operating Expenses:
Total cost of sales	1,367	2,423	3,376	5,249
Purchased power
Operating Expenses:
Total cost of sales	207	645	680	1,285
Natural gas
Operating Expenses:
Total cost of sales	$ 102	$ 294	$ 1,199	$ 1,840

XML

Condensed Consolidated Statements of Income (Unaudited) - Southern (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Total operating revenues	$ 6,980	$ 8,378	$ 19,208	$ 22,232
Alternative revenue programs
Total operating revenues	$ 0	$ (1)	$ 11	$ 0

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - Southern - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Statement of Comprehensive Income [Abstract]
Consolidated Net Income	$ 1,432	$ 1,487	$ 3,053	$ 3,566
Qualifying hedges:
Changes in fair value, net of tax	2	0	(34)	(27)
Reclassification adjustment for amounts included in net income, net of tax	36	26	70	100
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	0	2	1	8
Total other comprehensive income	38	28	37	81
Comprehensive Income	1,470	1,515	3,090	3,647
Dividends on preferred stock of subsidiaries	0	3	0	10
Comprehensive income (loss) attributable to noncontrolling interests	10	12	(68)	(55)
Comprehensive Income	$ 1,460	$ 1,500	$ 3,158	$ 3,692

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - Southern (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Statement of Comprehensive Income [Abstract]
Changes in fair value, tax	$ 3	$ 2	$ (11)	$ (5)
Qualifying hedges, reclassification adjustment, tax	12	8	25	32
Reclassification adjustment for amounts included in net income, tax	$ 0	$ 1	$ 0	$ 3

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) - Southern - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Operating Activities:
Consolidated net income	$ 3,053	$ 3,566
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	3,699	3,084
Deferred income taxes	(52)	608
Utilization of federal investment tax credits	195	266
Allowance for equity funds used during construction	(200)	(163)
Pension, postretirement, and other employee benefits	(397)	(322)
Settlement of asset retirement obligations	(444)	(314)
Stock based compensation expense	119	116
Estimated loss on Plant Vogtle Units 3 and 4	160	(18)
Storm damage accruals	41	160
Natural gas cost under recovery – long-term	0	207
Retail fuel cost under recovery – long-term	(157)	(1,701)
Other, net	(67)	(119)
Changes in certain current assets and liabilities —
Receivables	524	(316)
Retail fuel cost under recovery	513	(104)
Fossil fuel stock	(254)	(76)
Materials and supplies	(271)	(138)
Natural gas cost under recovery	108	(124)
Other current assets	(32)	(310)
Accounts payable	(1,031)	805
Accrued taxes	376	167
Accrued compensation	(197)	(123)
Customer refunds	(177)	(52)
Natural gas cost over recovery	165	0
Other current liabilities	66	(82)
Net cash provided from operating activities	5,740	5,017
Investing Activities:
Property additions	(6,561)	(5,502)
Nuclear decommissioning trust fund purchases	(885)	(858)
Nuclear decommissioning trust fund sales	879	854
Proceeds from dispositions	165	120
Cost of removal, net of salvage	(421)	(518)
Construction payables	241	15
Other investing activities	(139)	(63)
Net cash used for investing activities	(6,721)	(5,952)
Financing Activities:
Increase (decrease) in notes payable, net	(298)	(349)
Proceeds —
Long-term debt	7,812	3,800
Short-term borrowings	250	1,200
Common stock	26	1,803
Redemptions and repurchases —
Long-term debt	(3,567)	(1,932)
Short-term borrowings	(850)	(900)
Capital contributions from noncontrolling interests	21	73
Distributions to noncontrolling interests	(148)	(175)
Payment of common stock dividends	(2,271)	(2,166)
Other financing activities	(141)	(235)
Net cash provided from financing activities	834	1,119
Net Change in Cash, Cash Equivalents, and Restricted Cash	(147)	184
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	2,037	1,829
Cash, Cash Equivalents, and Restricted Cash at End of Period	1,890	2,013
Supplemental Cash Flow Information:
Interest, net of amounts capitalized	1,694	1,425
Income taxes, net	11	160
Noncash transactions —
Accrued property additions at end of period	1,224	872
Right-of-use assets obtained under operating leases	76	27
Right-of-use assets obtained under finance leases	3	114
Reassessment of right-of-use assets under operating leases	$ 0	$ 40

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Condensed Consolidated Statements of Cash Flows (Unaudited) - Southern (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Statement of Cash Flows [Abstract]
Net cash paid for capitalized interest	$ 97	$ 74

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Condensed Consolidated Balance Sheets (Unaudited) - Southern - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Current Assets:
Cash and cash equivalents	$ 1,676	$ 1,917
Receivables —
Customer accounts	2,230	2,128
Unbilled revenues	547	1,012
Under recovered fuel clause revenues	757	10
Other accounts and notes	553	637
Accumulated provision for uncollectible accounts	(78)	(71)
Materials and supplies	1,913	1,664
Fossil fuel for generation	829	575
Natural gas for sale	406	438
Prepaid expenses	321	347
Assets from risk management activities, net of collateral	36	115
Regulatory assets – asset retirement obligations	358	332
Other regulatory assets	996	968
Other current assets	544	344
Total current assets	11,088	10,416
Property, Plant, and Equipment:
In service	125,573	117,529
Less: Accumulated depreciation	37,199	35,297
Plant in service, net of depreciation	88,374	82,232
Other utility plant, net	522	599
Nuclear fuel, at amortized cost	862	843
Construction work in progress	8,496	10,896
Total property, plant, and equipment	98,254	94,570
Other Property and Investments:
Goodwill	5,161	5,161
Nuclear decommissioning trusts, at fair value	2,207	2,145
Equity investments in unconsolidated subsidiaries	1,376	1,443
Other intangible assets, net of amortization	377	406
Miscellaneous property and investments	651	602
Total other property and investments	9,772	9,757
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,467	1,531
Deferred charges related to income taxes	889	866
Prepaid pension costs	2,574	2,290
Unamortized loss on reacquired debt	224	238
Deferred under recovered fuel clause revenues	1,279	2,056
Regulatory assets – asset retirement obligations, deferred	5,629	5,764
Other regulatory assets, deferred	5,666	5,918
Other deferred charges and assets	1,479	1,485
Total deferred charges and other assets	19,207	20,148
Total Assets	138,321	134,891
Current Liabilities:
Securities due within one year	3,076	4,285
Notes payable	1,726	2,609
Accounts payable	2,942	3,525
Customer deposits	511	502
Accrued taxes —
Accrued income taxes	177	60
Other accrued taxes	862	764
Accrued interest	573	614
Accrued compensation	936	1,127
Asset retirement obligations	727	694
Liabilities from risk management activities, net of collateral	232	178
Operating lease obligations	181	197
Natural gas cost over recovery	165	0
Other regulatory liabilities	163	382
Other current liabilities	943	787
Total current liabilities	13,214	15,724
Long-term Debt	56,003	50,656
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	10,774	10,036
Deferred credits related to income taxes	4,813	5,235
Accumulated deferred ITCs	2,071	2,133
Employee benefit obligations	1,184	1,238
Operating lease obligations, deferred	1,320	1,388
Asset retirement obligations, deferred	9,872	10,146
Other cost of removal obligations	1,940	1,903
Other regulatory liabilities, deferred	660	733
Other deferred credits and liabilities	1,166	1,167
Total deferred credits and other liabilities	33,800	33,979
Total Liabilities	103,017	100,359
Total Stockholders' Equity	35,304	34,532
Total Liabilities and Stockholders' Equity	$ 138,321	$ 134,891

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Condensed Consolidated Balance Sheets (Unaudited) - Southern (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Other intangible assets, amortization	$ 367	$ 340

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Condensed Consolidated Statements of Stockholders' Equity (Unaudited) - Southern - USD ($) shares in Millions, $ in Millions	Total	Common Stock	Treasury	Paid-In Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests
Beginning balance (in shares) at Dec. 31, 2021		1,061
Beginning balance (in shares) at Dec. 31, 2021			(1)
Beginning balance at Dec. 31, 2021	$ 32,276	$ 5,279	$ (47)	$ 11,950	$ 10,929	$ (237)	$ 4,402
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated net income (loss)	987				1,032		(45)
Other comprehensive income	42					42
Stock issued (in shares)		3
Stock issued	38	$ 7		31
Stock-based compensation	6			6
Cash dividends on common stock	(702)				(702)
Capital contributions from noncontrolling interests	73						73
Distributions to noncontrolling interests	(98)						(98)
Other	7		$ (2)	7	2
Ending balance (in shares) at Mar. 31, 2022		1,064
Ending balance (in shares) at Mar. 31, 2022			(1)
Ending balance at Mar. 31, 2022	32,629	$ 5,286	$ (49)	11,994	11,261	(195)	4,332
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated net income (loss)	1,085				1,107		(22)
Other comprehensive income	11					11
Stock issued	23	$ 2		21
Stock-based compensation	14			14
Cash dividends on common stock	(723)				(723)
Distributions to noncontrolling interests	(28)						(28)
Other	2		$ (2)	4
Ending balance (in shares) at Jun. 30, 2022		1,064
Ending balance (in shares) at Jun. 30, 2022			(1)
Ending balance at Jun. 30, 2022	33,013	$ 5,288	$ (51)	12,033	11,645	(184)	4,282
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated net income (loss)	1,484				1,472		12
Other comprehensive income	28					28
Stock issued (in shares)		26
Stock issued	1,742	$ 129		1,613
Stock-based compensation	15			15
Cash dividends on common stock	(741)				(741)
Distributions to noncontrolling interests	(57)						(57)
Other	(8)		$ (1)	(4)	(2)	(1)
Ending balance (in shares) at Sep. 30, 2022		1,090
Ending balance (in shares) at Sep. 30, 2022			(1)
Ending balance at Sep. 30, 2022	35,476	$ 5,417	$ (52)	13,657	12,374	(157)	4,237
Beginning balance (in shares) at Dec. 31, 2022		1,090
Beginning balance (in shares) at Dec. 31, 2022			(1)
Beginning balance at Dec. 31, 2022	34,532	$ 5,417	$ (53)	13,673	11,538	(167)	4,124
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated net income (loss)	799				862		(63)
Other comprehensive income	(44)					(44)
Stock issued (in shares)		2
Stock issued	15	$ 4		11
Stock-based compensation	29			29
Cash dividends on common stock	(742)				(742)
Capital contributions from noncontrolling interests	21						21
Distributions to noncontrolling interests	(48)						(48)
Other	0		$ (2)	2
Ending balance (in shares) at Mar. 31, 2023		1,092
Ending balance (in shares) at Mar. 31, 2023			(1)
Ending balance at Mar. 31, 2023	34,562	$ 5,421	$ (55)	13,715	11,658	(211)	4,034
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated net income (loss)	823				838		(15)
Other comprehensive income	43					43
Stock issued	7	$ 1		6
Stock-based compensation	19			19
Cash dividends on common stock	(764)				(764)
Distributions to noncontrolling interests	(42)						(42)
Other	0		$ (1)	2			(1)
Ending balance (in shares) at Jun. 30, 2023		1,092
Ending balance (in shares) at Jun. 30, 2023			(1)
Ending balance at Jun. 30, 2023	34,648	$ 5,422	$ (56)	13,742	11,732	(168)	3,976
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated net income (loss)	1,432				1,422		10
Other comprehensive income	38					38
Stock issued	4			4
Stock-based compensation	7			7
Cash dividends on common stock	(765)				(765)
Distributions to noncontrolling interests	(59)						(59)
Other	(1)		$ (1)	(2)	2
Ending balance (in shares) at Sep. 30, 2023		1,092
Ending balance (in shares) at Sep. 30, 2023			(1)
Ending balance at Sep. 30, 2023	$ 35,304	$ 5,422	$ (57)	$ 13,751	$ 12,391	$ (130)	$ 3,927

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Condensed Consolidated Statements of Stockholders' Equity (Unaudited) - Southern (Parenthetical) - $ / shares	3 Months Ended
	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022
Statement of Stockholders' Equity [Abstract]
Cash dividends (in dollars per share)	$ 0.70	$ 0.70	$ 0.68	$ 0.68	$ 0.68	$ 0.66

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Condensed Statements of Income (Unaudited) - APC - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Operating Revenues:
Total operating revenues	$ 6,980	$ 8,378	$ 19,208	$ 22,232
Operating Expenses:
Other operations and maintenance	1,424	1,527	4,352	4,568
Depreciation and amortization	1,143	922	3,365	2,728
Taxes other than income taxes	341	352	1,076	1,073
Total operating expenses	4,870	6,185	14,589	17,000
Operating Income	2,110	2,193	4,619	5,232
Other Income and (Expense):
Allowance for equity funds used during construction	66	59	200	163
Interest expense, net of amounts capitalized	(620)	(511)	(1,812)	(1,461)
Total other income (expense), net	141	132	428	414
Total other income and (expense)	(381)	(292)	(1,074)	(775)
Earnings Before Income Taxes	1,729	1,901	3,545	4,457
Income taxes	297	414	492	891
Consolidated Net Income	1,432	1,487	3,053	3,566
Dividends on preferred stock of subsidiaries	0	3	0	10
Net Income	1,422	1,472	3,121	3,611
Retail electric revenues
Operating Revenues:
Total operating revenues	5,139	5,961	12,597	14,363
Wholesale electric revenues
Operating Revenues:
Total operating revenues	727	1,197	1,930	2,798
Other electric revenues
Operating Revenues:
Total operating revenues	203	185	602	554
Natural Gas
Operating Revenues:
Total operating revenues	689	857	3,417	3,998
Other revenues
Operating Revenues:
Total operating revenues	222	178	662	519
Operating Expenses:
Total cost of sales	126	92	381	275
Fuel
Operating Expenses:
Total cost of sales	1,367	2,423	3,376	5,249
Purchased power
Operating Expenses:
Total cost of sales	207	645	680	1,285
Alabama Power
Operating Revenues:
Total operating revenues	2,083	2,444	5,420	6,023
Operating Expenses:
Other operations and maintenance	411	418	1,275	1,270
Depreciation and amortization	351	220	1,045	652
Taxes other than income taxes	110	106	333	309
Total operating expenses	1,396	1,708	4,056	4,237
Operating Income	687	736	1,364	1,786
Other Income and (Expense):
Allowance for equity funds used during construction	23	18	65	51
Interest expense, net of amounts capitalized	(104)	(98)	(311)	(278)
Total other income (expense), net	38	38	117	101
Total other income and (expense)	(43)	(42)	(129)	(126)
Earnings Before Income Taxes	644	694	1,235	1,660
Income taxes	79	166	103	394
Consolidated Net Income	565	528	1,132	1,266
Dividends on preferred stock of subsidiaries	0	3	0	10
Net Income	565	525	1,132	1,256
Alabama Power | Retail electric revenues
Operating Revenues:
Total operating revenues	1,860	2,008	4,708	5,015
Alabama Power | Wholesale revenues, non-affiliates
Operating Revenues:
Total operating revenues	106	250	358	522
Alabama Power | Wholesale revenues, affiliates
Operating Revenues:
Total operating revenues	14	70	43	170
Alabama Power | Other revenues
Operating Revenues:
Total operating revenues	103	116	311	316
Alabama Power | Fuel
Operating Expenses:
Total cost of sales	402	666	1,013	1,399
Alabama Power | Purchased power
Operating Expenses:
Total cost of sales	42	185	197	347
Alabama Power | Purchased power, affiliates
Operating Expenses:
Total cost of sales	$ 80	$ 113	$ 193	$ 260

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Condensed Statements of Comprehensive Income (Unaudited) - APC - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Consolidated Net Income	$ 1,432	$ 1,487	$ 3,053	$ 3,566
Qualifying hedges:
Changes in fair value, net of tax	2	0	(34)	(27)
Reclassification adjustment for amounts included in net income, net of tax	36	26	70	100
Total other comprehensive income	38	28	37	81
Comprehensive Income	1,470	1,515	3,090	3,647
Alabama Power
Consolidated Net Income	565	528	1,132	1,266
Qualifying hedges:
Changes in fair value, net of tax	0	1	1	(1)
Reclassification adjustment for amounts included in net income, net of tax	1	1	1	3
Total other comprehensive income	1	2	2	2
Comprehensive Income	$ 566	$ 530	$ 1,134	$ 1,268

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Condensed Statements of Comprehensive Income (Unaudited) - APC (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Changes in fair value, tax	$ 3	$ 2	$ (11)	$ (5)
Qualifying hedges, reclassification adjustment, tax	12	8	25	32
Alabama Power
Changes in fair value, tax	0	0	0	0
Qualifying hedges, reclassification adjustment, tax	$ 0	$ 0	$ 0	$ 1

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Condensed Statements of Cash Flows (Unaudited) - APC - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Operating Activities:
Consolidated net income	$ 3,053	$ 3,566
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	3,699	3,084
Deferred income taxes	(52)	608
Pension, postretirement, and other employee benefits	(397)	(322)
Settlement of asset retirement obligations	(444)	(314)
Retail fuel cost under recovery – long-term	(157)	(1,701)
Other, net	(67)	(119)
Changes in certain current assets and liabilities —
Receivables	524	(316)
Fossil fuel stock	(254)	(76)
Retail fuel cost under recovery	513	(104)
Other current assets	(32)	(310)
Accounts payable	(1,031)	805
Accrued taxes	376	167
Accrued compensation	(197)	(123)
Other current liabilities	66	(82)
Net cash provided from operating activities	5,740	5,017
Investing Activities:
Property additions	(6,561)	(5,502)
Nuclear decommissioning trust fund purchases	(885)	(858)
Nuclear decommissioning trust fund sales	879	854
Cost of removal, net of salvage	(421)	(518)
Change in construction payables, net	241	15
Other investing activities	(139)	(63)
Net cash used for investing activities	(6,721)	(5,952)
Financing Activities:
Payment of common stock dividends	(2,271)	(2,166)
Other financing activities	(141)	(235)
Net cash provided from financing activities	834	1,119
Net Change in Cash, Cash Equivalents, and Restricted Cash	(147)	184
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	2,037	1,829
Cash, Cash Equivalents, and Restricted Cash at End of Period	1,890	2,013
Supplemental Cash Flow Information:
Interest, net of amounts capitalized	1,694	1,425
Income taxes, net	11	160
Noncash transactions —
Accrued property additions at end of period	1,224	872
Right-of-use assets obtained under finance leases	3	114
Alabama Power
Operating Activities:
Consolidated net income	1,132	1,266
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	1,158	817
Deferred income taxes	(210)	210
Pension, postretirement, and other employee benefits	(148)	(85)
Settlement of asset retirement obligations	(188)	(139)
Retail fuel cost under recovery – long-term	0	(413)
Other, net	(21)	(98)
Changes in certain current assets and liabilities —
Receivables	(108)	(296)
Fossil fuel stock	(113)	(40)
Retail fuel cost under recovery	334	(93)
Other current assets	(124)	(75)
Accounts payable	(358)	(22)
Accrued taxes	271	110
Other current liabilities	(103)	(70)
Net cash provided from operating activities	1,522	1,072
Investing Activities:
Property additions	(1,377)	(1,483)
Nuclear decommissioning trust fund purchases	(226)	(273)
Nuclear decommissioning trust fund sales	226	273
Cost of removal, net of salvage	(128)	(163)
Change in construction payables, net	(68)	36
Other investing activities	27	(31)
Net cash used for investing activities	(1,546)	(1,641)
Financing Activities:
Proceeds — Senior notes	200	1,700
Revenue bonds	326	0
Other long-term debt	28	0
Redemptions — Senior notes	0	(550)
Capital contributions from parent company	380	660
Payment of common stock dividends	(856)	(762)
Other financing activities	(12)	(81)
Net cash provided from financing activities	66	967
Net Change in Cash, Cash Equivalents, and Restricted Cash	42	398
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	687	1,060
Cash, Cash Equivalents, and Restricted Cash at End of Period	729	1,458
Supplemental Cash Flow Information:
Interest, net of amounts capitalized	329	278
Income taxes, net	152	178
Noncash transactions —
Accrued property additions at end of period	114	186
Right-of-use assets obtained under operating leases	28	7
Right-of-use assets obtained under finance leases	$ 3	$ 2

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Condensed Statements of Cash Flows (Unaudited) - APC (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Net cash paid for capitalized interest	$ 97	$ 74
Alabama Power
Net cash paid for capitalized interest	$ 21	$ 14

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Condensed Balance Sheets (Unaudited) - APC - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Current Assets:
Cash and cash equivalents	$ 1,676	$ 1,917
Receivables —
Customer accounts, net and Affiliated	2,230	2,128
Unbilled revenues	547	1,012
Other accounts and notes	553	637
Accumulated provision for uncollectible accounts	(78)	(71)
Fossil fuel stock	829	575
Materials and supplies	1,913	1,664
Prepaid expenses	321	347
Other regulatory assets	996	968
Other current assets	544	344
Total current assets	11,088	10,416
Property, Plant, and Equipment:
In service	125,573	117,529
Less: Accumulated depreciation	37,199	35,297
Plant in service, net of depreciation	88,374	82,232
Other utility plant, net	522	599
Nuclear fuel, at amortized cost	862	843
Construction work in progress	8,496	10,896
Total property, plant, and equipment	98,254	94,570
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	2,207	2,145
Equity investments in unconsolidated subsidiaries	1,376	1,443
Miscellaneous property and investments	651	602
Total other property and investments	9,772	9,757
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,467	1,531
Deferred charges related to income taxes	889	866
Regulatory assets – asset retirement obligations	5,629	5,764
Other regulatory assets, deferred	5,666	5,918
Other deferred charges and assets	1,479	1,485
Total deferred charges and other assets	19,207	20,148
Total Assets	138,321	134,891
Current Liabilities:
Securities due within one year	3,076	4,285
Accounts payable —
Customer deposits	511	502
Accrued interest	573	614
Accrued compensation	936	1,127
Asset retirement obligations	727	694
Other regulatory liabilities	163	382
Other current liabilities	943	787
Total current liabilities	13,214	15,724
Long-term Debt	56,003	50,656
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	10,774	10,036
Deferred credits related to income taxes	4,813	5,235
Accumulated deferred ITCs	2,071	2,133
Employee benefit obligations	1,184	1,238
Operating lease obligations, deferred	1,320	1,388
Asset retirement obligations, deferred	9,872	10,146
Other regulatory liabilities, deferred	660	733
Other deferred credits and liabilities	1,166	1,167
Total deferred credits and other liabilities	33,800	33,979
Total Liabilities	103,017	100,359
Total Stockholders' Equity	35,304	34,532
Total Liabilities and Stockholders' Equity	138,321	134,891
Alabama Power
Current Assets:
Cash and cash equivalents	621	687
Receivables —
Unbilled revenues	162	174
Other accounts and notes	114	153
Accumulated provision for uncollectible accounts	(16)	(14)
Fossil fuel stock	342	229
Materials and supplies	624	557
Prepaid expenses	72	65
Other regulatory assets	549	474
Other current assets	171	67
Total current assets	3,376	2,924
Property, Plant, and Equipment:
In service	34,313	33,472
Less: Accumulated depreciation	11,042	10,470
Plant in service, net of depreciation	23,271	23,002
Other utility plant, net	522	599
Nuclear fuel, at amortized cost	240	239
Construction work in progress	1,759	1,526
Total property, plant, and equipment	25,792	25,366
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,165	1,127
Equity investments in unconsolidated subsidiaries	53	57
Miscellaneous property and investments	156	124
Total other property and investments	1,374	1,308
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	88	71
Deferred charges related to income taxes	263	250
Prepaid pension and other postretirement benefit costs	735	657
Regulatory assets – asset retirement obligations	1,881	1,845
Other regulatory assets, deferred	1,706	2,107
Other deferred charges and assets	455	442
Total deferred charges and other assets	5,128	5,372
Total Assets	35,670	34,970
Current Liabilities:
Securities due within one year	522	301
Accounts payable —
Customer deposits	105	106
Accrued taxes	305	57
Accrued interest	84	120
Accrued compensation	193	229
Asset retirement obligations	342	330
Other regulatory liabilities	28	96
Other current liabilities	158	91
Total current liabilities	2,419	2,414
Long-term Debt	10,661	10,329
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	4,082	3,981
Deferred credits related to income taxes	1,626	1,925
Accumulated deferred ITCs	76	81
Employee benefit obligations	146	145
Operating lease obligations, deferred	81	67
Asset retirement obligations, deferred	3,859	3,957
Other regulatory liabilities, deferred	284	315
Other deferred credits and liabilities	85	69
Total deferred credits and other liabilities	10,239	10,540
Total Liabilities	23,319	23,283
Total Stockholders' Equity	12,351	11,687
Total Liabilities and Stockholders' Equity	35,670	34,970
Alabama Power | Nonrelated Party
Receivables —
Customer accounts, net and Affiliated	624	431
Accounts payable —
Affiliated and Other	377	641
Alabama Power | Related Party
Receivables —
Customer accounts, net and Affiliated	113	101
Accounts payable —
Affiliated and Other	$ 305	$ 443

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Condensed Statements of Common Stockholders' Equity (Unaudited) - APC - USD ($) shares in Millions, $ in Millions	Total	Common Stock	Paid-In Capital	Retained Earnings (Accumulated Deficit)	Accumulated Other Comprehensive Income (Loss)	Alabama Power	Alabama Power Common Stock	Alabama Power Paid-In Capital	Alabama Power Retained Earnings (Accumulated Deficit)	Alabama Power Accumulated Other Comprehensive Income (Loss)
Beginning balance (in shares) at Dec. 31, 2021							31
Beginning balance at Dec. 31, 2021	$ 32,276	$ 5,279	$ 11,950	$ 10,929	$ (237)	$ 10,713	$ 1,222	$ 6,056	$ 3,448	$ (13)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income						347			347
Capital contributions from parent company						626		626
Other comprehensive income	42				42
Cash dividends on common stock	(702)			(702)		(254)			(254)
Ending balance (in shares) at Mar. 31, 2022							31
Ending balance at Mar. 31, 2022	32,629	5,286	11,994	11,261	(195)	11,432	$ 1,222	6,682	3,541	(13)
Beginning balance (in shares) at Dec. 31, 2021							31
Beginning balance at Dec. 31, 2021	32,276	5,279	11,950	10,929	(237)	10,713	$ 1,222	6,056	3,448	(13)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	3,611					1,256
Ending balance (in shares) at Sep. 30, 2022							31
Ending balance at Sep. 30, 2022	35,476	5,417	13,657	12,374	(157)	11,874	$ 1,222	6,721	3,941	(10)
Beginning balance (in shares) at Mar. 31, 2022							31
Beginning balance at Mar. 31, 2022	32,629	5,286	11,994	11,261	(195)	11,432	$ 1,222	6,682	3,541	(13)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income						383			383
Capital contributions from parent company						32		32
Other comprehensive income	11				11	1				1
Cash dividends on common stock	(723)			(723)		(254)			(254)
Ending balance (in shares) at Jun. 30, 2022							31
Ending balance at Jun. 30, 2022	33,013	5,288	12,033	11,645	(184)	11,594	$ 1,222	6,714	3,670	(12)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	1,472					525			525
Capital contributions from parent company						7		7
Other comprehensive income	28				28	2				2
Cash dividends on common stock	(741)			(741)		(254)			(254)
Ending balance (in shares) at Sep. 30, 2022							31
Ending balance at Sep. 30, 2022	35,476	5,417	13,657	12,374	(157)	11,874	$ 1,222	6,721	3,941	(10)
Beginning balance (in shares) at Dec. 31, 2022							31
Beginning balance at Dec. 31, 2022	34,532	5,417	13,673	11,538	(167)	11,687	$ 1,222	6,710	3,764	(9)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income						255			255
Capital contributions from parent company						330		330
Other comprehensive income	(44)				(44)
Cash dividends on common stock	(742)			(742)		(285)			(285)
Ending balance (in shares) at Mar. 31, 2023							31
Ending balance at Mar. 31, 2023	34,562	5,421	13,715	11,658	(211)	11,987	$ 1,222	7,040	3,734	(9)
Beginning balance (in shares) at Dec. 31, 2022							31
Beginning balance at Dec. 31, 2022	34,532	5,417	13,673	11,538	(167)	11,687	$ 1,222	6,710	3,764	(9)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	3,121					1,132
Ending balance (in shares) at Sep. 30, 2023							31
Ending balance at Sep. 30, 2023	35,304	5,422	13,751	12,391	(130)	12,351	$ 1,222	7,097	4,040	(8)
Beginning balance (in shares) at Mar. 31, 2023							31
Beginning balance at Mar. 31, 2023	34,562	5,421	13,715	11,658	(211)	11,987	$ 1,222	7,040	3,734	(9)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income						312			312
Capital contributions from parent company						29		29
Other comprehensive income	43				43
Cash dividends on common stock	(764)			(764)		(286)			(286)
Ending balance (in shares) at Jun. 30, 2023							31
Ending balance at Jun. 30, 2023	34,648	5,422	13,742	11,732	(168)	12,042	$ 1,222	7,069	3,760	(9)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	1,422					565			565
Capital contributions from parent company						28		28
Other comprehensive income	38				38	1				1
Cash dividends on common stock	(765)			(765)		(285)			(285)
Ending balance (in shares) at Sep. 30, 2023							31
Ending balance at Sep. 30, 2023	$ 35,304	$ 5,422	$ 13,751	$ 12,391	$ (130)	$ 12,351	$ 1,222	$ 7,097	$ 4,040	$ (8)

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Condensed Statements of Income (Unaudited) - GPC - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Operating Revenues:
Total operating revenues	$ 6,980	$ 8,378	$ 19,208	$ 22,232
Operating Expenses:
Other operations and maintenance	1,424	1,527	4,352	4,568
Depreciation and amortization	1,143	922	3,365	2,728
Taxes other than income taxes	341	352	1,076	1,073
Estimated loss on Plant Vogtle Units 3 and 4	160	(70)	160	(18)
Total operating expenses	4,870	6,185	14,589	17,000
Operating Income	2,110	2,193	4,619	5,232
Other Income and (Expense):
Allowance for equity funds used during construction	66	59	200	163
Interest expense, net of amounts capitalized	(620)	(511)	(1,812)	(1,461)
Other income (expense), net	141	132	428	414
Total other income and (expense)	(381)	(292)	(1,074)	(775)
Earnings Before Income Taxes	1,729	1,901	3,545	4,457
Income taxes	297	414	492	891
Net Income	1,432	1,487	3,053	3,566
Retail electric revenues
Operating Revenues:
Total operating revenues	5,139	5,961	12,597	14,363
Wholesale electric revenues
Operating Revenues:
Total operating revenues	727	1,197	1,930	2,798
Other electric revenues
Operating Revenues:
Total operating revenues	203	185	602	554
Natural Gas
Operating Revenues:
Total operating revenues	689	857	3,417	3,998
Other revenues
Operating Revenues:
Total operating revenues	222	178	662	519
Operating Expenses:
Cost of Goods and Services Sold	126	92	381	275
Fuel
Operating Expenses:
Cost of Goods and Services Sold	1,367	2,423	3,376	5,249
Purchased power
Operating Expenses:
Cost of Goods and Services Sold	207	645	680	1,285
GEORGIA POWER CO
Operating Revenues:
Total operating revenues	3,237	3,889	7,805	9,218
Operating Expenses:
Other operations and maintenance	512	595	1,505	1,686
Depreciation and amortization	429	359	1,248	1,066
Taxes other than income taxes	144	155	406	420
Estimated loss on Plant Vogtle Units 3 and 4	160	(70)	160	(18)
Total operating expenses	2,173	2,755	5,687	6,841
Operating Income	1,064	1,134	2,118	2,377
Other Income and (Expense):
Allowance for equity funds used during construction	37	37	121	102
Interest expense, net of amounts capitalized	(166)	(123)	(472)	(347)
Other income (expense), net	45	36	125	140
Total other income and (expense)	(84)	(50)	(226)	(105)
Earnings Before Income Taxes	980	1,084	1,892	2,272
Income taxes	200	226	345	421
Net Income	780	858	1,547	1,851
GEORGIA POWER CO | Retail electric revenues
Operating Revenues:
Total operating revenues	2,996	3,703	7,142	8,629
GEORGIA POWER CO | Wholesale electric revenues
Operating Revenues:
Total operating revenues	69	56	147	186
GEORGIA POWER CO | Other revenues
Operating Revenues:
Total operating revenues	172	130	516	403
GEORGIA POWER CO | Fuel
Operating Expenses:
Cost of Goods and Services Sold	576	841	1,392	1,887
GEORGIA POWER CO | Purchased power
Operating Expenses:
Cost of Goods and Services Sold	131	304	397	700
GEORGIA POWER CO | Purchased power, affiliates
Operating Expenses:
Cost of Goods and Services Sold	$ 221	$ 571	$ 579	$ 1,100

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Condensed Statements of Comprehensive Income (Unaudited) - GPC - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Consolidated Net Income	$ 1,432	$ 1,487	$ 3,053	$ 3,566
Qualifying hedges:
Changes in fair value, net of tax	2	0	(34)	(27)
Reclassification adjustment for amounts included in net income, net of tax	36	26	70	100
Total other comprehensive income	38	28	37	81
Comprehensive Income	1,470	1,515	3,090	3,647
GEORGIA POWER CO
Consolidated Net Income	780	858	1,547	1,851
Qualifying hedges:
Changes in fair value, net of tax	0	0	(1)	23
Reclassification adjustment for amounts included in net income, net of tax	1	1	3	4
Total other comprehensive income	1	1	2	27
Comprehensive Income	$ 781	$ 859	$ 1,549	$ 1,878

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Condensed Statements of Comprehensive Income (Unaudited) - GPC (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Changes in fair value, tax	$ 3	$ 2	$ (11)	$ (5)
Qualifying hedges, reclassification adjustment, tax	12	8	25	32
GEORGIA POWER CO
Changes in fair value, tax	0	0	(1)	8
Qualifying hedges, reclassification adjustment, tax	$ 0	$ 0	$ 1	$ 1

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Condensed Statements of Cash Flows (Unaudited) - GPC - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Operating Activities:
Consolidated net income	$ 3,053	$ 3,566
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	3,699	3,084
Deferred income taxes	(52)	608
Allowance for equity funds used during construction	(200)	(163)
Pension, postretirement, and other employee benefits	(397)	(322)
Settlement of asset retirement obligations	(444)	(314)
Storm damage accruals	41	160
Retail fuel cost under recovery – long-term	(157)	(1,701)
Estimated loss on Plant Vogtle Units 3 and 4	160	(18)
Other, net	(67)	(119)
Changes in certain current assets and liabilities —
Receivables	524	(316)
Retail fuel cost under recovery	513	(104)
Fossil fuel stock	(254)	(76)
Materials and supplies	(271)	(138)
Other current assets	(32)	(310)
Accounts payable	(1,031)	805
Accrued taxes	376	167
Customer refunds	(177)	(52)
Other current liabilities	66	(82)
Net cash provided from operating activities	5,740	5,017
Investing Activities:
Property additions	(6,561)	(5,502)
Nuclear decommissioning trust fund purchases	(885)	(858)
Nuclear decommissioning trust fund sales	879	854
Cost of removal, net of salvage	(421)	(518)
Proceeds from dispositions	165	120
Other investing activities	(139)	(63)
Net cash used for investing activities	(6,721)	(5,952)
Proceeds —
Short-term borrowings	250	1,200
Redemptions and repurchases —
Short-term borrowings	(850)	(900)
Payment of common stock dividends	(2,271)	(2,166)
Other financing activities	(141)	(235)
Net cash provided from financing activities	834	1,119
Net Change in Cash, Cash Equivalents, and Restricted Cash	(147)	184
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	2,037	1,829
Cash, Cash Equivalents, and Restricted Cash at End of Period	1,890	2,013
Supplemental Cash Flow Information:
Interest, net of amounts capitalized	1,694	1,425
Income taxes, net	11	160
Noncash transactions —
Accrued property additions at end of period	1,224	872
Right-of-use assets obtained under operating leases	76	27
Right-of-use assets obtained under finance leases	3	114
GEORGIA POWER CO
Operating Activities:
Consolidated net income	1,547	1,851
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	1,411	1,211
Deferred income taxes	102	266
Allowance for equity funds used during construction	(121)	(102)
Pension, postretirement, and other employee benefits	(207)	(178)
Settlement of asset retirement obligations	(228)	(149)
Storm damage accruals	24	160
Retail fuel cost under recovery – long-term	(157)	(1,287)
Estimated loss on Plant Vogtle Units 3 and 4	160	(18)
Other, net	(12)	(22)
Changes in certain current assets and liabilities —
Receivables	(311)	(321)
Retail fuel cost under recovery	204	0
Fossil fuel stock	(138)	(23)
Materials and supplies	(135)	(67)
Contract assets	(57)	(51)
Other current assets	16	(72)
Accounts payable	(142)	211
Accrued taxes	118	151
Customer refunds	(121)	1
Other current liabilities	16	(79)
Net cash provided from operating activities	1,969	1,482
Investing Activities:
Property additions	(3,501)	(2,556)
Nuclear decommissioning trust fund purchases	(659)	(585)
Nuclear decommissioning trust fund sales	654	581
Cost of removal, net of salvage	(191)	(250)
Change in construction payables, net of joint owner portion	338	148
Proceeds from dispositions	59	56
Other investing activities	(76)	(47)
Net cash used for investing activities	(3,376)	(2,653)
Financing Activities:
Increase in notes payable, net	50	415
Proceeds —
Proceeds — Senior notes	1,750	1,500
Short-term borrowings	250	650
Revenue bonds	229	0
Redemptions and repurchases —
Redemptions — Senior notes	(800)	(400)
Short-term borrowings	(650)	(250)
FFB loan	(64)	(66)
Revenue bonds	0	(53)
Other long-term debt	0	(125)
Capital contributions from parent company	1,837	813
Payment of common stock dividends	(1,392)	(1,268)
Other financing activities	(27)	(45)
Net cash provided from financing activities	1,183	1,171
Net Change in Cash, Cash Equivalents, and Restricted Cash	(224)	0
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	480	33
Cash, Cash Equivalents, and Restricted Cash at End of Period	256	33
Supplemental Cash Flow Information:
Interest, net of amounts capitalized	439	332
Income taxes, net	74	151
Noncash transactions —
Accrued property additions at end of period	942	609
Right-of-use assets obtained under operating leases	17	7
Right-of-use assets obtained under finance leases	18	112
ALABAMA POWER CO
Operating Activities:
Consolidated net income	1,132	1,266
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	1,158	817
Deferred income taxes	(210)	210
Allowance for equity funds used during construction	(65)	(51)
Pension, postretirement, and other employee benefits	(148)	(85)
Settlement of asset retirement obligations	(188)	(139)
Retail fuel cost under recovery – long-term	0	(413)
Other, net	(21)	(98)
Changes in certain current assets and liabilities —
Receivables	(108)	(296)
Retail fuel cost under recovery	334	(93)
Fossil fuel stock	(113)	(40)
Other current assets	(124)	(75)
Accounts payable	(358)	(22)
Accrued taxes	271	110
Other current liabilities	(103)	(70)
Net cash provided from operating activities	1,522	1,072
Investing Activities:
Property additions	(1,377)	(1,483)
Nuclear decommissioning trust fund purchases	(226)	(273)
Nuclear decommissioning trust fund sales	226	273
Cost of removal, net of salvage	(128)	(163)
Other investing activities	27	(31)
Net cash used for investing activities	(1,546)	(1,641)
Proceeds —
Proceeds — Senior notes	200	1,700
Redemptions and repurchases —
Redemptions — Senior notes	0	(550)
Capital contributions from parent company	380	660
Payment of common stock dividends	(856)	(762)
Other financing activities	(12)	(81)
Net cash provided from financing activities	66	967
Net Change in Cash, Cash Equivalents, and Restricted Cash	42	398
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	687	1,060
Cash, Cash Equivalents, and Restricted Cash at End of Period	729	1,458
Supplemental Cash Flow Information:
Interest, net of amounts capitalized	329	278
Income taxes, net	152	178
Noncash transactions —
Accrued property additions at end of period	114	186
Right-of-use assets obtained under finance leases	$ 3	$ 2

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Condensed Statements of Cash Flows (Unaudited) - GPC (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Net cash paid for capitalized interest	$ 97	$ 74
GEORGIA POWER CO
Net cash paid for capitalized interest	$ 63	$ 52

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Condensed Balance Sheets (Unaudited) - GPC - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Current Assets:
Cash and cash equivalents	$ 1,676	$ 1,917
Receivables —
Customer accounts, net and Affiliated	2,230	2,128
Unbilled revenues	547	1,012
Other accounts and notes	553	637
Fossil fuel stock	829	575
Materials and supplies	1,913	1,664
Regulatory assets – asset retirement obligations	358	332
Other regulatory assets	996	968
Other current assets	544	344
Total current assets	11,088	10,416
Property, Plant, and Equipment:
In service	125,573	117,529
Less: Accumulated depreciation	37,199	35,297
Plant in service, net of depreciation	88,374	82,232
Nuclear fuel, at amortized cost	862	843
Construction work in progress	8,496	10,896
Total property, plant, and equipment	98,254	94,570
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	2,207	2,145
Equity investments in unconsolidated subsidiaries	1,376	1,443
Miscellaneous property and investments	651	602
Total other property and investments	9,772	9,757
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,467	1,531
Deferred charges related to income taxes	889	866
Prepaid pension costs	2,574	2,290
Deferred under recovered fuel clause revenues	1,279	2,056
Regulatory assets – asset retirement obligations, deferred	5,629	5,764
Other regulatory assets, deferred	5,666	5,918
Other deferred charges and assets	1,479	1,485
Total deferred charges and other assets	19,207	20,148
Total Assets	138,321	134,891
Current Liabilities:
Securities due within one year	3,076	4,285
Notes payable	1,726	2,609
Accounts payable —
Customer deposits	511	502
Accrued interest	573	614
Accrued compensation	936	1,127
Operating lease obligations	181	197
Asset retirement obligations	727	694
Other regulatory liabilities	163	382
Other current liabilities	943	787
Total current liabilities	13,214	15,724
Long-term Debt	56,003	50,656
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	10,774	10,036
Deferred credits related to income taxes	4,813	5,235
Accumulated deferred ITCs	2,071	2,133
Employee benefit obligations	1,184	1,238
Operating lease obligations, deferred	1,320	1,388
Asset retirement obligations, deferred	9,872	10,146
Other deferred credits and liabilities	1,166	1,167
Total deferred credits and other liabilities	33,800	33,979
Total Liabilities	103,017	100,359
Total Stockholders' Equity	35,304	34,532
Total Liabilities and Stockholders' Equity	138,321	134,891
GEORGIA POWER CO
Current Assets:
Cash and cash equivalents	173	364
Receivables —
Unbilled revenues	250	309
Under recovered fuel clause revenues	730	0
Joint owner accounts	157	128
Other accounts and notes	70	62
Fossil fuel stock	429	291
Materials and supplies	856	729
Regulatory assets – asset retirement obligations	183	158
Other regulatory assets	379	324
Other current assets	266	246
Total current assets	4,624	3,399
Property, Plant, and Equipment:
In service	48,083	41,879
Less: Accumulated depreciation	13,771	13,115
Plant in service, net of depreciation	34,312	28,764
Nuclear fuel, at amortized cost	622	604
Construction work in progress	5,055	8,103
Total property, plant, and equipment	39,989	37,471
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,042	1,018
Equity investments in unconsolidated subsidiaries	47	51
Miscellaneous property and investments	131	107
Total other property and investments	1,220	1,176
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	914	1,007
Deferred charges related to income taxes	595	583
Prepaid pension costs	839	738
Deferred under recovered fuel clause revenues	1,279	2,056
Regulatory assets – asset retirement obligations, deferred	3,508	3,671
Other regulatory assets, deferred	2,685	2,522
Other deferred charges and assets	496	540
Total deferred charges and other assets	10,316	11,117
Total Assets	56,149	53,163
Current Liabilities:
Securities due within one year	503	901
Notes payable	1,250	1,600
Accounts payable —
Customer deposits	251	252
Accrued taxes	620	508
Accrued interest	178	157
Accrued compensation	205	254
Operating lease obligations	134	151
Asset retirement obligations	328	295
Other regulatory liabilities	22	170
Other current liabilities	421	286
Total current liabilities	6,314	6,578
Long-term Debt	15,522	14,009
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,914	3,707
Deferred credits related to income taxes	2,171	2,244
Accumulated deferred ITCs	311	319
Employee benefit obligations	291	318
Operating lease obligations, deferred	744	851
Asset retirement obligations, deferred	5,567	5,739
Other deferred credits and liabilities	458	540
Total deferred credits and other liabilities	13,456	13,718
Total Liabilities	35,292	34,305
Total Stockholders' Equity	20,857	18,858
Total Liabilities and Stockholders' Equity	56,149	53,163
GEORGIA POWER CO | Nonrelated Party
Receivables —
Customer accounts, net and Affiliated	1,056	735
Accounts payable —
Affiliated and Other	1,632	1,076
GEORGIA POWER CO | Related Party
Receivables —
Customer accounts, net and Affiliated	75	53
Accounts payable —
Affiliated and Other	$ 770	$ 928

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Condensed Statements of Common Stockholders' Equity (Unaudited) - GPC - USD ($) shares in Millions, $ in Millions	Total	Common Stock	Paid-In Capital	Retained Earnings (Accumulated Deficit)	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)
Beginning balance (in shares) at Dec. 31, 2021							9
Beginning balance at Dec. 31, 2021	$ 32,276	$ 5,279	$ 11,950	$ 10,929	$ (237)	$ 17,234	$ 398	$ 14,153	$ 2,724	$ (41)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income						385			385
Capital contributions from parent company						443		443
Other comprehensive income	42				42	10				10
Cash dividends on common stock	(702)			(702)		(423)			(423)
Other	7		7	2
Ending balance (in shares) at Mar. 31, 2022							9
Ending balance at Mar. 31, 2022	32,629	5,286	11,994	11,261	(195)	17,649	$ 398	14,596	2,686	(31)
Beginning balance (in shares) at Dec. 31, 2021							9
Beginning balance at Dec. 31, 2021	32,276	5,279	11,950	10,929	(237)	17,234	$ 398	14,153	2,724	(41)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income	3,566					1,851
Ending balance (in shares) at Sep. 30, 2022							9
Ending balance at Sep. 30, 2022	35,476	5,417	13,657	12,374	(157)	18,657	$ 398	14,966	3,307	(14)
Beginning balance (in shares) at Mar. 31, 2022							9
Beginning balance at Mar. 31, 2022	32,629	5,286	11,994	11,261	(195)	17,649	$ 398	14,596	2,686	(31)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income						608			608
Capital contributions from parent company						46		46
Other comprehensive income	11				11	16				16
Cash dividends on common stock	(723)			(723)		(422)			(422)
Other	2		4
Ending balance (in shares) at Jun. 30, 2022							9
Ending balance at Jun. 30, 2022	33,013	5,288	12,033	11,645	(184)	17,897	$ 398	14,642	2,872	(15)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income	1,487					858			858
Capital contributions from parent company						324		324
Other comprehensive income	28				28	1				1
Cash dividends on common stock	(741)			(741)		(423)			(423)
Other	(8)		(4)	(2)	(1)
Ending balance (in shares) at Sep. 30, 2022							9
Ending balance at Sep. 30, 2022	35,476	5,417	13,657	12,374	(157)	18,657	$ 398	14,966	3,307	(14)
Beginning balance (in shares) at Dec. 31, 2022							9
Beginning balance at Dec. 31, 2022	34,532	5,417	13,673	11,538	(167)	18,858	$ 398	15,626	2,846	(12)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income						296			296
Capital contributions from parent company						752		752
Other comprehensive income	(44)				(44)
Cash dividends on common stock	(742)			(742)		(464)			(464)
Other	0		2			1			1
Ending balance (in shares) at Mar. 31, 2023							9
Ending balance at Mar. 31, 2023	34,562	5,421	13,715	11,658	(211)	19,443	$ 398	16,378	2,679	(12)
Beginning balance (in shares) at Dec. 31, 2022							9
Beginning balance at Dec. 31, 2022	34,532	5,417	13,673	11,538	(167)	18,858	$ 398	15,626	2,846	(12)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income	3,053					1,547
Ending balance (in shares) at Sep. 30, 2023							9
Ending balance at Sep. 30, 2023	35,304	5,422	13,751	12,391	(130)	20,857	$ 398	17,467	3,002	(10)
Beginning balance (in shares) at Mar. 31, 2023							9
Beginning balance at Mar. 31, 2023	34,562	5,421	13,715	11,658	(211)	19,443	$ 398	16,378	2,679	(12)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income						471			471
Capital contributions from parent company						33		33
Other comprehensive income	43				43	1				1
Cash dividends on common stock	(764)			(764)		(464)			(464)
Other	0		2
Ending balance (in shares) at Jun. 30, 2023							9
Ending balance at Jun. 30, 2023	34,648	5,422	13,742	11,732	(168)	19,484	$ 398	16,411	2,686	(11)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income	1,432					780			780
Capital contributions from parent company						1,056		1,056
Other comprehensive income	38				38	1				1
Cash dividends on common stock	(765)			(765)		(464)			(464)
Other	(1)		(2)	2
Ending balance (in shares) at Sep. 30, 2023							9
Ending balance at Sep. 30, 2023	$ 35,304	$ 5,422	$ 13,751	$ 12,391	$ (130)	$ 20,857	$ 398	$ 17,467	$ 3,002	$ (10)

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Condensed Statements of Income (Unaudited) - MPC - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Operating Revenues:
Total operating revenues	$ 6,980	$ 8,378	$ 19,208	$ 22,232
Operating Expenses:
Other operations and maintenance	1,424	1,527	4,352	4,568
Depreciation and amortization	1,143	922	3,365	2,728
Taxes other than income taxes	341	352	1,076	1,073
Total operating expenses	4,870	6,185	14,589	17,000
Operating Income	2,110	2,193	4,619	5,232
Other Income and (Expense):
Interest expense, net of amounts capitalized	(620)	(511)	(1,812)	(1,461)
Other income (expense), net	141	132	428	414
Total other income and (expense)	(381)	(292)	(1,074)	(775)
Earnings Before Income Taxes	1,729	1,901	3,545	4,457
Income taxes	297	414	492	891
Net Income	1,432	1,487	3,053	3,566
Retail electric revenues
Operating Revenues:
Total operating revenues	5,139	5,961	12,597	14,363
Wholesale electric revenues
Operating Revenues:
Total operating revenues	727	1,197	1,930	2,798
Other electric revenues
Operating Revenues:
Total operating revenues	203	185	602	554
Natural Gas
Operating Revenues:
Total operating revenues	689	857	3,417	3,998
Other revenues
Operating Revenues:
Total operating revenues	222	178	662	519
Operating Expenses:
Total cost of sales	126	92	381	275
Mississippi Power
Operating Revenues:
Total operating revenues	436	510	1,137	1,279
Operating Expenses:
Other operations and maintenance	84	86	258	252
Depreciation and amortization	48	45	139	135
Taxes other than income taxes	32	32	92	93
Total operating expenses	333	425	905	1,081
Operating Income	103	85	232	198
Other Income and (Expense):
Interest expense, net of amounts capitalized	(19)	(15)	(53)	(42)
Other income (expense), net	9	9	29	32
Total other income and (expense)	(10)	(6)	(24)	(10)
Earnings Before Income Taxes	93	79	208	188
Income taxes	18	17	35	38
Net Income	75	62	173	150
Mississippi Power | Retail electric revenues
Operating Revenues:
Total operating revenues	284	250	747	718
Mississippi Power | Wholesale revenues, non-affiliates
Operating Revenues:
Total operating revenues	77	60	201	191
Mississippi Power | Wholesale revenues, affiliates
Operating Revenues:
Total operating revenues	65	187	158	336
Mississippi Power | Other revenues
Operating Revenues:
Total operating revenues	10	13	31	34
Mississippi Power | Fuel and purchased power
Operating Expenses:
Total cost of sales	$ 169	$ 262	$ 416	$ 601

XML

Condensed Statements of Cash Flows (Unaudited) - MPC - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Operating Activities:
Consolidated net income	$ 3,053	$ 3,566
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	3,699	3,084
Deferred income taxes	(52)	608
Pension, postretirement, and other employee benefits	(397)	(322)
Settlement of asset retirement obligations	(444)	(314)
Other, net	(67)	(119)
Changes in certain current assets and liabilities —
Receivables	524	(316)
Retail fuel cost under recovery	513	(104)
Other current assets	(32)	(310)
Accounts payable	(1,031)	805
Accrued taxes	376	167
Accrued compensation	(197)	(123)
Other current liabilities	66	(82)
Net cash provided from operating activities	5,740	5,017
Investing Activities:
Property additions	(6,561)	(5,502)
Cost of removal, net of salvage	(421)	(518)
Construction payables	241	15
Other investing activities	(139)	(63)
Net cash used for investing activities	(6,721)	(5,952)
Financing Activities:
Payment of common stock dividends	(2,271)	(2,166)
Other financing activities	(141)	(235)
Net cash provided from financing activities	834	1,119
Net Change in Cash, Cash Equivalents, and Restricted Cash	(147)	184
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	2,037	1,829
Cash, Cash Equivalents, and Restricted Cash at End of Period	1,890	2,013
Supplemental Cash Flow Information:
Interest, net of amounts capitalized	1,694	1,425
Income taxes, net	11	160
Noncash transactions —
Accrued property additions at end of period	1,224	872
Right-of-use assets obtained under operating leases	76	27
Mississippi Power
Operating Activities:
Consolidated net income	173	150
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	171	164
Deferred income taxes	(10)	(4)
Pension, postretirement, and other employee benefits	(15)	(12)
Settlement of asset retirement obligations	(12)	(15)
Other, net	12	36
Changes in certain current assets and liabilities —
Receivables	55	(49)
Retail fuel cost under recovery	(24)	(9)
Other current assets	14	(17)
Accounts payable	(83)	41
Accrued taxes	(16)	(3)
Accrued compensation	(5)	(5)
Other current liabilities	0	2
Net cash provided from operating activities	260	279
Investing Activities:
Property additions	(231)	(165)
Cost of removal, net of salvage	(21)	(20)
Construction payables	(5)	(9)
Payments pursuant to LTSAs	(21)	(23)
Other investing activities	(2)	(2)
Net cash used for investing activities	(280)	(219)
Financing Activities:
Increase in notes payable, net	20	0
Proceeds — Senior notes	100	0
Capital contributions from parent company	8	55
Payment of common stock dividends	(139)	(128)
Other financing activities	(1)	1
Net cash provided from financing activities	(12)	(72)
Net Change in Cash, Cash Equivalents, and Restricted Cash	(32)	(12)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	59	61
Cash, Cash Equivalents, and Restricted Cash at End of Period	27	49
Supplemental Cash Flow Information:
Interest, net of amounts capitalized	53	49
Income taxes, net	33	18
Noncash transactions —
Accrued property additions at end of period	20	16
Right-of-use assets obtained under operating leases	1	0
GEORGIA POWER CO
Operating Activities:
Consolidated net income	1,547	1,851
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	1,411	1,211
Deferred income taxes	102	266
Pension, postretirement, and other employee benefits	(207)	(178)
Settlement of asset retirement obligations	(228)	(149)
Other, net	(12)	(22)
Changes in certain current assets and liabilities —
Receivables	(311)	(321)
Retail fuel cost under recovery	204	0
Other current assets	16	(72)
Accounts payable	(142)	211
Accrued taxes	118	151
Other current liabilities	16	(79)
Net cash provided from operating activities	1,969	1,482
Investing Activities:
Property additions	(3,501)	(2,556)
Cost of removal, net of salvage	(191)	(250)
Other investing activities	(76)	(47)
Net cash used for investing activities	(3,376)	(2,653)
Financing Activities:
Increase in notes payable, net	50	415
Proceeds — Senior notes	1,750	1,500
Capital contributions from parent company	1,837	813
Payment of common stock dividends	(1,392)	(1,268)
Other financing activities	(27)	(45)
Net cash provided from financing activities	1,183	1,171
Net Change in Cash, Cash Equivalents, and Restricted Cash	(224)	0
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	480	33
Cash, Cash Equivalents, and Restricted Cash at End of Period	256	33
Supplemental Cash Flow Information:
Interest, net of amounts capitalized	439	332
Income taxes, net	74	151
Noncash transactions —
Accrued property additions at end of period	942	609
Right-of-use assets obtained under operating leases	$ 17	$ 7

XML

Condensed Balance Sheets (Unaudited) - MPC - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Current Assets:
Cash and cash equivalents	$ 1,676	$ 1,917
Receivables —
Customer accounts, net and Affiliated	2,230	2,128
Unbilled revenues	547	1,012
Other accounts and notes	553	637
Fossil fuel stock	829	575
Materials and supplies	1,913	1,664
Other regulatory assets	996	968
Other current assets	544	344
Total current assets	11,088	10,416
Property, Plant, and Equipment:
In service	125,573	117,529
Less: Accumulated depreciation	37,199	35,297
Plant in service, net of depreciation	88,374	82,232
Construction work in progress	8,496	10,896
Total property, plant, and equipment	98,254	94,570
Other Property and Investments:
Total other property and investments	9,772	9,757
Deferred Charges and Other Assets:
Deferred charges related to income taxes	889	866
Prepaid pension costs	2,574	2,290
Regulatory assets – asset retirement obligations	5,629	5,764
Other regulatory assets, deferred	5,666	5,918
Other deferred charges and assets	1,479	1,485
Total deferred charges and other assets	19,207	20,148
Total Assets	138,321	134,891
Current Liabilities:
Securities due within one year	3,076	4,285
Notes payable	1,726	2,609
Accounts payable —
Accrued compensation	936	1,127
Asset retirement obligations	727	694
Other regulatory liabilities	163	382
Other current liabilities	943	787
Total current liabilities	13,214	15,724
Long-term Debt	56,003	50,656
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	10,774	10,036
Deferred credits related to income taxes	4,813	5,235
Employee benefit obligations	1,184	1,238
Asset retirement obligations, deferred	9,872	10,146
Other cost of removal obligations	1,940	1,903
Other regulatory liabilities, deferred	660	733
Other deferred credits and liabilities	1,166	1,167
Total deferred credits and other liabilities	33,800	33,979
Total Liabilities	103,017	100,359
Total Liabilities and Stockholders' Equity	138,321	134,891
Mississippi Power
Current Assets:
Cash and cash equivalents	27	59
Receivables —
Unbilled revenues	41	47
Other accounts and notes	22	35
Fossil fuel stock	37	44
Materials and supplies	85	80
Other regulatory assets	54	72
Other current assets	10	38
Total current assets	392	504
Property, Plant, and Equipment:
In service	5,473	5,254
Less: Accumulated depreciation	1,763	1,689
Plant in service, net of depreciation	3,710	3,565
Construction work in progress	183	208
Total property, plant, and equipment	3,893	3,773
Other Property and Investments:
Total other property and investments	160	167
Deferred Charges and Other Assets:
Deferred charges related to income taxes	29	30
Prepaid pension costs	123	109
Regulatory assets – asset retirement obligations	241	239
Other regulatory assets, deferred	246	249
Accumulated deferred income taxes	95	107
Other deferred charges and assets	79	94
Total deferred charges and other assets	813	828
Total Assets	5,258	5,272
Current Liabilities:
Securities due within one year	201	1
Notes payable	20	0
Accounts payable —
Accrued taxes	108	124
Accrued compensation	32	37
Asset retirement obligations	26	37
Other regulatory liabilities	30	43
Other current liabilities	74	85
Total current liabilities	631	554
Long-term Debt	1,443	1,544
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	466	466
Deferred credits related to income taxes	229	253
Employee benefit obligations	67	69
Asset retirement obligations, deferred	145	142
Other cost of removal obligations	192	196
Other regulatory liabilities, deferred	81	96
Other deferred credits and liabilities	30	21
Total deferred credits and other liabilities	1,210	1,243
Total Liabilities	3,284	3,341
Total common stockholders' equity	1,974	1,931
Total Liabilities and Stockholders' Equity	5,258	5,272
Mississippi Power | Nonrelated Party
Receivables —
Customer accounts, net and Affiliated	78	47
Accounts payable —
Affiliated and Other	61	106
Mississippi Power | Related Party
Receivables —
Customer accounts, net and Affiliated	38	82
Accounts payable —
Affiliated and Other	$ 79	$ 121

XML

Condensed Statements of Common Stockholders' Equity (Unaudited) - MPC - USD ($) shares in Millions, $ in Millions	Total	Common Stock	Paid-In Capital	Retained Earnings (Accumulated Deficit)	Mississippi Power	Mississippi Power Common Stock	Mississippi Power Paid-In Capital	Mississippi Power Retained Earnings (Accumulated Deficit)
Beginning balance (in shares) at Dec. 31, 2021						1
Beginning balance at Dec. 31, 2021	$ 32,276	$ 5,279	$ 11,950	$ 10,929	$ 1,867	$ 38	$ 4,582	$ (2,753)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income					42			42
Capital contributions from parent company					51		51
Cash dividends on common stock	(702)			(702)	(43)			(43)
Ending balance (in shares) at Mar. 31, 2022						1
Ending balance at Mar. 31, 2022	32,629	5,286	11,994	11,261	1,917	$ 38	4,633	(2,754)
Beginning balance (in shares) at Dec. 31, 2021						1
Beginning balance at Dec. 31, 2021	32,276	5,279	11,950	10,929	1,867	$ 38	4,582	(2,753)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	3,566				150
Ending balance (in shares) at Sep. 30, 2022						1
Ending balance at Sep. 30, 2022	35,476	5,417	13,657	12,374	1,946	$ 38	4,639	(2,731)
Beginning balance (in shares) at Mar. 31, 2022						1
Beginning balance at Mar. 31, 2022	32,629	5,286	11,994	11,261	1,917	$ 38	4,633	(2,754)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income					45			45
Capital contributions from parent company					1		1
Cash dividends on common stock	(723)			(723)	(42)			(42)
Ending balance (in shares) at Jun. 30, 2022						1
Ending balance at Jun. 30, 2022	33,013	5,288	12,033	11,645	1,921	$ 38	4,634	(2,751)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	1,487				62			62
Capital contributions from parent company					5		5
Cash dividends on common stock	(741)			(741)	(42)			(42)
Ending balance (in shares) at Sep. 30, 2022						1
Ending balance at Sep. 30, 2022	35,476	5,417	13,657	12,374	1,946	$ 38	4,639	(2,731)
Beginning balance (in shares) at Dec. 31, 2022						1
Beginning balance at Dec. 31, 2022	34,532	5,417	13,673	11,538	1,931	$ 38	4,652	(2,759)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income					58			58
Cash dividends on common stock	(742)			(742)	(46)			(46)
Ending balance (in shares) at Mar. 31, 2023						1
Ending balance at Mar. 31, 2023	34,562	5,421	13,715	11,658	1,943	$ 38	4,652	(2,747)
Beginning balance (in shares) at Dec. 31, 2022						1
Beginning balance at Dec. 31, 2022	34,532	5,417	13,673	11,538	1,931	$ 38	4,652	(2,759)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	3,053				173
Ending balance (in shares) at Sep. 30, 2023						1
Ending balance at Sep. 30, 2023	35,304	5,422	13,751	12,391	1,974	$ 38	4,661	(2,725)
Beginning balance (in shares) at Mar. 31, 2023						1
Beginning balance at Mar. 31, 2023	34,562	5,421	13,715	11,658	1,943	$ 38	4,652	(2,747)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income					40			40
Capital contributions from parent company					12		12
Cash dividends on common stock	(764)			(764)	(47)			(47)
Ending balance (in shares) at Jun. 30, 2023						1
Ending balance at Jun. 30, 2023	34,648	5,422	13,742	11,732	1,948	$ 38	4,664	(2,754)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	1,432				75			75
Return of capital to parent company					(3)		(3)
Cash dividends on common stock	(765)			(765)	(46)			(46)
Ending balance (in shares) at Sep. 30, 2023						1
Ending balance at Sep. 30, 2023	$ 35,304	$ 5,422	$ 13,751	$ 12,391	$ 1,974	$ 38	$ 4,661	$ (2,725)

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Condensed Consolidated Statements of Income (Unaudited) - SPC - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Operating Revenues:
Total operating revenues	$ 6,980	$ 8,378	$ 19,208	$ 22,232
Operating Expenses:
Other operations and maintenance	1,424	1,527	4,352	4,568
Depreciation and amortization	1,143	922	3,365	2,728
Taxes other than income taxes	341	352	1,076	1,073
Total operating expenses	4,870	6,185	14,589	17,000
Operating Income	2,110	2,193	4,619	5,232
Other Income and (Expense):
Interest expense, net of amounts capitalized	(620)	(511)	(1,812)	(1,461)
Other income (expense), net	141	132	428	414
Total other income and (expense)	(381)	(292)	(1,074)	(775)
Earnings Before Income Taxes	1,729	1,901	3,545	4,457
Income taxes	297	414	492	891
Net Income	1,432	1,487	3,053	3,566
Net income (loss) attributable to noncontrolling interests	10	12	(68)	(55)
Net Income	1,422	1,472	3,121	3,611
Retail electric revenues
Operating Revenues:
Total operating revenues	5,139	5,961	12,597	14,363
Wholesale electric revenues
Operating Revenues:
Total operating revenues	727	1,197	1,930	2,798
Other electric revenues
Operating Revenues:
Total operating revenues	203	185	602	554
Natural Gas
Operating Revenues:
Total operating revenues	689	857	3,417	3,998
Other revenues
Operating Revenues:
Total operating revenues	222	178	662	519
Operating Expenses:
Total cost of sales	126	92	381	275
Fuel
Operating Expenses:
Total cost of sales	1,367	2,423	3,376	5,249
Purchased power
Operating Expenses:
Total cost of sales	207	645	680	1,285
SOUTHERN POWER CO
Operating Revenues:
Total operating revenues	653	1,180	1,686	2,618
Operating Expenses:
Other operations and maintenance	104	113	327	332
Depreciation and amortization	130	133	380	384
Taxes other than income taxes	13	13	38	38
Gain on dispositions, net	0	0	(20)	(2)
Total operating expenses	476	1,008	1,338	2,259
Operating Income	177	172	348	359
Other Income and (Expense):
Interest expense, net of amounts capitalized	(32)	(32)	(98)	(105)
Other income (expense), net	4	3	8	5
Total other income and (expense)	(28)	(29)	(90)	(100)
Earnings Before Income Taxes	149	143	258	259
Income taxes	39	36	38	49
Net Income	110	107	220	210
Net income (loss) attributable to noncontrolling interests	10	12	(68)	(55)
Net Income	100	95	288	265
SOUTHERN POWER CO | Wholesale revenues, non-affiliates
Operating Revenues:
Total operating revenues	479	835	1,234	1,918
SOUTHERN POWER CO | Wholesale revenues, affiliates
Operating Revenues:
Total operating revenues	156	336	406	673
SOUTHERN POWER CO | Other revenues
Operating Revenues:
Total operating revenues	18	9	46	27
SOUTHERN POWER CO | Fuel
Operating Expenses:
Total cost of sales	196	605	526	1,274
SOUTHERN POWER CO | Purchased power
Operating Expenses:
Total cost of sales	$ 33	$ 144	$ 87	$ 233

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - SPC - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Consolidated Net Income	$ 1,432	$ 1,487	$ 3,053	$ 3,566
Qualifying hedges:
Changes in fair value, net of tax	2	0	(34)	(27)
Reclassification adjustment for amounts included in net income, net of tax	36	26	70	100
Reclassification adjustment for amounts included in net income, net of tax	0	2	1	8
Total other comprehensive income	38	28	37	81
Comprehensive income	1,470	1,515	3,090	3,647
Comprehensive income (loss) attributable to noncontrolling interests	10	12	(68)	(55)
Comprehensive Income	1,460	1,500	3,158	3,692
SOUTHERN POWER CO
Consolidated Net Income	110	107	220	210
Qualifying hedges:
Changes in fair value, net of tax	(13)	(35)	(17)	(106)
Reclassification adjustment for amounts included in net income, net of tax	17	28	24	106
Reclassification adjustment for amounts included in net income, net of tax	0	0	0	1
Total other comprehensive income	4	(7)	7	1
Comprehensive income	114	100	227	211
Comprehensive income (loss) attributable to noncontrolling interests	10	12	(68)	(55)
Comprehensive Income	$ 104	$ 88	$ 295	$ 266

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Condensed Consolidated Statements of Comprehensive Income (Unaudited) - SPC (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Changes in fair value, tax	$ 3	$ 2	$ (11)	$ (5)
Qualifying hedges, reclassification adjustment, tax	12	8	25	32
Reclassification adjustment for amounts included in net income, tax	0	1	0	3
SOUTHERN POWER CO
Changes in fair value, tax	(2)	(11)	(3)	(35)
Qualifying hedges, reclassification adjustment, tax	4	9	6	35
Reclassification adjustment for amounts included in net income, tax	$ 0	$ 0	$ 0	$ 0

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Condensed Consolidated Statements of Cash Flows (Unaudited) - SPC - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Operating Activities:
Consolidated net income	$ 3,053	$ 3,566
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	3,699	3,084
Deferred income taxes	(52)	608
Utilization of federal investment tax credits	195	266
Other, net	(67)	(119)
Changes in certain current assets and liabilities —
Receivables	524	(316)
Other current assets	(32)	(310)
Accounts payable	(1,031)	805
Accrued taxes	376	167
Other current liabilities	66	(82)
Net cash provided from operating activities	5,740	5,017
Investing Activities:
Property additions	(6,561)	(5,502)
Other investing activities	(139)	(63)
Net cash used for investing activities	(6,721)	(5,952)
Financing Activities:
Increase (decrease) in notes payable, net	(298)	(349)
Capital contributions from noncontrolling interests	21	73
Distributions to noncontrolling interests	(148)	(175)
Payment of common stock dividends	(2,271)	(2,166)
Other financing activities	(141)	(235)
Net cash provided from financing activities	834	1,119
Net Change in Cash, Cash Equivalents, and Restricted Cash	(147)	184
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	2,037	1,829
Cash, Cash Equivalents, and Restricted Cash at End of Period	1,890	2,013
Supplemental Cash Flow Information:
Interest, net of amounts capitalized	1,694	1,425
Income taxes, net	11	160
Noncash transactions —
Accrued property additions at end of period	1,224	872
Right-of-use assets obtained under operating leases	76	27
Reassessment of right-of-use assets under operating leases	0	40
SOUTHERN POWER CO
Operating Activities:
Consolidated net income	220	210
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	395	404
Deferred income taxes	1	21
Utilization of federal investment tax credits	179	218
Amortization of investment tax credits	(44)	(44)
Gain on dispositions, net	(20)	(2)
Other, net	4	1
Changes in certain current assets and liabilities —
Receivables	100	(124)
Prepaid income taxes	31	22
Other current assets	(14)	(15)
Accounts payable	(70)	95
Accrued taxes	9	55
Other current liabilities	8	(14)
Net cash provided from operating activities	799	827
Investing Activities:
Acquisitions, net of cash acquired	(181)	0
Property additions	(40)	(64)
Proceeds from dispositions	59	48
Change in construction payables	(18)	(60)
Payments pursuant to LTSAs	(49)	(52)
Other investing activities	5	0
Net cash used for investing activities	(224)	(128)
Financing Activities:
Increase (decrease) in notes payable, net	136
Increase (decrease) in notes payable, net		(5)
Redemptions — Senior notes	(290)	(677)
Capital contributions from parent company	16	330
Capital contributions from noncontrolling interests	21	73
Distributions to noncontrolling interests	(148)	(175)
Payment of common stock dividends	(189)	(148)
Other financing activities	3	(1)
Net cash provided from financing activities	(451)	(603)
Net Change in Cash, Cash Equivalents, and Restricted Cash	124	96
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	133	135
Cash, Cash Equivalents, and Restricted Cash at End of Period	257	231
Supplemental Cash Flow Information:
Interest, net of amounts capitalized	103	120
Income taxes, net	(124)	(202)
Noncash transactions —
Accrued property additions at end of period	23	30
Right-of-use assets obtained under operating leases	7	0
Reassessment of right-of-use assets under operating leases	$ 0	$ 40

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Condensed Consolidated Statements of Cash Flows (Unaudited) - SPC (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Net cash paid for capitalized interest	$ 97	$ 74
SOUTHERN POWER CO
Net cash paid for capitalized interest	$ 1	$ 0

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Condensed Consolidated Balance Sheets (Unaudited) - SPC - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Current Assets:
Cash and cash equivalents	$ 1,676	$ 1,917
Receivables —
Customer accounts, net and Affiliated	2,230	2,128
Other	553	637
Materials and supplies	1,913	1,664
Other current assets	544	344
Total current assets	11,088	10,416
Property, Plant, and Equipment:
In service	125,573	117,529
Less: Accumulated depreciation	37,199	35,297
Plant in service, net of depreciation	88,374	82,232
Construction work in progress	8,496	10,896
Total property, plant, and equipment	98,254	94,570
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	1,376	1,443
Total other property and investments	9,772	9,757
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,467	1,531
Other deferred charges and assets	1,479	1,485
Total deferred charges and other assets	19,207	20,148
Total Assets	138,321	134,891
Current Liabilities:
Securities due within one year	3,076	4,285
Notes payable	1,726	2,609
Accounts payable —
Accrued interest	573	614
Other current liabilities	943	787
Total current liabilities	13,214	15,724
Long-term Debt	56,003	50,656
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	10,774	10,036
Accumulated deferred ITCs	2,071	2,133
Operating lease obligations	1,320	1,388
Other deferred credits and liabilities	1,166	1,167
Total deferred credits and other liabilities	33,800	33,979
Total Liabilities	103,017	100,359
Total Stockholders' Equity (See accompanying statements)	35,304	34,532
Total Liabilities and Stockholders' Equity	138,321	134,891
SOUTHERN POWER CO
Current Assets:
Cash and cash equivalents	236	131
Receivables —
Other	44	70
Materials and supplies	84	88
Prepaid income taxes	130	5
Other current assets	71	50
Total current assets	789	621
Property, Plant, and Equipment:
In service	14,678	14,658
Less: Accumulated depreciation	4,001	3,661
Plant in service, net of depreciation	10,677	10,997
Construction work in progress	224	41
Total property, plant, and equipment	10,901	11,038
Other Property and Investments:
Intangible assets, net of amortization	248	263
Equity investments in unconsolidated subsidiaries	0	49
Net investment in sales-type leases	150	154
Total other property and investments	398	466
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	490	489
Prepaid LTSAs	225	193
Other deferred charges and assets	287	274
Total deferred charges and other assets	1,002	956
Total Assets	13,090	13,081
Current Liabilities:
Securities due within one year	0	290
Notes payable	359	225
Accounts payable —
Accrued taxes	33	24
Accrued interest	22	28
Other current liabilities	117	111
Total current liabilities	654	884
Long-term Debt	2,687	2,689
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	619	279
Accumulated deferred ITCs	1,512	1,556
Operating lease obligations	516	514
Other deferred credits and liabilities	259	243
Total deferred credits and other liabilities	2,906	2,592
Total Liabilities	6,247	6,165
Total Stockholders' Equity (See accompanying statements)	6,843	6,916
Total Liabilities and Stockholders' Equity	13,090	13,081
SOUTHERN POWER CO | Nonrelated Party
Receivables —
Customer accounts, net and Affiliated	164	226
Accounts payable —
Affiliated and Other	43	67
SOUTHERN POWER CO | Related Party
Receivables —
Customer accounts, net and Affiliated	60	51
Accounts payable —
Affiliated and Other	$ 80	$ 139

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Condensed Consolidated Balance Sheets (Unaudited) - SPC (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Other intangible assets, amortization	$ 367	$ 340
SOUTHERN POWER CO
Other intangible assets, amortization	$ 143	$ 129

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Condensed Consolidated Statements of Stockholders' Equity (Unaudited) - SPC - USD ($) $ in Millions	Total	Paid-In Capital	Retained Earnings (Accumulated Deficit)	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests	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
Beginning balance at Dec. 31, 2021	$ 32,276	$ 11,950	$ 10,929	$ (237)	$ 4,402	$ 6,598	$ 2,196	$ 638	$ 1,585	$ (27)	$ 4,402
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income						27	72		72		(45)
Other comprehensive income	42			42		5	5			5
Cash dividends on common stock	(702)		(702)			(49)	(49)		(49)
Capital contributions from noncontrolling interests	73				73	73					73
Distributions to noncontrolling interests	(98)				(98)	(98)					(98)
Other	7	7	2
Ending balance at Mar. 31, 2022	32,629	11,994	11,261	(195)	4,332	6,556	2,224	638	1,608	(22)	4,332
Beginning balance at Dec. 31, 2021	32,276	11,950	10,929	(237)	4,402	6,598	2,196	638	1,585	(27)	4,402
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income	3,566					210
Ending balance at Sep. 30, 2022	35,476	13,657	12,374	(157)	4,237	6,880	2,643	969	1,701	(27)	4,237
Beginning balance at Mar. 31, 2022	32,629	11,994	11,261	(195)	4,332	6,556	2,224	638	1,608	(22)	4,332
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income						76	98		98		(22)
Capital contributions from parent company						322	322	322
Other comprehensive income	11			11		3	3			3
Cash dividends on common stock	(723)		(723)			(50)	(50)		(50)
Distributions to noncontrolling interests	(28)				(28)	(28)					(28)
Other	2	4
Ending balance at Jun. 30, 2022	33,013	12,033	11,645	(184)	4,282	6,879	2,597	960	1,656	(19)	4,282
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income	1,487					107	95		95		12
Capital contributions from parent company						9	9	9
Other comprehensive income	28			28		(7)	(7)			(7)
Cash dividends on common stock	(741)		(741)			(49)	(49)		(49)
Distributions to noncontrolling interests	(57)				(57)	(57)					(57)
Other	(8)	(4)	(2)	(1)		(2)	(2)		(1)	(1)
Ending balance at Sep. 30, 2022	35,476	13,657	12,374	(157)	4,237	6,880	2,643	969	1,701	(27)	4,237
Beginning balance at Dec. 31, 2022	34,532	13,673	11,538	(167)	4,124	6,916	2,792	1,069	1,741	(18)	4,124
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income						39	102		102		(63)
Other comprehensive income	(44)			(44)		(7)	(7)			(7)
Cash dividends on common stock	(742)		(742)			(63)	(63)		(63)
Capital contributions from noncontrolling interests	21				21	21					21
Distributions to noncontrolling interests	(48)				(48)	(48)					(48)
Other	0	2
Ending balance at Mar. 31, 2023	34,562	13,715	11,658	(211)	4,034	6,858	2,824	1,069	1,780	(25)	4,034
Beginning balance at Dec. 31, 2022	34,532	13,673	11,538	(167)	4,124	6,916	2,792	1,069	1,741	(18)	4,124
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income	3,053					220
Ending balance at Sep. 30, 2023	35,304	13,751	12,391	(130)	3,927	6,843	2,916	1,087	1,839	(10)	3,927
Beginning balance at Mar. 31, 2023	34,562	13,715	11,658	(211)	4,034	6,858	2,824	1,069	1,780	(25)	4,034
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income						70	85		85		(15)
Capital contributions from parent company						14	14	14
Other comprehensive income	43			43		10	10			10
Cash dividends on common stock	(764)		(764)			(63)	(63)		(63)
Distributions to noncontrolling interests	(42)				(42)	(42)					(42)
Other	0	2			(1)	0	1			1	(1)
Ending balance at Jun. 30, 2023	34,648	13,742	11,732	(168)	3,976	6,847	2,871	1,083	1,802	(14)	3,976
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income	1,432					110	100		100		10
Capital contributions from parent company						3	3	3
Other comprehensive income	38			38		4	4			4
Cash dividends on common stock	(765)		(765)			(63)	(63)		(63)
Distributions to noncontrolling interests	(59)				(59)	(59)					(59)
Other	(1)	(2)	2			1	1	1	0	0	0
Ending balance at Sep. 30, 2023	$ 35,304	$ 13,751	$ 12,391	$ (130)	$ 3,927	$ 6,843	$ 2,916	$ 1,087	$ 1,839	$ (10)	$ 3,927

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Condensed Consolidated Statements of Income (Unaudited) - GAS - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Operating Revenues:
Total operating revenues	$ 6,980	$ 8,378	$ 19,208	$ 22,232
Operating Expenses:
Other operations and maintenance	1,424	1,527	4,352	4,568
Depreciation and amortization	1,143	922	3,365	2,728
Taxes other than income taxes	341	352	1,076	1,073
Total operating expenses	4,870	6,185	14,589	17,000
Operating Income	2,110	2,193	4,619	5,232
Other Income and (Expense):
Earnings from equity method investments	32	28	110	109
Interest expense, net of amounts capitalized	(620)	(511)	(1,812)	(1,461)
Other income (expense), net	141	132	428	414
Total other income and (expense)	(381)	(292)	(1,074)	(775)
Earnings Before Income Taxes	1,729	1,901	3,545	4,457
Income taxes	297	414	492	891
Net Income	1,432	1,487	3,053	3,566
Retail electric revenues
Operating Revenues:
Total operating revenues	5,139	5,961	12,597	14,363
Wholesale electric revenues
Operating Revenues:
Total operating revenues	727	1,197	1,930	2,798
Other electric revenues
Operating Revenues:
Total operating revenues	203	185	602	554
Natural Gas
Operating Revenues:
Total operating revenues	689	857	3,417	3,998
Natural gas
Operating Expenses:
Total cost of sales	102	294	1,199	1,840
Other revenues
Operating Revenues:
Total operating revenues	222	178	662	519
Operating Expenses:
Total cost of sales	126	92	381	275
Fuel
Operating Expenses:
Total cost of sales	1,367	2,423	3,376	5,249
Purchased power
Operating Expenses:
Total cost of sales	207	645	680	1,285
SOUTHERN Co GAS
Operating Revenues:
Total operating revenues	$ 689	$ 857	$ 3,417	$ 3,998
Operating Expenses:
Cost, Product and Service [Extensible Enumeration]	Natural gas	Natural gas	Natural gas	Natural gas
Other operations and maintenance	$ 264	$ 252	$ 879	$ 824
Depreciation and amortization	145	140	429	414
Taxes other than income taxes	42	45	203	208
Total operating expenses	553	731	2,710	3,286
Operating Income	136	126	707	712
Other Income and (Expense):
Earnings from equity method investments	32	34	104	105
Interest expense, net of amounts capitalized	(77)	(65)	(226)	(187)
Other income (expense), net	19	15	50	47
Total other income and (expense)	(26)	(16)	(72)	(35)
Earnings Before Income Taxes	110	110	635	677
Income taxes	28	27	160	161
Net Income	82	83	475	516
SOUTHERN Co GAS | Natural gas
Operating Revenues:
Total operating revenues	689	857	3,417	3,998
Operating Expenses:
Total cost of sales	$ 102	$ 294	$ 1,199	$ 1,840

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Condensed Consolidated Statements of Income (Unaudited) - GAS (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
SOUTHERN Co GAS
Revenue taxes collected	$ 11	$ 15	$ 103	$ 118

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Condensed Consolidated Statements of Comprehensive Income (Unaudited) - GAS - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Consolidated Net Income	$ 1,432	$ 1,487	$ 3,053	$ 3,566
Qualifying hedges:
Changes in fair value, net of tax	2	0	(34)	(27)
Reclassification adjustment for amounts included in net income, net of tax	36	26	70	100
Total other comprehensive income	38	28	37	81
Comprehensive Income	1,470	1,515	3,090	3,647
SOUTHERN Co GAS
Consolidated Net Income	82	83	475	516
Qualifying hedges:
Changes in fair value, net of tax	(6)	19	(30)	39
Reclassification adjustment for amounts included in net income, net of tax	16	(5)	37	(17)
Total other comprehensive income	10	14	7	22
Comprehensive Income	$ 92	$ 97	$ 482	$ 538

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Condensed Consolidated Statements of Comprehensive Income (Unaudited) - GAS (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Changes in fair value, tax	$ 3	$ 2	$ (11)	$ (5)
Qualifying hedges, reclassification adjustment, tax	12	8	25	32
SOUTHERN Co GAS
Changes in fair value, tax	(2)	8	(11)	16
Qualifying hedges, reclassification adjustment, tax	$ 7	$ (2)	$ 15	$ (7)

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Condensed Consolidated Statements of Cash Flows (Unaudited) - GAS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Operating Activities:
Consolidated net income	$ 3,053	$ 3,566
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	3,699	3,084
Deferred income taxes	(52)	608
Natural gas cost under recovery – long-term	0	207
Other, net	(67)	(119)
Changes in certain current assets and liabilities —
Receivables	524	(316)
Natural gas cost under recovery	108	(124)
Other current assets	(32)	(310)
Accounts payable	(1,031)	805
Other current liabilities	66	(82)
Net cash provided from operating activities	5,740	5,017
Investing Activities:
Property additions	(6,561)	(5,502)
Cost of removal, net of salvage	(421)	(518)
Change in construction payables, net	241	15
Other investing activities	(139)	(63)
Net cash used for investing activities	(6,721)	(5,952)
Financing Activities:
Decrease in notes payable, net	(298)	(349)
Proceeds —
Short-term borrowings	250	1,200
Redemptions —
Short-term borrowings	(850)	(900)
Payment of common stock dividends	(2,271)	(2,166)
Other financing activities	(141)	(235)
Net cash provided from financing activities	834	1,119
Net Change in Cash, Cash Equivalents, and Restricted Cash	(147)	184
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	2,037	1,829
Cash, Cash Equivalents, and Restricted Cash at End of Period	1,890	2,013
Supplemental Cash Flow Information:
Interest, net of amounts capitalized	1,694	1,425
Income taxes, net	11	160
Accrued property additions at end of period	1,224	872
Right-of-use assets obtained under operating leases	76	27
SOUTHERN Co GAS
Operating Activities:
Consolidated net income	475	516
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	429	414
Deferred income taxes	75	109
Natural gas cost under recovery – long-term	0	207
Other, net	(15)	(12)
Changes in certain current assets and liabilities —
Receivables	776	301
Natural gas for sale, net of temporary LIFO liquidation	31	(136)
Prepaid income taxes	12	(77)
Natural gas cost under recovery	108	(124)
Other current assets	(32)	7
Accounts payable	(346)	342
Natural gas cost over recovery	165	0
Other current liabilities	(34)	(15)
Net cash provided from operating activities	1,644	1,532
Investing Activities:
Property additions	(1,151)	(1,063)
Cost of removal, net of salvage	(82)	(84)
Change in construction payables, net	(38)	(103)
Other investing activities	45	11
Net cash used for investing activities	(1,226)	(1,239)
Financing Activities:
Decrease in notes payable, net	(493)	(749)
Proceeds —
Proceeds — Senior notes	500	500
First mortgage bonds	125	100
Short-term borrowings	0	50
Other long-term debt	29	0
Redemptions —
Short-term borrowings	(200)	(150)
Medium-term notes	0	(46)
Capital contributions from parent company	377	357
Payment of common stock dividends	(439)	(389)
Other financing activities	(1)	14
Net cash provided from financing activities	(102)	(313)
Net Change in Cash, Cash Equivalents, and Restricted Cash	316	(20)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	83	48
Cash, Cash Equivalents, and Restricted Cash at End of Period	399	28
Supplemental Cash Flow Information:
Interest, net of amounts capitalized	214	186
Income taxes, net	70	193
Accrued property additions at end of period	139	10
Right-of-use assets obtained under operating leases	$ 3	$ 0

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Condensed Consolidated Statements of Cash Flows (Unaudited) - GAS (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Net cash paid for capitalized interest	$ 97	$ 74
SOUTHERN Co GAS
Net cash paid for capitalized interest	$ 12	$ 7

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Condensed Consolidated Balance Sheets (Unaudited) - GAS - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Current Assets:
Cash and cash equivalents	$ 1,676	$ 1,917
Receivables —
Customer accounts	2,230	2,128
Unbilled revenues	547	1,012
Other accounts and notes	553	637
Accumulated provision for uncollectible accounts	(78)	(71)
Natural gas for sale	406	438
Prepaid expenses	321	347
Other regulatory assets	996	968
Other current assets	544	344
Total current assets	11,088	10,416
Property, Plant, and Equipment:
In service	125,573	117,529
Less: Accumulated depreciation	37,199	35,297
Plant in service, net of depreciation	88,374	82,232
Construction work in progress	8,496	10,896
Total property, plant, and equipment	98,254	94,570
Other Property and Investments:
Goodwill	5,161	5,161
Equity investments in unconsolidated subsidiaries	1,376	1,443
Other intangible assets, net of amortization	377	406
Miscellaneous property and investments	651	602
Total other property and investments	9,772	9,757
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,467	1,531
Prepaid pension costs	2,574	2,290
Other regulatory assets, deferred	5,666	5,918
Other deferred charges and assets	1,479	1,485
Total deferred charges and other assets	19,207	20,148
Total Assets	138,321	134,891
Current Liabilities:
Securities due within one year	3,076	4,285
Notes payable	1,726	2,609
Accounts payable —
Customer deposits	511	502
Accrued interest	573	614
Accrued compensation	936	1,127
Natural gas cost over recovery	165	0
Other regulatory liabilities	163	382
Other current liabilities	943	787
Total current liabilities	13,214	15,724
Long-term Debt	56,003	50,656
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	10,774	10,036
Deferred credits related to income taxes	4,813	5,235
Employee benefit obligations	1,184	1,238
Operating lease obligations	1,320	1,388
Other cost of removal obligations	1,940	1,903
Other deferred credits and liabilities	1,166	1,167
Total deferred credits and other liabilities	33,800	33,979
Total Liabilities	103,017	100,359
Total Stockholders' Equity	35,304	34,532
Total Liabilities and Stockholders' Equity	138,321	134,891
SOUTHERN Co GAS
Current Assets:
Cash and cash equivalents	397	81
Receivables —
Customer accounts	242	616
Unbilled revenues	74	453
Other accounts and notes	52	76
Accumulated provision for uncollectible accounts	(53)	(50)
Natural gas for sale	406	438
Prepaid expenses	92	93
Natural gas cost under recovery	0	108
Other regulatory assets	144	119
Other current assets	108	104
Total current assets	1,462	2,038
Property, Plant, and Equipment:
In service	20,459	19,723
Less: Accumulated depreciation	5,454	5,276
Plant in service, net of depreciation	15,005	14,447
Construction work in progress	1,158	909
Total property, plant, and equipment	16,163	15,356
Other Property and Investments:
Goodwill	5,015	5,015
Equity investments in unconsolidated subsidiaries	1,243	1,276
Other intangible assets, net of amortization	19	26
Miscellaneous property and investments	24	28
Total other property and investments	6,301	6,345
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	47	57
Prepaid pension costs	205	183
Other regulatory assets, deferred	483	497
Other deferred charges and assets	162	145
Total deferred charges and other assets	897	882
Total Assets	24,823	24,621
Current Liabilities:
Securities due within one year	400	400
Notes payable	75	768
Accounts payable —
Customer deposits	133	125
Accrued taxes	75	77
Accrued interest	79	67
Accrued compensation	85	105
Natural gas cost over recovery	165	0
Other regulatory liabilities	44	36
Other current liabilities	146	187
Total current liabilities	1,638	2,570
Long-term Debt	7,657	7,042
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,629	1,560
Deferred credits related to income taxes	766	788
Employee benefit obligations	108	120
Operating lease obligations	40	51
Other cost of removal obligations	1,748	1,707
Accrued environmental remediation	202	207
Other deferred credits and liabilities	202	179
Total deferred credits and other liabilities	4,695	4,612
Total Liabilities	13,990	14,224
Total Stockholders' Equity	10,833	10,397
Total Liabilities and Stockholders' Equity	24,823	24,621
SOUTHERN Co GAS | Related Party
Accounts payable —
Affiliated and Other	62	104
SOUTHERN Co GAS | Nonrelated Party
Accounts payable —
Affiliated and Other	$ 374	$ 701

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Condensed Consolidated Balance Sheets (Unaudited) - GAS (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Other intangible assets, amortization	$ 367	$ 340
SOUTHERN Co GAS
Other intangible assets, amortization	$ 163	$ 156

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Condensed Consolidated Statements of Stockholders' Equity (Unaudited) - GAS - USD ($) $ in Millions	Total	Paid-In Capital	Retained Earnings (Accumulated Deficit)	Accumulated Other Comprehensive Income (Loss)	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 at Dec. 31, 2021	$ 32,276	$ 11,950	$ 10,929	$ (237)	$ 9,916	$ 10,024	$ (132)	$ 24
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income					319		319
Capital contributions from parent company					50	50
Other comprehensive income	42			42	20			20
Cash dividends on common stock	(702)		(702)		(130)		(130)
Other	7	7	2
Ending balance at Mar. 31, 2022	32,629	11,994	11,261	(195)	10,175	10,074	57	44
Beginning balance at Dec. 31, 2021	32,276	11,950	10,929	(237)	9,916	10,024	(132)	24
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income	3,566				516
Ending balance at Sep. 30, 2022	35,476	13,657	12,374	(157)	10,438	10,397	(5)	46
Beginning balance at Mar. 31, 2022	32,629	11,994	11,261	(195)	10,175	10,074	57	44
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income					115		115
Capital contributions from parent company					312	312
Other comprehensive income	11			11	(12)			(12)
Cash dividends on common stock	(723)		(723)		(130)		(130)
Other	2	4
Ending balance at Jun. 30, 2022	33,013	12,033	11,645	(184)	10,460	10,386	42	32
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income	1,487				83		83
Capital contributions from parent company					11	11
Other comprehensive income	28			28	14			14
Cash dividends on common stock	(741)		(741)		(130)		(130)
Other	(8)	(4)	(2)	(1)
Ending balance at Sep. 30, 2022	35,476	13,657	12,374	(157)	10,438	10,397	(5)	46
Beginning balance at Dec. 31, 2022	34,532	13,673	11,538	(167)	10,397	10,445	(79)	31
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income					309		309
Capital contributions from parent company					203	203
Other comprehensive income	(44)			(44)	(10)			(10)
Cash dividends on common stock	(742)		(742)		(146)		(146)
Other	0	2			0	1	(1)
Ending balance at Mar. 31, 2023	34,562	13,715	11,658	(211)	10,753	10,649	83	21
Beginning balance at Dec. 31, 2022	34,532	13,673	11,538	(167)	10,397	10,445	(79)	31
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income	3,053				475
Ending balance at Sep. 30, 2023	35,304	13,751	12,391	(130)	10,833	10,838	(43)	38
Beginning balance at Mar. 31, 2023	34,562	13,715	11,658	(211)	10,753	10,649	83	21
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income					85		85
Capital contributions from parent company					40	40
Other comprehensive income	43			43	7			7
Cash dividends on common stock	(764)		(764)		(147)		(147)
Other	0	2
Ending balance at Jun. 30, 2023	34,648	13,742	11,732	(168)	10,738	10,689	21	28
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Consolidated Net Income	1,432				82		82
Capital contributions from parent company					149	149
Other comprehensive income	38			38	10			10
Cash dividends on common stock	(765)		(765)		(146)		(146)
Other	(1)	(2)	2
Ending balance at Sep. 30, 2023	$ 35,304	$ 13,751	$ 12,391	$ (130)	$ 10,833	$ 10,838	$ (43)	$ 38

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Introduction

9 Months Ended

Sep. 30, 2023

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, 2022 have been derived from the audited financial statements of each Registrant. In the opinion of each Registrant's management, the information regarding such Registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2023 and 2022. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each Registrant believes that the disclosures regarding such Registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy and other factors, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the overall results of operations, financial position, or cash flows of any Registrant.

Recently Adopted Accounting Standards

In March 2020 and December 2022, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting and ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, respectively, providing temporary guidance to ease the potential burden in accounting for reference rate reform primarily resulting from the discontinuation of LIBOR through December 31, 2024. See Note 1 to the financial statements under "Recently Adopted Accounting Standards" in Item 8 of the Form 10-K for additional information on the temporary guidance.

Certain provisions in PPAs at Southern Power include references to LIBOR. Contract amendments have been executed to change to a SOFR-based interest rate. Southern Power adopted and applied the practical expedients guidance to these PPAs. Additionally, the Registrants referenced LIBOR for certain debt and hedging arrangements. As of July 1, 2023, all of the debt and hedging arrangements of the Registrants have transitioned to a SOFR-based interest rate based on the terms of the agreements. There were no material impacts from the transition to SOFR and no impacts to any existing accounting conclusions. See Note (J) under "Interest Rate Derivatives" for additional information.

Goodwill and Other Intangible Assets

Goodwill at September 30, 2023 and December 31, 2022 was as follows:

	Goodwill
	(in millions)
Southern Company	$	5,161
Southern Company Gas:
Gas distribution operations	$	4,034
Gas marketing services	981
Southern Company Gas total	$	5,015

Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if goodwill impairment indicators arise.

Other intangible assets were as follows:

	At September 30, 2023						At December 31, 2022
	Gross Carrying Amount		Accumulated Amortization		Other Intangible Assets, Net		Gross Carrying Amount		Accumulated Amortization		Other Intangible Assets, Net
	(in millions)						(in millions)
Southern Company
Subject to amortization:
Customer relationships	$	211	$	(169)	$	42	$	212	$	(162)	$	50
Trade names	63		(50)		13		64		(44)		20
PPA fair value adjustments	390		(143)		247		390		(129)		261
Other	5		(5)		—		5		(5)		—
Total subject to amortization	$	669	$	(367)	$	302	$	671	$	(340)	$	331
Not subject to amortization:
FCC licenses	75		—		75		75		—		75
Total other intangible assets	$	744	$	(367)	$	377	$	746	$	(340)	$	406
Southern Power(*)
PPA fair value adjustments	$	390	$	(143)	$	247	$	390	$	(129)	$	261
Southern Company Gas(*)
Gas marketing services
Customer relationships	$	156	$	(143)	$	13	$	156	$	(139)	$	17
Trade names	26		(20)		6		26		(17)		9
Total other intangible assets	$	182	$	(163)	$	19	$	182	$	(156)	$	26

(*) All subject to amortization.

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Nine Months Ended		Three Months Ended		Nine Months Ended
	September 30, 2023				September 30, 2022
	(in millions)
Southern Company(a)	$	10	$	27	$	11	$	30
Southern Power(b)	5		14		5		15
Southern Company Gas	3		7		4		9

(a)Includes $5 million, $14 million, $5 million, and $15 million for the three and nine months ended September 30, 2023 and 2022, respectively, recorded as a reduction to operating revenues.

(b)Recorded as a reduction to operating revenues.

Cash, Cash Equivalents, and Restricted Cash

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

	Southern Company		Alabama Power		Georgia Power		Southern Power		Southern Company Gas
	(in millions)
At September 30, 2023
Cash and cash equivalents	$	1,676	$	621	$	173	$	236	$	397
Restricted cash(a):
Other current assets	176		108		48		18		2
Other deferred charges and assets	38		—		35		3		—
Total cash, cash equivalents, and restricted cash(b)	$	1,890	$	729	$	256	$	257	$	399
At December 31, 2022
Cash and cash equivalents	$	1,917	$	687	$	364	$	131	$	81
Restricted cash(a):
Other current assets	62		—		60		—		2
Other deferred charges and assets	58		—		56		3		—
Total cash, cash equivalents, and restricted cash(b)	$	2,037	$	687	$	480	$	133	$	83

(a)For Alabama Power, balance at September 30, 2023 reflects proceeds from the issuance of solid waste disposal facility revenue bonds in 2023. For Georgia Power, reflects proceeds from the issuance of solid waste disposal facility revenue bonds in 2022. For Southern Power, reflects $18 million at September 30, 2023 resulting from an arbitration interim award held to fund future replacement costs and $3 million at both September 30, 2023 and December 31, 2022 held to fund estimated construction completion costs at the Deuel Harvest wind facility. See Note (C) under "General Litigation Matters – Southern Power" for additional information. For Southern Company Gas, reflects collateral for workers' compensation, life insurance, and long-term disability insurance.

(b)Total may not add due to rounding.

Natural Gas for Sale

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

Southern Company Gas recorded no material adjustments to natural gas inventories for either period presented. Nicor Gas' inventory decrement at September 30, 2023 is expected to be restored prior to year-end.

Storm Damage Reserves

See Note 1 to the financial statements in Item 8 of the Form 10-K under "Storm Damage and Reliability Reserves" for additional information.

Storm damage reserve activity for the traditional electric operating companies during the nine months ended September 30, 2023 was as follows:

	Southern Company(*)		Alabama Power		Georgia Power(*)		Mississippi Power
	(in millions)
Balance at December 31, 2022	$	216	$	97	$	83	$	36
Accrual	42		9		24		9
Weather-related damages	(242)		(35)		(204)		(3)
Balance at September 30, 2023	$	16	$	71	$	(97)	$	42

(*)See Note (B) under "Georgia Power – Storm Damage Recovery" for additional information.

Asset Retirement Obligations

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

Following initial criticality on March 6, 2023, Georgia Power recorded AROs of approximately $90 million related to Plant Vogtle Unit 3. See Note (B) under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.

In September 2023, Georgia Power recorded a net decrease of approximately $175 million to its AROs related to the CCR Rule and the related state rule resulting from changes in estimates, including lower future inflation rates and the timing of closure activities.

In June 2023, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated cost of decommissioning based on the study resulted in a decrease in Alabama Power's ARO liability of approximately $15 million. See "Nuclear Decommissioning" herein for additional information.

Nuclear Decommissioning

See Note 6 to the financial statements in Item 8 of the Form 10-K under "Nuclear Decommissioning" for additional information. Site study cost is the estimate to decommission a specific facility as of the site study year. The decommissioning cost estimates are based on removal of the plant from service and prompt dismantlement. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.

The estimated costs of decommissioning Plant Farley based on Alabama Power's June 2023 site study are as follows:

	Plant Farley
Decommissioning periods:
Beginning year	2037
Completion year	2087
	(in millions)
Site study costs:
Radiated structures	$	1,402
Spent fuel management	513
Non-radiated structures	133
Total site study costs	$	2,048

For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an estimated inflation rate of 4.5% and an estimated trust earnings rate of 7.0%.

Amounts previously contributed to the external trust funds are currently projected to be adequate to meet the updated decommissioning obligations. Alabama Power's site-specific estimates of decommissioning costs for Plant Farley are updated every five years. The next site study for Alabama Power is expected to be completed in 2028. Projections of funds are reviewed with the Alabama PSC to ensure that, over time, the deposits and earnings of the funds in the external trust will provide adequate funding to cover the site-specific costs. If necessary, Alabama Power would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements.

Income Taxes

In the third quarter 2023, Georgia Power started generating advanced nuclear PTCs for Plant Vogtle Unit 3 beginning on the in-service date of July 31, 2023. PTCs are recognized as an income tax benefit based on KWH production. In addition, pursuant to the Global Amendments to the Vogtle Joint Ownership Agreements (as defined in Note (B) under "Georgia Power – Nuclear Construction – Joint Owner Contracts"), Georgia Power is purchasing advanced nuclear PTCs for Plant Vogtle Unit 3 from certain other Vogtle Owners. The gain recognized on the purchase of the joint owner PTCs is recognized as an income tax benefit. See Note 1 to the financial statements under "Income Taxes" in Item 8 of the Form 10-K for additional information regarding accounting policies related to income taxes. See Note (B) under "Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4. Also see Note (G) under "Current and Deferred Income Taxes" for additional information.

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Regulatory Matters

9 Months Ended

Sep. 30, 2023

Regulated Operations [Abstract]

Regulatory Matters

REGULATORY MATTERS

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

The recovery balances for certain retail regulatory clauses of the traditional electric operating companies and Southern Company Gas at September 30, 2023 and December 31, 2022 were as follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2023		December 31, 2022
		(in millions)
Alabama Power
Rate CNP Compliance	Other regulatory liabilities, deferred	$	3	$	—
	Other regulatory assets, current	—		47
Rate CNP PPA	Other regulatory assets, current	17		18
	Other regulatory assets, deferred	90		102
Retail Energy Cost Recovery	Other regulatory assets, current	208		102
	Other regulatory assets, deferred	80		520
Georgia Power
Fuel Cost Recovery(*)	Receivables – under recovered fuel clause revenues	$	730	$	—
	Deferred under recovered fuel clause revenues	1,279		2,056
Mississippi Power
Fuel Cost Recovery	Receivables – customer accounts, net	$	25	$	1
Ad Valorem Tax	Other regulatory assets, current	3		12
	Other regulatory assets, deferred	11		19
Southern Company Gas
Natural Gas Cost Recovery	Natural gas cost under recovery	$	—	$	108
	Natural gas cost over recovery	165		—

(*)See "Georgia Power – Fuel Cost Recovery" herein for additional information.

Alabama Power

Certificates of Convenience and Necessity

In 2020, the Alabama PSC approved a certificate of convenience and necessity authorizing Alabama Power's construction of Plant Barry Unit 8 and the recovery of estimated in-service costs of $652 million. At September 30, 2023, project expenditures associated with Plant Barry Unit 8 totaled approximately $583 million, of which $578 million and $5 million was included in CWIP and property, plant, and equipment in service, respectively. On November 1, 2023, the unit was placed in service. The ultimate outcome of this matter cannot be determined at this time.

Excess Accumulated Deferred Income Tax Accounting Order

On October 3, 2023, the Alabama PSC issued an order modifying its December 2022 order and authorizing Alabama Power to (i) flow back in 2023 approximately $24 million of certain federal excess accumulated deferred income taxes resulting from the Tax Cuts and Jobs Act of 2017 and (ii) make available any remaining balance of excess accumulated deferred income taxes at the end of 2023 for the benefit of customers in 2024 and/or 2025. The ultimate outcome of this matter cannot be determined at this time.

Rate CNP New Plant

On March 24, 2023, Alabama Power filed Rate CNP New Plant with the Alabama PSC to recover costs associated with the acquisition of the Central Alabama Generating Station. The filing reflected an annual increase in retail revenues of $78 million effective with June 2023 billings. Through May 2023, Alabama Power recovered substantially all costs associated with the Central Alabama Generating Station through Rate RSE, offset by revenues from a power sales agreement. On May 24, 2023, the Central Alabama Generating Station was placed into retail service. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.

Renewable Generation Certificate

Through the issuance of a Renewable Generation Certificate (RGC), Alabama Power is authorized by the Alabama PSC to procure renewable capacity and energy and to market the related energy and environmental attributes to customers and other third parties. On April 4, 2023, the Alabama PSC approved two new solar PPAs totaling 160 MWs. Upon approval of these PPAs, Alabama Power had procured solar capacity totaling approximately 490 MWs under the RGC's original 500-MW limit.

On June 14, 2023, the Alabama PSC issued an order approving modifications to Alabama Power's RGC. The modifications authorized Alabama Power to procure an additional 2,400 MWs of renewable capacity and energy by June 14, 2029 and to market the related energy and environmental attributes to customers and other third parties. The modifications also increased the size of allowable renewable projects from 80 MWs to 200 MWs and increased the annual approval limit from 160 MWs to 400 MWs.

Reliability Reserve Accounting Order

On July 11, 2023, the Alabama PSC issued an order authorizing Alabama Power to expand the existing authority of its reliability reserve to include certain production-related expenses that are intended to maintain reliability in between scheduled generating unit maintenance outages.

On August 18, 2023, Alabama Power notified the Alabama PSC of its intent to use a portion of its $166 million reliability reserve balance during 2023. The ultimate outcome of this matter cannot be determined at this time.

Georgia Power

Rate Plans

In accordance with the terms of the 2022 ARP, on October 2, 2023, Georgia Power filed the following tariff adjustments to become effective January 1, 2024 pending approval by the Georgia PSC:

•increase traditional base tariffs by approximately $275 million;

•decrease the Environmental Compliance Cost Recovery tariff by approximately $99 million;

•increase the Demand-Side Management tariffs by approximately $10 million; and

•increase the Municipal Franchise Fee tariffs by approximately $5 million.

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

Plant Vogtle Unit 3 and Common Facilities Rate Proceeding

In compliance with a Georgia PSC order approved in November 2021, Georgia Power increased annual retail base rates by $318 million effective August 1, 2023 based on the in-service date of July 31, 2023 for Plant Vogtle Unit 3. See "Plant Vogtle Units 3 and 4 Prudency Proceeding" and "Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

Plant Vogtle Units 3 and 4 Prudency Proceeding

On August 30, 2023, as provided for in the December 2017 Georgia PSC approval of the seventeenth VCM report, Georgia Power filed with the Georgia PSC an application to adjust rates to include reasonable and prudent Plant Vogtle Units 3 and 4 costs (Application). The Application provides the necessary support to justify the reasonableness, prudence, and recovery of $8.826 billion in total construction and capital costs, $1.07 billion in associated retail rate base items, and the operating costs related to the full operation and output of Plant Vogtle Units 3 and 4. Through the VCM process, the Georgia PSC has verified and approved all expenditures up to the revised approved construction and capital cost of $7.3 billion and has reviewed, but not verified and approved, all expenditures through December 31, 2022 above that amount.

Also on August 30, 2023, the staff of the Georgia PSC filed a stipulated agreement (Prudency Stipulation) among Georgia Power, the staff of the Georgia PSC, and certain intervenors. The Prudency Stipulation is intended to resolve all issues for determination by the Georgia PSC regarding the reasonableness, prudence, and cost recovery for the remaining costs not already in retail base rates, after considering many of the issues raised by the staff of the Georgia PSC and intervenors in prior VCM proceedings, including the extended construction time, required rework, scheduling of activities, and challenges with testing and productivity. If the Prudency Stipulation is approved, Georgia Power will recover $7.562 billion in total construction and capital costs and associated retail rate base items of $1.02 billion, which includes AFUDC financing costs above $4.418 billion (the Georgia PSC-certified amount) up to $7.562 billion.

The Prudency Stipulation also provides for the recovery of projected operations and maintenance expenses, depreciation expense, nuclear decommissioning accruals, and property taxes, net of projected production tax credits. After considering construction and capital costs already in retail base rates of $2.1 billion and $362 million of associated retail rate base items (approved by the Georgia PSC in November 2021), and upon achieving commercial operation of Unit 4, Georgia Power will include in retail rate base the remaining $5.462 billion of construction and capital costs as well as $656 million of associated retail rate base items.

Under the terms of the Prudency Stipulation, when the rate adjustment occurs, Georgia Power's NCCR tariff will cease to be collected and financing costs will be included in Georgia Power's general revenue requirements. Additionally, if commercial operation for Unit 4 is not achieved by March 31, 2024, Georgia Power's ROE used to determine the NCCR tariff and calculate AFUDC will be reduced to zero, which would result in an estimated negative impact to earnings of approximately $12 million per month until commercial operation for Unit 4 is achieved. The Prudency Stipulation also provides that as of each Unit's respective first refueling outage, if the respective Unit's performance has materially deviated from expected performance, the Georgia PSC may order Georgia Power to credit customers for operations and maintenance expenses or disallow costs associated with the repair or replacement of any system, structure, or component found to have caused the material deviation in performance if proven to be the result of imprudent engineering, construction, procurement, testing, or start-up.

If the Prudency Stipulation is approved by the Georgia PSC, annual retail base revenues will increase approximately $729 million and the average retail base rates will be adjusted by approximately 5% (net of the elimination of the NCCR tariff described above) effective the first day of the month after Unit 4 achieves commercial operation.

Georgia Power expects the Georgia PSC to render a final decision on these matters on December 19, 2023. The ultimate outcome of these matters cannot be determined at this time. See "Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" and "Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

Fuel Cost Recovery

On May 16, 2023, the Georgia PSC approved a stipulation agreement between Georgia Power and the staff of the Georgia PSC to increase annual fuel billings by 54%, or approximately $1.1 billion, effective June 1, 2023. The increase includes a three-year recovery period for $2.2 billion of Georgia Power's under recovered fuel balance at May 31, 2023. Under the approved stipulation agreement, Georgia Power is allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case, subject to a maximum 40% cumulative change, if its

under or over recovered fuel balance accumulated since May 31, 2023 exceeds $200 million. Georgia Power is scheduled to file its next fuel case no later than February 28, 2026. Changes in fuel rates have no significant effect on Southern Company's or Georgia Power's net income but do impact the related operating cash flows.

Integrated Resource Plans

In August 2022, Restore Chattooga Gorge Coalition (RCG) filed a petition in the Superior Court of Fulton County, Georgia against Georgia Power and the Georgia PSC. The petition challenges Georgia Power's plan to expend $115 million to modernize Plant Tugalo (a hydro facility), as approved in the 2019 IRP, and seeks judicial review of the Georgia PSC's order in the 2022 IRP proceeding with respect to the denial of RCG's challenge to the modernization plan. On October 23, 2023, the court granted Georgia Power's and the Georgia PSC's motions to dismiss the RCG petition. RCG has until November 22, 2023 to file a notice of appeal.

On October 27, 2023, Georgia Power filed an updated IRP (2023 IRP Update) with the Georgia PSC, which sets forth a plan to support the recent increase in the state of Georgia's projected energy needs since the 2022 IRP. In the 2023 IRP Update, Georgia Power requested the following:

•Authority to develop, own, and operate up to 1,400 MWs from three simple cycle combustion turbines at Plant Yates.

•Approval to pursue potential acquisition of an additional ownership interest in an existing generation asset within the Southern Company system's retail electric service territory.

•Certification of an affiliate PPA with Mississippi Power for 750 MWs starting January 2024 through December 2028.

•Certification of a non-affiliate PPA for 230 MWs starting the month after conclusion of the 2023 IRP Update proceeding continuing through December 2028.

•Authority to develop, own, and operate up to 1,000 MWs of battery energy storage facilities collocated with existing and new Georgia Power-owned solar facilities.

•Approval of transmission projects necessary to support the generation resources requested in the 2023 IRP Update.

The schedule for the Georgia PSC to consider the 2023 IRP Update has not been determined. Georgia Power has requested that the Georgia PSC evaluate the 2023 IRP Update by the end of April 2024.

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

Storm Damage Recovery

Georgia Power is recovering $31 million annually under the 2022 ARP for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. During August 2023, Hurricane Idalia caused significant damage to Georgia Power's transmission and distribution facilities. The incremental restoration costs related to this hurricane deferred in the regulatory asset for storm damage totaled approximately $110 million. At September 30, 2023, Georgia Power's regulatory asset balance related to storm damage was $97 million. The rate of storm damage cost recovery is expected to be adjusted in future regulatory proceedings as necessary. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's or Georgia Power's net income but do impact the related operating cash flows.

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, under which Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, 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, and mandatory prepayment events.

Cost and Schedule

Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4, including contingency, through July 2023 and March 2024, respectively, is as follows:

	(in millions)
Base project capital cost forecast(a)(b)	$	10,736
Construction contingency estimate	17
Total project capital cost forecast(a)(b)	10,753
Net investment at September 30, 2023(b)	(10,495)
Remaining estimate to complete	$	258

(a)Includes approximately $610 million of costs that are not shared with the other Vogtle Owners, including $33 million of construction monitoring costs approved for recovery by the Georgia PSC in its nineteenth VCM order, and approximately $567 million of incremental costs under the cost-sharing provisions of the joint ownership agreements described below. Excludes financing costs expected to be capitalized through AFUDC of approximately $420 million, of which $385 million had been accrued through September 30, 2023.

(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 $3.5 billion, of which $3.4 billion had been incurred through September 30, 2023.

Georgia Power placed Unit 3 in service on July 31, 2023. See "Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" herein for additional information.

As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts for Unit 4 on a regular basis to incorporate current information available, particularly in the areas of start-up testing and related test results, engineering support, system turnovers, and workforce statistics. Southern Nuclear establishes aggressive target values for monthly testing and system turnover activities, which are reflected in the site work plan for Unit 4.

Since March 2020, the number of active COVID-19 cases at the site has fluctuated consistent with the surrounding area and impacted productivity levels and pace of activity completion, with the site experiencing peaks in the

number of active cases in January 2021, August 2021, and January 2022. Georgia Power estimates the productivity impacts of the COVID-19 pandemic have consumed approximately three to four months of schedule margin previously embedded in the site work plans. As of September 30, 2023, Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is estimated to be approximately $200 million and is included in the total project capital cost forecast.

During the first nine months of 2023, established construction contingency totaling $43 million was assigned to the base capital cost forecast for costs primarily associated with the Unit 3 schedule extension and completion of start-up and pre-operational testing, including continued need of support resources for Unit 3 testing, as well as additional craft and support resources and subcontract work for Unit 4.

Hot functional testing for Unit 4 was completed on May 1, 2023. On July 20, 2023, Southern Nuclear announced that all Unit 4 ITAACs had been submitted to the NRC, and, on July 28, 2023, the NRC published its 103(g) finding that the accepted criteria in the combined license for Unit 4 had been met, which allowed nuclear fuel to be loaded and start-up testing to begin. Fuel load for Unit 4 was completed on August 19, 2023. On October 6, 2023, Georgia Power announced that during the start-up and pre-operational testing for Plant Vogtle Unit 4, Southern Nuclear identified a motor fault in one of four reactor coolant pumps (RCPs) and has started the process to replace this RCP with an on-site spare RCP from inventory. Considering this remediation and the remaining pre-operational testing, Unit 4 is projected to be placed in service during the first quarter 2024.

With Unit 3's four RCPs operating as designed, Southern Nuclear believes that the motor fault on this single Unit 4 RCP is an isolated event. However, any findings related to the root cause of the motor fault on the single Unit 4 RCP could require engineering changes or remediation related to the other seven Unit 3 and Unit 4 RCPs. The projected schedule for Unit 4 significantly depends on the pace and success of replacing the RCP, which involves removing and re-installing commodities around the RCP. As Unit 4 completes the RCP replacement, including any associated repairs to other RCPs, and transitions further into testing, ongoing and potential future challenges include the management of contractors and vendors, subcontractor performance, the availability of materials and parts, and/or related cost escalation; the pace of remaining work package closures; the availability of craft, supervisory, and technical support resources; and the timeframe and duration of final component and pre-operational testing. New challenges also may continue to arise as Unit 4 moves further into testing and start-up, which may result in required engineering changes or remediation related to plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale). These challenges may result in further schedule delays and/or cost increases.

There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to ensure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. With the receipt of the NRC's 103(g) findings for Units 3 and 4 in August 2022 and July 2023, respectively, the site is subject to the NRC's operating reactor oversight process and must meet applicable technical and operational requirements contained in its operating license. Various design and other licensing-based compliance matters may result in additional license amendment requests or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the Unit 4 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 March 2024 for Unit 4, including the joint owner cost sharing impacts described below, is estimated to result in additional base capital costs for Georgia Power of up to $25 million per month, as well as the related AFUDC and any additional related construction, support resources, or testing costs. Pursuant to Georgia Power's Application and the Prudency Stipulation (as discussed under "Plant Vogtle Units 3 and 4 Prudency Proceeding" herein), any further changes to the capital cost forecast are not expected to be recoverable through regulated rates and will be required to be charged to income. 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.

Amendments to the Vogtle Joint Ownership Agreements

In connection with a September 2018 vote by the Vogtle Owners to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide up to $300 million of funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. In January 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. In February 2019, Georgia Power, the other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet (Global Amendments).

Pursuant to the Global Amendments: (i) each Vogtle Owner paid 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, of which Georgia Power's share is $8.4 billion (VCM 19 Forecast Amount), plus $800 million; (ii) Georgia Power was responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the VCM 19 Forecast Amount (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 was responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the VCM 19 Forecast Amount (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests. The Global Amendments provide that if the EAC was revised and exceeded the VCM 19 Forecast Amount by more than $2.1 billion, each of the other Vogtle Owners had a one-time option at the time the project budget cost forecast was 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 VCM 19 Forecast Amount 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 (Project Adverse Events) occur, including, among other events: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power's public announcement of its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Global Amendments described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more from the seventeenth VCM report estimated in-

service dates of November 2021 and November 2022 for Units 3 and 4, respectively. The schedule extension announced in February 2022 triggered the requirement for a vote to continue construction and all the Vogtle Owners voted to continue construction. The filing of the Application with the Georgia PSC, which included Georgia Power's public announcement of its intention not to submit for rate recovery an amount that is greater than the first 6% of costs during any six-month VCM reporting period, triggered the requirement for a vote to continue construction and all the Vogtle Owners voted to continue construction. See "Plant Vogtle Units 3 and 4 Prudency Proceeding" herein for additional information on Georgia Power's prudency application filing.

Georgia Power and the other Vogtle Owners did not agree on either the starting dollar amount for the determination of cost increases subject to the cost-sharing and tender provisions of the Global Amendments or the extent to which COVID-19-related costs impact those provisions. The other Vogtle Owners notified Georgia Power that they believed the project capital cost forecast approved by the Vogtle Owners in February 2022 triggered the tender provisions. In June 2022 and July 2022, OPC and Dalton, respectively, notified Georgia Power of their purported exercises of their tender options. Georgia Power did not accept these purported tender exercises.

In June 2022, OPC and MEAG Power each filed a separate lawsuit against Georgia Power in the Superior Court of Fulton County, Georgia seeking a declaratory judgment that the starting dollar amount is $17.1 billion and that the cost-sharing and tender provisions had been triggered. The lawsuits also assert other claims, including breach of contract allegations, and seek, among other remedies, damages and injunctive relief requiring Georgia Power to track and allocate construction costs consistent with MEAG Power's and OPC's interpretations of the Global Amendments. In July 2022, Georgia Power filed its answers in the lawsuits filed by MEAG Power and OPC and included counterclaims seeking a declaratory judgment that the starting dollar amount is $18.38 billion and that costs related to force majeure events are excluded prior to calculating the cost-sharing and tender provisions and when calculating Georgia Power's related financial obligations. In September 2022, Dalton filed complaints in each of these lawsuits.

Also in September 2022, Georgia Power and MEAG Power reached an agreement to resolve their dispute regarding the proper interpretation of the cost-sharing and tender provisions of the Global Amendments. Under the terms of the agreement, among other items, (i) MEAG Power will not exercise its tender option and will retain its full ownership interest in Plant Vogtle Units 3 and 4; (ii) Georgia Power will reimburse a portion of MEAG Power's costs of construction for Plant Vogtle Units 3 and 4 as such costs are incurred and with no further adjustment for force majeure costs, which payments will total approximately $92 million based on the current project capital cost forecast; and (iii) Georgia Power will reimburse 20% of MEAG Power's costs of construction with respect to any amounts over the current project capital cost forecast, with no further adjustment for force majeure costs. In addition, MEAG Power agreed to vote to continue construction upon occurrence of a Project Adverse Event unless the commercial operation date of either of Plant Vogtle Unit 3 or Unit 4 is not projected to occur by December 31, 2025. In October 2022, MEAG Power and Georgia Power filed a notice of settlement and voluntary dismissal of their pending litigation, including Georgia Power's counterclaim, and Dalton dismissed its related complaint.

On October 5, 2023 and October 17, 2023, Georgia Power reached agreements with OPC and Dalton, respectively, to resolve its respective dispute with each of OPC and Dalton regarding the proper interpretation of the cost-sharing and tender provisions of the joint ownership agreements relating to the Global Amendments. Under the terms of the agreements with OPC and Dalton, among other items, (i) each of OPC and Dalton retracted its exercise of the tender option and will retain its full ownership interest in Plant Vogtle Units 3 and 4, (ii) Georgia Power made payments immediately after execution of the agreements of $308 million and $17 million to OPC and Dalton, respectively, representing payment for a portion of each of OPC's and Dalton's costs of construction for Plant Vogtle Units 3 and 4 previously incurred, (iii) Georgia Power will pay a portion of each of OPC's and Dalton's further costs of construction for Plant Vogtle Units 3 and 4 as such costs are incurred and with no further adjustment for force majeure costs, which payments will be in an aggregate amount of approximately $105 million and $6 million for OPC and Dalton, respectively, based on the current project capital cost forecast, and (iv) Georgia Power will pay 66% of each of OPC's and Dalton's costs of construction with respect to any amounts above the current project capital cost forecast, with no further adjustment for force majeure costs. On October 23, 2023, OPC, Dalton, and

Georgia Power filed a stipulation of dismissal with prejudice of their litigation described above, including Georgia Power's counterclaims.

Georgia Power recorded pre-tax charges to income through the fourth quarter 2022 of $407 million ($304 million after tax) associated with the cost-sharing provisions of the Global Amendments, including the settlement with MEAG Power. Based on the current project capital cost forecast and the settlements with OPC and Dalton described above, Georgia Power recorded a pre-tax charge to income of approximately $160 million ($120 million after tax) in the third quarter 2023. These charges are included in the total project capital cost forecast and will not be recovered from retail customers.

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

Regulatory Matters

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At September 30, 2023, Georgia Power had recovered approximately $3.0 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 is not recording AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery. In December 2022, the Georgia PSC approved Georgia Power's filing to increase the NCCR tariff by $36 million annually, effective January 1, 2023. On November 1, 2023, Georgia Power filed a request to continue the current NCCR tariff for 2024, pending Georgia PSC approval. See "Plant Vogtle Units 3 and 4 Prudency Proceeding" herein for additional information on the NCCR tariff following commercial operation of Unit 4.

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 at that time) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%,

effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that effective the first month after Unit 3 reaches commercial operation, retail base rates would be adjusted to include the costs related to Unit 3 and common facilities deemed prudent in the Vogtle Cost Settlement Agreement. On July 31, 2023, Georgia Power notified the Georgia PSC that Unit 3 had reached commercial operation, and, effective August 1, 2023, Georgia Power adjusted retail base rates for Unit 3 and the common facilities shared between Units 3 and 4 (see "Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" herein for additional information). On August 19, 2023, fuel load for Unit 4 was completed, and, on August 30, 2023, Georgia Power filed an application to adjust rates to include reasonable and prudent Plant Vogtle Units 3 and 4 costs (see "Plant Vogtle Units 3 and 4 Prudency Proceeding" herein for additional information).

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 $300 million in 2022 and are estimated to have negative earnings impacts of approximately $290 million in 2023 and $60 million in 2024. 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. See "Plant Vogtle Units 3 and 4 Prudency Proceeding" herein for additional information on impacts to the NCCR tariff if commercial operation for Unit 4 is not achieved by March 31, 2024.

In the August 2021 order approving the twenty-fourth VCM report, the Georgia PSC approved a stipulation addressing the following matters: (i) beginning with its twenty-fifth VCM report, Georgia Power will continue to report to the Georgia PSC all costs incurred during the period for review and will request for approval costs up to the $7.3 billion determined to be reasonable in the Georgia PSC's seventeenth VCM order and (ii) Georgia Power will not seek rate recovery of the $0.7 billion increase to the base capital cost forecast included in the nineteenth VCM report and charged to income by Georgia Power in the second quarter 2018. In addition, the August 2021 stipulation confirmed that Georgia Power may request verification and approval of costs above $7.3 billion for inclusion in rate base at a later time, but no earlier than the prudence review contemplated by the seventeenth VCM order described previously. See "Plant Vogtle Units 3 and 4 Prudency Proceeding" herein for additional information on Georgia Power's request for verification and approval of costs above $7.3 billion for inclusion in rate base.

The Georgia PSC approved 25 VCM reports covering periods through June 30, 2021. These reports reflect total construction capital costs incurred of $7.9 billion (net of $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds), of which the Georgia PSC has verified and approved $7.3 billion as described above. The Georgia PSC also has reviewed three additional VCM reports, which reflected $1.6 billion of additional construction capital costs incurred through December 31, 2022. Georgia Power filed its twenty-ninth VCM report with the Georgia PSC on August 30, 2023, which reflects the revised capital cost forecast as of June 30, 2023 of $10.6 billion and $390 million of construction capital costs incurred from January 1, 2023 through June 30, 2023.

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

Mississippi Power

Performance Evaluation Plan

On June 13, 2023, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2023 indicating no change in retail rates.

Ad Valorem Tax Adjustment

On May 2, 2023, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment filing for 2023, resulting in a $7 million annual decrease in revenues effective with the first billing cycle of June 2023.

Mississippi Power's operating revenues are adjusted for differences in actual recoverable ad valorem taxes and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on Mississippi Power's revenues or net income but will affect operating cash flows.

Environmental Compliance Overview Plan

On April 4, 2023, the Mississippi PSC approved Mississippi Power's annual ECO Plan filing for 2023, resulting in a $3 million annual increase in revenues effective with the first billing cycle of May 2023.

System Restoration Rider

On April 4, 2023, the Mississippi PSC approved Mississippi Power's annual SRR filing, which indicated no change in retail rates. Mississippi Power's minimum annual SRR accrual was increased from $8 million to $12 million.

Municipal and Rural Associations Tariff

On October 27, 2023, the FERC approved a settlement agreement filed by Mississippi Power and Cooperative Energy on July 31, 2023 related to Mississippi Power's July 2022 request for a $23 million increase in annual wholesale base revenues under the MRA tariff. The settlement agreement provides for a $16 million increase in annual wholesale base revenues, effective September 14, 2022, and a refund to customers of approximately $6 million primarily related to the difference between the approved rates and interim rates.

Integrated Resource Plans

In October 2023, Mississippi Power signed an affiliate PPA with Georgia Power for 750 MWs of capacity and energy starting January 2024 through December 2028. In order to fulfill this agreement and serve the interests of customers, Mississippi Power will need to delay the anticipated retirement of certain electric generating units, as identified in its 2021 IRP. Mississippi Power is expected to file its next IRP in April 2024 in accordance with the rules and orders of the Mississippi PSC.

Southern Company Gas

Infrastructure Replacement Programs and Capital Projects

Capital expenditures incurred under specific infrastructure replacement programs and capital projects during the first nine months of 2023 were as follows:

Utility	Program	Nine Months Ended September 30, 2023
		(in millions)
Nicor Gas	Investing in Illinois	$	320
Virginia Natural Gas	SAVE	56
Atlanta Gas Light	System Reinforcement Rider	84
Chattanooga Gas	Pipeline Replacement Program	7
Total		$	467

Nicor Gas

On June 15, 2023, the Illinois Commission concluded its review of the Qualifying Infrastructure Plant (QIP) capital investments by Nicor Gas for calendar year 2019 under the QIP Rider, also referred to as Investing in Illinois, program. The Illinois Commission disallowed $32 million of the $415 million of capital investments commissioned in 2019, together with the related return on investment. Nicor Gas recorded a pre-tax charge to income in the second quarter 2023 of $38 million ($28 million after tax) associated with the disallowance of capital investments. The disallowance is reflected on the statement of income as an $8 million reduction to revenues and a $30 million increase in operating expenses. On August 3, 2023, the Illinois Commission denied a rehearing request filed by Nicor Gas. On August 24, 2023, Nicor Gas filed a notice of appeal with the Illinois Appellate Court. Nicor Gas defends these investments in infrastructure as prudently incurred. The Illinois Commission has not yet conducted its review for calendar years 2020 through 2022 or the nine months ended September 30, 2023. Any further disallowance by the Illinois Commission could be material. The ultimate outcome of these matters cannot be determined at this time.

Rate Proceedings

Atlanta Gas Light

On July 14, 2023, Atlanta Gas Light filed its annual GRAM update with the Georgia PSC. The filing requests an annual base rate increase of $53 million based on the projected 12-month period beginning January 1, 2024. Resolution of the GRAM filing is expected by December 31, 2023, with new rates effective January 1, 2024. The ultimate outcome of this matter cannot be determined at this time.

Virginia Natural Gas

On August 28, 2023, the Virginia Commission approved a stipulation agreement related to Virginia Natural Gas' August 2022 general base rate case filing. The approved agreement provides for a $48 million increase in annual base rate revenues, including the recovery of investments under the SAVE program, an ROE of 9.70%, and an equity ratio of 49.06%. Interim rates became effective January 1, 2023, subject to refund, based on Virginia Natural Gas' original requested increase of approximately $69 million. Refunds to customers related to the difference between the approved rates effective September 1, 2023 and the interim rates will be completed later in the fourth quarter 2023.

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Contingencies

9 Months Ended

Sep. 30, 2023

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 and Mississippi Power

In 2010, the DOE, through a cooperative agreement with SCS, agreed to fund $270 million of the Kemper County energy facility through the grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2. In 2016, additional DOE grants in the amount of $137 million were awarded to the Kemper County energy facility. In 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of total grants received. In 2020, Mississippi Power and Southern Company executed an agreement with the DOE completing Mississippi Power's request, which enabled Mississippi Power to proceed with full dismantlement of the abandoned gasifier-related assets and site restoration activities. In connection with the DOE closeout discussions, in 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of a civil investigation related to the DOE grants. On August 4, 2023, the U.S. District Court for the Northern District of Georgia unsealed a civil action in which defendants Southern Company, SCS, and Mississippi Power are alleged to have violated certain provisions of the False Claims Act by fraudulently inducing the DOE to disburse funds pursuant to the grants. The federal government declined to intervene in the action. On October 30, 2023, the plaintiff, a former SCS employee, filed an amended complaint, again alleging certain violations of the False Claims Act. The plaintiff seeks to recover all damages incurred personally and on behalf of the government caused by the defendants' alleged violations, as well as treble damages and attorneys' fees, among other relief. The ultimate outcome of this matter cannot be determined at this time; however, an adverse outcome could have a material impact on Southern Company's and Mississippi Power's financial statements.

Alabama Power

In September 2022, Mobile Baykeeper filed a citizen suit in the U.S. District Court for the Southern District of Alabama alleging that Alabama Power's plan to close the Plant Barry ash pond utilizing a closure-in-place methodology violates the Resource Conservation and Recovery Act (RCRA) and regulations governing CCR. Among other relief requested, Mobile Baykeeper seeks a declaratory judgment that the RCRA and regulations governing CCR are being violated, preliminary and injunctive relief to prevent implementation of Alabama Power's closure plan and the development of a closure plan that satisfies regulations governing CCR requirements. On December 19, 2022, Alabama Power filed a motion to dismiss the case. On September 30, 2023, the magistrate judge issued a report and recommendation to deny Alabama Power's motion to dismiss, to which Alabama Power has filed objections.

On January 31, 2023, the EPA issued a Notice of Potential Violations associated with Alabama Power's plan to close the Plant Barry ash pond. Alabama Power has affirmed to the EPA its position that it is in compliance with CCR requirements.

The ultimate outcome of these matters cannot be determined at this time but could have a material impact on Alabama Power's ARO estimates and cash flows. See Note 6 to the financial statements in Item 8 of the Form 10-K for a discussion of Alabama Power's ARO liabilities.

Georgia Power

Municipal Franchise Fees

In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state law claims. This case has been ruled upon and appealed numerous times over the last several years. In 2019, the Georgia PSC issued an order that found Georgia Power has appropriately implemented the municipal franchise fee schedule. In March 2021, the Superior Court of Fulton County granted class certification and Georgia Power's motion for summary judgment and the plaintiffs filed a notice of appeal. In April 2021, Georgia Power filed a notice of cross appeal on the issue of class certification. In December 2021, the Georgia Court of Appeals affirmed the Superior Court's ruling that granted summary judgment to Georgia Power and dismissed Georgia Power's cross appeal on the

issue of class certification as moot. Also in December 2021, the plaintiffs filed a petition for writ of certiorari to the Georgia Supreme Court, which was denied on January 27, 2023. On February 6, 2023, the plaintiffs filed a motion for reconsideration with the Georgia Supreme Court, which was denied on February 16, 2023. This matter is now concluded.

Plant Scherer

In July 2020, a group of individual plaintiffs filed a complaint, which was amended in December 2022, in the Superior Court of Fulton County, Georgia against Georgia Power alleging that the construction and operation of Plant Scherer has impacted groundwater 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 December 2022, the Superior Court of Fulton County, Georgia granted Georgia Power's motion to transfer the case to the Superior Court of Monroe County, Georgia. On May 9, 2023, the Superior Court of Monroe County, Georgia denied Georgia Power's motion to dismiss the case for lack of subject matter jurisdiction. On July 27, 2023, the Superior Court of Monroe County, Georgia denied the remaining motions to dismiss certain claims and plaintiffs that Georgia Power filed at the outset of the case.

In October 2021, February 2022, and January 2023, a total of eight additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs sought an unspecified amount of monetary damages including punitive damages. After Georgia Power removed these cases to the U.S. District Court for the Middle District of Georgia, the plaintiffs voluntarily dismissed their complaints without prejudice in November 2022 and January 2023. On May 12, 2023, the plaintiffs in the cases originally filed in October 2021, February 2022, and January 2023 refiled their eight complaints in the Superior Court of Monroe County, Georgia. Also on May 12, 2023, a new complaint was filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that the construction and operation of Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries. The plaintiff seeks an unspecified amount of monetary damages, including punitive damages. On May 18, 2023, Georgia Power removed all of these cases to the U.S. District Court for the Middle District of Georgia. The plaintiffs are requesting the court remand the cases back to the Superior Court of Monroe County, Georgia.

The amount of possible loss, if any, from these matters cannot be estimated at this time.

Mississippi Power

In 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi, which was amended in March 2019 to include four additional plaintiffs. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper and make claims for gross negligence, reckless conduct, and intentional wrongdoing. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. The district court dismissed the amended complaint; however, in March 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. In July 2020, the plaintiffs filed a motion for leave to file a third amended complaint, which included the same federal claims as the proposed second amended complaint, as well as several additional state law claims based on the allegation that Mississippi Power failed to disclose the annual percentage rate of interest applicable to refunds. In November 2020, the district court denied each of the plaintiffs' pending

motions and entered final judgment in favor of Mississippi Power. In January 2021, the district court denied further motions by the plaintiffs to vacate the judgment and to file a revised second amended complaint. In February 2021, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fifth Circuit. In March 2022, the U.S. Court of Appeals for the Fifth Circuit issued an opinion affirming the dismissal of the claims against the Mississippi PSC defendants but reversing the dismissal of the claims against Mississippi Power. In May 2022, the U.S. Court of Appeals for the Fifth Circuit denied a petition by Mississippi Power for a rehearing en banc and remanded the case to the U.S. District Court for the Southern District of Mississippi for further proceedings. In June 2022, Mississippi Power filed with the trial court a motion to dismiss the complaint with prejudice, which was granted on March 15, 2023. On March 28, 2023, 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.

Southern Power

In July 2021, Southern Power and certain of its subsidiaries filed an arbitration demand with the American Arbitration Association against First Solar for defective design of actuators on trackers and inverters installed by First Solar under the engineering, procurement, and construction agreements associated with five solar projects owned by Southern Power and partners and managed by Southern Power. In February 2023, arbitration hearings concluded. In July 2023, an interim award of approximately $36 million was entered in favor of Southern Power and was subsequently received in September 2023. The interim award included $18 million representing recovery of losses associated with replacement costs, penalty payments, and lost revenues previously incurred. This recovery is reflected in Southern Power's third quarter and year-to-date 2023 statements of income as an $11 million reduction to other operations and maintenance expense and a $7 million increase in other revenues, with $6 million allocated through noncontrolling interests to Southern Power's partners. The remaining $18 million in award proceeds received in excess of the losses incurred is recognized on the balance sheet at September 30, 2023 as restricted cash and a liability to fund future replacement costs. The parties are awaiting issuance of a final award. The ultimate outcome of this matter cannot be determined at this time.

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 $14 million and $15 million at September 30, 2023 and December 31, 2022, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.

Southern Company Gas' environmental remediation liability was $234 million and $256 million at September 30, 2023 and December 31, 2022, 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

Traditional Electric Operating Companies

In April 2019, Bellsouth Telecommunications d/b/a AT&T Alabama (AT&T) filed a complaint against Alabama Power with the FCC alleging that the pole rental rate AT&T is required to pay pursuant to the parties' joint use agreement is unjust and unreasonable under federal law. The complaint sought a new rate and approximately $87 million in refunds of alleged overpayments for the preceding six years. In August 2019, the FCC stayed the case in favor of arbitration, which AT&T has not pursued. The ultimate outcome of this matter cannot be determined at this time, but an adverse outcome could have a material impact on the financial statements of Southern Company and Alabama Power. Georgia Power and Mississippi Power have joint use agreements with other AT&T affiliates.

Mississippi Power

In August 2022, the Mississippi Department of Revenue (Mississippi DOR) completed an audit of sales and use taxes paid by Mississippi Power from 2016 to 2019 and entered a final assessment, indicating a total amount due of $28 million, including associated penalties and interest. In October 2022, Mississippi Power filed an administrative appeal with the Mississippi DOR contesting the assessment. On October 2, 2023, Mississippi Power and the Mississippi DOR reached a settlement agreement on an assessment of approximately $11 million including associated penalties and interest, $7 million of which was previously paid by Mississippi Power. On October 5, 2023, Mississippi Power made a final $4 million payment and considers this matter closed.

Pursuant to an accounting order approved by the Mississippi PSC in December 2022, Mississippi Power deferred $3 million of the agreed upon assessment related to taxes and associated interest to a regulatory asset for disposition in a future rate proceeding.

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Revenue from Contracts with Customers and Lease Income

9 Months Ended

Sep. 30, 2023

Revenue from Contract with Customer [Abstract]

Revenue from Contracts with Customers and Lease Income

REVENUE FROM CONTRACTS WITH CUSTOMERS AND LEASE INCOME

Revenue from Contracts with Customers

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

The following table disaggregates revenue from contracts with customers for the three and nine months ended September 30, 2023 and 2022:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2023
Operating revenues
Retail electric revenues
Residential	$	2,543	$	969	$	1,473	$	101	$	—	$	—
Commercial	1,845		599		1,151		95		—		—
Industrial	1,116		498		528		90		—		—
Other	30		3		25		2		—		—
Total retail electric revenues	5,534		2,069		3,177		288		—		—
Natural gas distribution revenues
Residential	217		—		—		—		—		217
Commercial	56		—		—		—		—		56
Transportation	275		—		—		—		—		275
Industrial	4		—		—		—		—		4
Other	60		—		—		—		—		60
Total natural gas distribution revenues	612		—		—		—		—		612
Wholesale electric revenues
PPA energy revenues	317		66		31		2		226		—
PPA capacity revenues	151		26		13		3		110		—
Non-PPA revenues	101		15		21		137		126		—
Total wholesale electric revenues	569		107		65		142		462		—
Other natural gas revenues
Gas marketing services	54		—		—		—		—		54
Other natural gas revenues	8		—		—		—		—		8
Total natural gas revenues	62		—		—		—		—		62
Other revenues	330		54		146		10		18		—
Total revenue from contracts with customers	7,107		2,230		3,388		440		480		674
Other revenue sources(*)	(127)		(147)		(151)		(4)		173		15
Total operating revenues	$	6,980	$	2,083	$	3,237	$	436	$	653	$	689

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Nine Months Ended September 30, 2023
Operating revenues
Retail electric revenues
Residential	$	5,717	$	2,277	$	3,202	$	238	$	—	$	—
Commercial	4,464		1,493		2,733		238		—		—
Industrial	2,770		1,324		1,195		251		—		—
Other	84		10		68		6		—		—
Total retail electric revenues	13,035		5,104		7,198		733		—		—
Natural gas distribution revenues
Residential	1,443		—		—		—		—		1,443
Commercial	370		—		—		—		—		370
Transportation	878		—		—		—		—		878
Industrial	33		—		—		—		—		33
Other	228		—		—		—		—		228
Total natural gas distribution revenues	2,952		—		—		—		—		2,952
Wholesale electric revenues
PPA energy revenues	853		196		66		8		601		—
PPA capacity revenues	490		130		38		36		289		—
Non-PPA revenues	199		49		30		315		312		—
Total wholesale electric revenues	1,542		375		134		359		1,202		—
Other natural gas revenues
Gas marketing services	358		—		—		—		—		358
Other natural gas revenues	28		—		—		—		—		28
Total natural gas revenues	386		—		—		—		—		386
Other revenues	971		159		422		31		46		—
Total revenue from contracts with customers	18,886		5,638		7,754		1,123		1,248		3,338
Other revenue sources(*)	322		(218)		51		14		438		79
Total operating revenues	$	19,208	$	5,420	$	7,805	$	1,137	$	1,686	$	3,417

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2022
Operating revenues
Retail electric revenues
Residential	$	2,104	$	799	$	1,212	$	93	$	—	$	—
Commercial	1,637		499		1,051		87		—		—
Industrial	1,183		452		642		89		—		—
Other	27		3		22		2		—		—
Total retail electric revenues	4,951		1,753		2,927		271		—		—
Natural gas distribution revenues
Residential	331		—		—		—		—		331
Commercial	93		—		—		—		—		93
Transportation	259		—		—		—		—		259
Industrial	12		—		—		—		—		12
Other	49		—		—		—		—		49
Total natural gas distribution revenues	744		—		—		—		—		744
Wholesale electric revenues
PPA energy revenues	812		187		40		4		591		—
PPA capacity revenues	175		56		12		1		107		—
Non-PPA revenues	58		67		4		242		303		—
Total wholesale electric revenues	1,045		310		56		247		1,001		—
Other natural gas revenues
Gas marketing services	84		—		—		—		—		84
Other natural gas revenues	15		—		—		—		—		15
Total natural gas revenues	99		—		—		—		—		99
Other revenues	277		65		110		13		9		—
Total revenue from contracts with customers	7,116		2,128		3,093		531		1,010		843
Other revenue sources(*)	1,262		316		796		(21)		170		14
Total operating revenues	$	8,378	$	2,444	$	3,889	$	510	$	1,180	$	857

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Nine Months Ended September 30, 2022
Operating revenues
Retail electric revenues
Residential	$	5,282	$	2,049	$	2,995	$	238	$	—	$	—
Commercial	4,202		1,285		2,688		229		—		—
Industrial	2,914		1,143		1,529		242		—		—
Other	79		10		62		7		—		—
Total retail electric revenues	12,477		4,487		7,274		716		—		—
Natural gas distribution revenues
Residential	1,821		—		—		—		—		1,821
Commercial	493		—		—		—		—		493
Transportation	872		—		—		—		—		872
Industrial	60		—		—		—		—		60
Other	244		—		—		—		—		244
Total natural gas distribution revenues	3,490		—		—		—		—		3,490
Wholesale electric revenues
PPA energy revenues	1,739		354		112		11		1,285		—
PPA capacity revenues	443		135		35		4		273		—
Non-PPA revenues	182		166		19		511		572		—
Total wholesale electric revenues	2,364		655		166		526		2,130		—
Other natural gas revenues
Gas marketing services	417		—		—		—		—		417
Other natural gas revenues	41		—		—		—		—		41
Total natural gas revenues	458		—		—		—		—		458
Other revenues	810		173		327		34		27		—
Total revenue from contracts with customers	19,599		5,315		7,767		1,276		2,157		3,948
Other revenue sources(*)	2,633		708		1,451		3		461		50
Total operating revenues	$	22,232	$	6,023	$	9,218	$	1,279	$	2,618	$	3,998

(*)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 (including those related to fuel costs) that meet other scope exceptions for revenues from contracts with customers at the traditional electric operating companies.

Contract Balances

The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers at September 30, 2023 and December 31, 2022:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Accounts Receivable
At September 30, 2023	$	2,680	$	858	$	1,175	$	106	$	138	$	331
At December 31, 2022	3,123		696		922		92		237		1,107
Contract Assets
At September 30, 2023	$	267	$	6	$	146	$	—	$	—	$	41
At December 31, 2022	156		2		89		—		—		—
Contract Liabilities
At September 30, 2023	$	62	$	—	$	8	$	2	$	8	$	—
At December 31, 2022	45		4		9		—		1		—

Contract assets for Georgia Power primarily relate to retail customer fixed bill programs, where the payment is contingent upon Georgia Power's continued performance and the customer's continued participation in the program over a one-year contract term, and unregulated service agreements, where payment is contingent on project completion. Contract liabilities for Georgia Power primarily relate to cash collections recognized in advance of revenue for unregulated service agreements. At September 30, 2023, Southern Company Gas' contract assets relate to work performed on an energy efficiency enhancement and upgrade contract with the U.S. General Services Administration. Southern Company Gas receives cash advances from a third-party financial institution to fund work performed, of which approximately $51 million had been received at September 30, 2023. These advances have been accounted for as long-term debt on the balance sheets. See Note 1 to the financial statements under "Affiliate Transactions" in Item 8 of the Form 10-K for additional information regarding the construction contract. At September 30, 2023 and December 31, 2022, Southern Company's unregulated distributed generation business had contract assets of $75 million and $65 million, respectively, and contract liabilities of $47 million and $32 million, respectively, for outstanding performance obligations.

Revenues recognized in the three and nine months ended September 30, 2023, which were included in contract liabilities at December 31, 2022, were immaterial for the applicable Registrants. Contract liabilities are primarily classified as current on the balance sheets as the corresponding revenues are generally expected to be recognized within one year.

Remaining Performance Obligations

The Subsidiary Registrants may enter into long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. For Alabama Power, Georgia Power, and Southern Power, these contracts primarily relate to PPAs whereby electricity and generation capacity are provided to a customer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. For Southern Company Gas, these contracts primarily relate to the U.S. General Services Administration contract described above. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain

fixed price contracts. Revenues from contracts with customers related to these performance obligations remaining at September 30, 2023 are expected to be recognized as follows:

	2023 (remaining)		2024		2025		2026		2027		Thereafter
	(in millions)
Southern Company	$	166	$	599	$	359	$	318	$	319	$	2,245
Alabama Power	10		24		8		—		—		—
Georgia Power	23		66		34		14		14		23
Southern Power	84		356		302		303		310		2,233
Southern Company Gas	4		29		—		—		—		—

Lease Income

Lease income for the three and nine months ended September 30, 2023 and 2022 is as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
For the Three Months Ended September 30, 2023
Lease income - interest income on sales-type leases	$	6	$	—	$	—	$	4	$	2	$	—
Lease income - operating leases	36		3		7		—		21		9
Variable lease income	134		—		—		—		144		—
Total lease income	$	176	$	3	$	7	$	4	$	167	$	9
For the Nine Months Ended September 30, 2023
Lease income - interest income on sales-type leases	$	18	$	—	$	—	$	11	$	7	$	—
Lease income - operating leases	129		32		22		2		64		27
Variable lease income	327		1		—		—		351		—
Total lease income	$	474	$	33	$	22	$	13	$	422	$	27
For the Three Months Ended September 30, 2022
Lease income - interest income on sales-type leases	$	7	$	—	$	—	$	4	$	3	$	—
Lease income - operating leases	50		19		8		1		21		9
Variable lease income	139		—		—		—		145		—
Total lease income	$	196	$	19	$	8	$	5	$	169	$	9
For the Nine Months Ended September 30, 2022
Lease income - interest income on sales-type leases	$	19	$	—	$	—	$	11	$	8	$	—
Lease income - operating leases	149		58		24		1		64		27
Variable lease income	355		1		—		—		372		—
Total lease income	$	523	$	59	$	24	$	12	$	444	$	27

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

9 Months Ended

Sep. 30, 2023

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 Company

At September 30, 2023 and December 31, 2022, Southern Holdings had equity method investments totaling $126 million and $112 million, respectively, primarily related to investments in venture capital funds focused on energy and utility investments. Earnings from these investments were immaterial for all periods presented.

Southern Power

Variable Interest Entities

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

SP Solar and SP Wind

At September 30, 2023 and December 31, 2022, SP Solar had total assets of $5.8 billion and $5.9 billion, respectively, total liabilities of $0.4 billion, and noncontrolling interests of $1.1 billion. Cash distributions from SP Solar are allocated 67% to Southern Power and 33% to the limited partner in accordance with their partnership interest percentage. Under the terms of the limited partnership agreement, distributions without limited partner consent are limited to available cash and SP Solar is obligated to distribute all such available cash to its partners each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves.

At September 30, 2023 and December 31, 2022, SP Wind had total assets of $2.2 billion, total liabilities of $184 million and $169 million, respectively, and noncontrolling interests of $38 million and $39 million, respectively. Under the terms of the limited liability agreement, distributions without Class A member consent are limited to available cash and SP Wind is obligated to distribute all such available cash to its members each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves. Cash distributions from SP Wind are generally allocated 60% to Southern Power and 40% to the three financial investors in accordance with the limited liability agreement.

Southern Power consolidates both SP Solar and SP Wind, as the primary beneficiary, since it controls the most significant activities of each entity, including operating and maintaining their assets. Certain transfers and sales of the assets in the VIEs are subject to partner consent and the liabilities are non-recourse to the general credit of Southern Power. Liabilities consist of customary working capital items and do not include any long-term debt.

Other Variable Interest Entities

Southern Power has other consolidated VIEs that relate to certain subsidiaries that have either sold noncontrolling interests to tax equity investors or acquired less than a 100% interest from facility developers. These entities are considered VIEs because the arrangements are structured similar to a limited partnership and the noncontrolling members do not have substantive kick-out rights.

At September 30, 2023 and December 31, 2022, the other VIEs had total assets of $1.7 billion and $1.8 billion, respectively, total liabilities of $0.2 billion, and noncontrolling interests of $0.8 billion. 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 December 31, 2022, Southern Power had equity method investments in wind and battery energy storage projects totaling $49 million. During the first quarter 2023, Southern Power sold its remaining equity method investments in the projects and received proceeds of $50 million. Earnings (loss) from these investments, including the gains associated with the sales, were immaterial for all periods presented.

Southern Company Gas

Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments at September 30, 2023 and December 31, 2022 and related earnings from those investments for the three and nine months ended September 30, 2023 and 2022 were as follows:

Investment Balance	September 30, 2023		December 31, 2022
	(in millions)
SNG	$	1,210	$	1,243
Other	33		33
Total	$	1,243	$	1,276

	Three Months Ended September 30,				Nine Months Ended September 30,
Earnings from Equity Method Investments	2023		2022		2023		2022
	(in millions)
SNG	$	32	$	34	$	104	$	104
Other	—		—		—		1
Total	$	32	$	34	$	104	$	105

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Financing and Leases

9 Months Ended

Sep. 30, 2023

Debt Disclosure [Abstract]

Financing and Leases

FINANCING AND LEASES

Bank Credit Arrangements

See Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K for additional information.

At September 30, 2023, committed credit arrangements with banks were as follows:

	Expires
Company	2024		2025		2026		2028		Total		Unused		Expires within One Year
	(in millions)
Southern Company parent(a)	$	150	$	—	$	—	$	1,850	$	2,000	$	1,998	$	150
Alabama Power	—		—		650		700		1,350		1,350		—
Georgia Power	—		—		—		1,750		1,750		1,726		—
Mississippi Power	—		125		150		—		275		275		—
Southern Power(a)(b)	—		—		—		600		600		589		—
Southern Company Gas(c)	100		—		—		1,500		1,600		1,598		100
SEGCO	30		—		—		—		30		30		30
Southern Company	$	280	$	125	$	800	$	6,400	$	7,605	$	7,566	$	280

(a)Arrangement expiring in 2028 represents a $2.45 billion combined arrangement for Southern Company and Southern Power as borrowers. Pursuant to the combined facility, the allocations between Southern Company and Southern Power may be adjusted.

(b)Does not include Southern Power Company's $75 million and $100 million continuing letter of credit facilities for standby letters of credit, expiring in 2025 and 2026, respectively, of which $9 million and $16 million, respectively, was unused at September 30, 2023. In March 2023, Southern Power amended the $100 million letter of credit facility, which, among other things, extended the expiration date from 2025 to 2026 and increased the amount from $75 million. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.

(c)Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $800 million of the credit arrangement expiring in 2028. Southern Company Gas' committed credit arrangement expiring in 2028 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 2028, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. Nicor Gas is also the borrower under a $100 million credit arrangement expiring in 2024.

As reflected in the table above, in May 2023, Southern Company and Southern Power combined and extended their multi-year credit arrangements previously maturing in 2026, resulting in a single aggregate $2.45 billion facility (currently allocated $1.85 billion for Southern Company and $600 million for Southern Power) maturing in 2028. Pursuant to the combined facility, the allocations between Southern Company and Southern Power may be adjusted. Alabama Power, Georgia Power, and Southern Company Gas Capital, along with Nicor Gas, amended and restated certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2026 to 2028. Mississippi Power amended and restated certain of its multi-year credit arrangements aggregating $150 million, which, among other things, extended the maturity dates from 2024 to 2026. Nicor Gas also entered into a $100 million credit arrangement maturing in 2024 to replace its $250 million credit arrangement that expired in 2023. In June 2023, Southern Company also entered into a new $150 million credit arrangement maturing in 2024. In August 2023, Alabama Power amended and restated one of its multi-year credit arrangements, which, among other things, extended the maturity date from 2024 to 2026 and increased the borrowing capacity from $550 million to $650 million.

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

These bank credit arrangements, as well as the term loan arrangements of the Registrants, Nicor Gas, and SEGCO, contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. The cross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2023, 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 certain revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. At September 30, 2023, outstanding variable rate demand revenue bonds of the traditional electric operating companies with allocated liquidity support totaled approximately $1.7 billion (comprised of approximately $818 million at Alabama Power, $819 million at Georgia Power, and $69 million at Mississippi Power). In addition, at September 30, 2023, Alabama Power and Georgia Power had approximately $120 million and $325 million, respectively, of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months. The variable rate demand revenue bonds and fixed rate revenue bonds required to be remarketed within the next 12 months are classified as long-term debt on the balance sheets as a result of available long-term committed credit.

Convertible Senior Notes

In February 2023, Southern Company issued $1.5 billion aggregate principal amount of Series 2023A 3.875% Convertible Senior Notes due December 15, 2025 (Series 2023A Convertible Senior Notes). In March 2023, Southern Company issued an additional $225 million aggregate principal amount of the Series 2023A Convertible Senior Notes upon the exercise by the initial purchasers of their over-allotment option.

Interest on the Series 2023A Convertible Senior Notes is payable semiannually, which began on June 15, 2023. The Series 2023A Convertible Senior Notes will mature on December 15, 2025, unless earlier converted or repurchased, but are not redeemable at the option of Southern Company. The Series 2023A Convertible Senior Notes are direct, unsecured, and unsubordinated obligations of Southern Company, ranking equally with all of Southern Company's other unsecured and unsubordinated indebtedness from time to time outstanding, and are effectively subordinated to all secured indebtedness of Southern Company.

Holders may convert their Series 2023A Convertible Senior Notes at their option prior to the close of business on the business day preceding September 15, 2025, but only under the following circumstances:

•during any calendar quarter (and only during such calendar quarter), if the last reported sale price of Southern Company's common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day as determined by Southern Company;

•during the five business day period after any 10 consecutive trading day period (Measurement Period) in which the trading price per $1,000 principal amount of Series 2023A Convertible Senior Notes for each trading day of the Measurement Period was less than 98% of the product of the last reported sale price of the common stock and the conversion rate on each such trading day; or

•upon the occurrence of certain corporate events specified in the indenture governing the Series 2023A Convertible Senior Notes.

On or after September 15, 2025, a holder may convert all or any portion of its Series 2023A Convertible Senior Notes at any time prior to the close of business on the second scheduled trading day immediately preceding the maturity date regardless of the foregoing conditions.

Southern Company will settle conversions of the Series 2023A Convertible Senior Notes by paying cash up to the aggregate principal amount of the Series 2023A Convertible Senior Notes to be converted and paying or delivering, as the case may be, cash, shares of common stock or a combination of cash and shares of common stock, at Southern Company's election, in respect of the remainder, if any, of Southern Company's conversion obligation in excess of the aggregate principal amount of the Series 2023A Convertible Senior Notes being converted. The Series 2023A Convertible Senior Notes are initially convertible at a rate of 11.8818 shares of common stock per $1,000 principal amount converted, which is approximately equal to $84.16 per share of common stock. The conversion rate will be subject to adjustment upon the occurrence of certain specified events but will not be adjusted for accrued and unpaid interest. In addition, upon the occurrence of a make-whole fundamental change (as defined in the indenture governing the Series 2023A Convertible Senior Notes), Southern Company will, in certain circumstances, increase the conversion rate by a number of additional shares of common stock for conversions in connection with the make-whole fundamental change.

Upon the occurrence of a fundamental change (as defined in the indenture governing the Series 2023A Convertible Senior Notes), holders of the Series 2023A Convertible Senior Notes may require Southern Company to purchase all or a portion of their Series 2023A Convertible Senior Notes, in principal amounts equal to $1,000 or an integral multiple thereof, for cash at a price equal to 100% of the principal amount of the Series 2023A Convertible Senior Notes to be purchased plus any accrued and unpaid interest.

Earnings per Share

For Southern Company, the only difference in computing basic and diluted earnings per share (EPS) is attributable to awards outstanding under stock-based compensation plans and the Series 2023A Convertible Senior Notes. EPS dilution resulting from stock-based compensation plans is determined using the treasury stock method and EPS dilution resulting from the Series 2023A Convertible Senior Notes is determined using the net share settlement method. See Note 12 to the financial statements in Item 8 of the Form 10-K and "Convertible Senior Notes" herein for additional information. Shares used to compute diluted EPS were as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2023	2022	2023	2022
	(in millions)
As reported shares	1,092	1,082	1,092	1,070
Effect of stock-based compensation	7	6	6	6
Diluted shares	1,099	1,088	1,098	1,076

For all periods presented, an immaterial number of stock-based compensation awards was excluded from the diluted EPS calculation because the awards were anti-dilutive.

For all periods presented, there was no dilution resulting from the Series 2023A Convertible Senior Notes.

Southern Company Leveraged Lease

See Note 9 to the financial statements in Item 8 of the Form 10-K for information on a leveraged lease agreement related to energy generation. In June 2022, the Southern Holdings subsidiary operating the generating plant for the lessee provided notice to the lessee to terminate the related operating and maintenance agreement effective June 30, 2023. Subsequently, the lessee failed to make the semi-annual lease payment due in December 2022. As a result, the Southern Holdings subsidiary was unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. The parties to the lease entered into forbearance agreements which suspended the related contractual rights of the parties while they continued restructuring negotiations, during which

the termination date for the operating and maintenance agreement was delayed until July 31, 2023. The negotiations were completed on July 14, 2023, resulting in the Southern Holdings subsidiary agreeing to continue operating the plant for the lessee until the lessee's associated power off-take agreement ends in 2032, subject to certain terms and conditions. The restructuring had no material impact on Southern Company's financial statements. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to meet its obligations, including those associated with a future closure or retirement of the generation assets and associated properties, including the dry ash landfill.

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Income Taxes

9 Months Ended

Sep. 30, 2023

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 $1.0 billion and $1.1 billion at September 30, 2023 and December 31, 2022, respectively.

Southern Company's federal PTC and ITC carryforwards begin expiring in 2031, but are expected to be fully utilized by 2028. 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, changes in taxable income projections, transfer of eligible credits, and potential income tax rate changes. In the third quarter 2023, Georgia Power started generating advanced nuclear PTCs for Plant Vogtle Unit 3 beginning on the in-service date of July 31, 2023. In addition, pursuant to the Global Amendments to the Vogtle Joint Ownership Agreements (as defined in Note (B) under "Georgia Power – Nuclear Construction – Joint Owner Contracts"), Georgia Power is purchasing advanced nuclear PTCs for Plant Vogtle Unit 3 from certain other Vogtle Owners. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.

Effective Tax Rate

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

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

Southern Company

Southern Company's effective tax rate was 13.9% for the nine months ended September 30, 2023 compared to 20.0% for the corresponding period in 2022. The effective tax rate decrease was primarily due to an increase in the flowback of certain excess deferred income taxes at Alabama Power in 2023, lower pre-tax earnings in 2023, and an adjustment related to state tax credit carryforwards and the related valuation allowance at Georgia Power in 2022 and 2023, partially offset by the flowback of certain excess deferred income taxes ending in 2022 at Georgia Power.

Alabama Power

Alabama Power's effective tax rate was 8.3% for the nine months ended September 30, 2023 compared to 23.7% for the corresponding period in 2022. The effective tax rate decrease was primarily due to an increase in the flowback of certain excess deferred income taxes in 2023. See Note 2 to the financial statements under "Alabama Power – Excess Accumulated Deferred Income Tax Accounting Order" in Item 8 of the Form 10-K for additional information.

Georgia Power

Georgia Power's effective tax rate was 18.2% for the nine months ended September 30, 2023 compared to 18.5% for the corresponding period in 2022. The effective tax rate decrease was primarily due to an adjustment related to state tax credit carryforwards in 2022, a decrease in a valuation allowance on certain state tax credit carryforwards in 2023, and lower pre-tax earnings in 2023, largely offset by the flowback of certain excess deferred income taxes ending in 2022.

Mississippi Power

Mississippi Power's effective tax rate was 16.9% for the nine months ended September 30, 2023 compared to 20.1% for the corresponding period in 2022. The effective tax rate decrease was primarily due to an increase in the flowback of certain excess deferred income taxes in 2023.

Southern Power

Southern Power's effective tax rate was 14.8% for the nine months ended September 30, 2023 compared to 18.8% for the corresponding period in 2022. The effective tax rate decrease was primarily due to changes in state apportionment methodology resulting from tax legislation enacted by the State of Tennessee in May 2023.

Unrecognized Tax Benefits

Southern Company's and Georgia Power's unrecognized tax positions balances at September 30, 2023 were $167 million and $86 million, respectively, compared to $80 million for Southern Company at December 31, 2022. The increases from prior periods are primarily related to the amendment of certain 2019 through 2021 state tax filing positions related to tax credit utilization. If effective settlement of the positions is favorable, these positions would decrease Southern Company's and Georgia Power's effective tax rates. The ultimate outcome of this unrecognized tax benefit, of which a portion is expected to be resolved within the next 12 months, is dependent on acceptance by the state or expiration of related statute of limitations.

Subsequent to September 30, 2023, a statute of limitations expired related to a 2019 state tax filing position to exclude certain gains from 2019 dispositions from taxation in a certain unitary state. This $44 million tax position and related interest will be recognized in the fourth quarter 2023 and will decrease Southern Company's annual effective tax rate.

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Retirement Benefits

9 Months Ended

Sep. 30, 2023

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, 2023. The Southern Company system also provides certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis. In addition, the Southern Company system provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund other postretirement trusts to the extent required by their respective regulatory commissions. Southern Company Gas has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.

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

On each Registrant's condensed statements of income, the service cost component of net periodic benefit costs is included in other operations and maintenance expenses and all other components of net periodic benefit costs are included in other income (expense), net. Components of the net periodic benefit costs for the three and nine months ended September 30, 2023 and 2022 are presented in the following tables.

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2023
Pension Plans
Service cost	$	69	$	16	$	17	$	2	$	2	$	6
Interest cost	156		37		48		7		2		11
Expected return on plan assets	(307)		(75)		(97)		(13)		(4)		(22)
Amortization:
Prior service costs	—		—		—		—		—		(1)
Regulatory asset	—		—		—		—		—		4
Net (gain) loss	8		2		4		1		—		(1)
Net periodic pension income	$	(74)	$	(20)	$	(28)	$	(3)	$	—	$	(3)
Postretirement Benefits
Service cost	$	4	$	1	$	1	$	—	$	—	$	—
Interest cost	18		5		6		1		—		2
Expected return on plan assets	(21)		(9)		(7)		(1)		—		(2)
Amortization:
Prior service costs	—		—		1		—		—		—
Regulatory asset	—		—		—		—		—		2
Net gain	(4)		(1)		(1)		—		—		(1)
Net periodic postretirement benefit cost (income)	$	(3)	$	(4)	$	—	$	—	$	—	$	1
Nine Months Ended September 30, 2023
Pension Plans
Service cost	$	207	$	48	$	51	$	8	$	5	$	18
Interest cost	469		109		143		21		6		32
Expected return on plan assets	(922)		(223)		(289)		(41)		(12)		(65)
Amortization:
Prior service costs	—		—		1		—		—		(2)
Regulatory asset	—		—		—		—		—		11
Net (gain) loss	24		7		10		1		—		(3)
Net periodic pension income	$	(222)	$	(59)	$	(84)	$	(11)	$	(1)	$	(9)
Postretirement Benefits
Service cost	$	11	$	3	$	3	$	—	$	—	$	1
Interest cost	53		13		19		2		—		6
Expected return on plan assets	(62)		(26)		(22)		(1)		—		(5)
Amortization:
Prior service costs	1		—		1		—		—		—
Regulatory asset	—		—		—		—		—		5
Net gain	(10)		(2)		(3)		—		—		(3)
Net periodic postretirement benefit cost (income)	$	(7)	$	(12)	$	(2)	$	1	$	—	$	4

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2022
Pension Plans
Service cost	$	103	$	25	$	26	$	5	$	2	$	9
Interest cost	102		24		31		5		2		7
Expected return on plan assets	(316)		(77)		(99)		(15)		(4)		(22)
Amortization:
Prior service costs	—		—		—		—		—		(1)
Regulatory asset	—		—		—		—		—		3
Net loss	60		16		18		2		1		2
Net periodic pension cost (income)	$	(51)	$	(12)	$	(24)	$	(3)	$	1	$	(2)
Postretirement Benefits
Service cost	$	6	$	2	$	2	$	1	$	1	$	—
Interest cost	10		3		4		—		—		1
Expected return on plan assets	(20)		(9)		(8)		—		—		(2)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		2
Net (gain)/loss	1		—		—		—		—		(1)
Net periodic postretirement benefit cost (income)	$	(4)	$	(4)	$	(2)	$	1	$	1	$	—
Nine Months Ended September 30, 2022
Pension Plans
Service cost	$	309	$	74	$	78	$	13	$	7	$	26
Interest cost	306		72		92		14		5		21
Expected return on plan assets	(949)		(229)		(298)		(44)		(12)		(68)
Amortization:
Prior service costs	—		—		1		—		—		(2)
Regulatory asset	—		—		—		—		—		11
Net loss	180		47		55		9		2		5
Net periodic pension cost (income)	$	(154)	$	(36)	$	(72)	$	(8)	$	2	$	(7)
Postretirement Benefits
Service cost	$	17	$	5	$	5	$	1	$	1	$	1
Interest cost	31		8		11		1		—		4
Expected return on plan assets	(60)		(25)		(21)		(1)		—		(6)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		5
Net (gain) loss	1		—		1		—		—		(2)
Net periodic postretirement benefit cost (income)	$	(12)	$	(12)	$	(4)	$	1	$	1	$	2

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Fair Value Measurements

9 Months Ended

Sep. 30, 2023

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

At September 30, 2023, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

	Fair Value Measurements Using:
At September 30, 2023	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)	$	7	$	73	$	—	$	—	$	80
Investments in trusts:(b)
Domestic equity	692		196		—		—		888
Foreign equity	131		154		—		—		285
U.S. Treasury and government agency securities	—		337		—		—		337
Municipal bonds	—		42		—		—		42
Pooled funds – fixed income	—		6		—		—		6
Corporate bonds	—		368		—		—		368
Mortgage and asset backed securities	—		85		—		—		85
Private equity	—		—		—		169		169
Cash and cash equivalents	3		—		—		—		3
Other	33		3		—		8		44
Cash equivalents and restricted cash	919		11		—		—		930
Other investments	9		34		8		—		51
Total	$	1,794	$	1,309	$	8	$	177	$	3,288
Liabilities:
Energy-related derivatives(a)	$	34	$	217	$	—	$	—	$	251
Interest rate derivatives	—		351		—		—		351
Foreign currency derivatives	—		192		—		—		192
Contingent consideration	5		—		19		—		24
Other	—		13		—		—		13
Total	$	39	$	773	$	19	$	—	$	831

	Fair Value Measurements Using:
At September 30, 2023	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	$	—	$	26	$	—	$	—	$	26
Nuclear decommissioning trusts:(b)
Domestic equity	404		188		—		—		592
Foreign equity	131		—		—		—		131
U.S. Treasury and government agency securities	—		20		—		—		20
Municipal bonds	—		1		—		—		1
Corporate bonds	—		215		—		—		215
Mortgage and asset backed securities	—		22		—		—		22
Private equity	—		—		—		169		169
Other	10		—		—		8		18
Cash equivalents and restricted cash	489		11		—		—		500
Other investments	—		34		—		—		34
Total	$	1,034	$	517	$	—	$	177	$	1,728
Liabilities:
Energy-related derivatives	$	—	$	75	$	—	$	—	$	75
Georgia Power
Assets:
Energy-related derivatives	$	—	$	14	$	—	$	—	$	14
Nuclear decommissioning trusts:(b)
Domestic equity	288		1		—		—		289
Foreign equity	—		153		—		—		153
U.S. Treasury and government agency securities	—		317		—		—		317
Municipal bonds	—		41		—		—		41
Corporate bonds	—		153		—		—		153
Mortgage and asset backed securities	—		63		—		—		63
Other	23		3		—		—		26
Total	$	311	$	745	$	—	$	—	$	1,056
Liabilities:
Energy-related derivatives	$	—	$	83	$	—	$	—	$	83

	Fair Value Measurements Using:
At September 30, 2023	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	$	—	$	24	$	—	$	—	$	24
Cash equivalents	3		—		—		—		3
Total	$	3	$	24	$	—	$	—	$	27
Liabilities:
Energy-related derivatives	$	—	$	44	$	—	$	—	$	44
Southern Power
Assets:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5
Cash equivalents	23		—		—		—		23
Total	$	23	$	5	$	—	$	—	$	28
Liabilities:
Energy-related derivatives	$	—	$	6	$	—	$	—	$	6
Foreign currency derivatives	—		42		—		—		42
Contingent consideration	5		—		19		—		24
Other	—		13		—		—		13
Total	$	5	$	61	$	19	$	—	$	85
Southern Company Gas
Assets:
Energy-related derivatives(a)	$	7	$	4	$	—	$	—	$	11
Non-qualified deferred compensation trusts:
Domestic equity	—		7		—		—		7
Foreign equity	—		1		—		—		1
Pooled funds – fixed income	—		6		—		—		6
Cash equivalents	3		—		—		—		3
Cash equivalents	294		—		—		—		294
Total	$	304	$	18	$	—	$	—	$	322
Liabilities:
Energy-related derivatives(a)	$	34	$	9	$	—	$	—	$	43
Interest rate derivatives	—		99		—		—		99
Total	$	34	$	108	$	—	$	—	$	142

(a)Excludes cash collateral of $49 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.

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds, including reinvested interest and dividends and excluding the funds' expenses, increased (decreased) by the amounts shown in the table below for the three and nine months ended September 30, 2023 and 2022. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.

	Three Months Ended				Nine Months Ended
Fair value increases (decreases)	September 30, 2023		September 30, 2022		September 30, 2023		September 30, 2022
	(in millions)
Southern Company	$	(4)	$	(106)	$	211	$	(486)
Alabama Power	(36)		(53)		54		(245)
Georgia Power	32		(53)		157		(241)

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 two of its acquisitions whereby it is primarily obligated to make generation-based payments to the seller, commencing at the commercial operation of each facility and continuing through 2026 and 2035, respectively. The obligations are primarily categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility's generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.

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

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

At September 30, 2023, the fair value measurements of private market 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 $177 million and unfunded commitments related to the private market investments totaled $72 million. Private market investments include high-quality private equity funds across several market sectors, funds that invest in real estate assets, and a private credit fund. Private market funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.

At September 30, 2023, 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	$	58.8	$	11.2	$	15.8	$	1.6	$	2.7	$	8.1
Fair value	50.8		9.4		13.4		1.3		2.4		6.5

(*)The carrying amount of Southern Company Gas' long-term debt includes fair value adjustments from 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.

XML

Derivatives

9 Months Ended

Sep. 30, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

DERIVATIVESThe Registrants are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. 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.

Energy-Related Derivatives

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

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

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

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

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

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

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

At September 30, 2023, 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(*)	422	2030	2028
Alabama Power	109	2026	—
Georgia Power	104	2026	—
Mississippi Power	80	2027	—
Southern Power	8	2030	2024
Southern Company Gas(*)	121	2027	2028

(*)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 135.5 million mmBtu long natural gas positions and 14.2 million mmBtu short natural gas positions at September 30, 2023, which is also included in Southern Company's total volume.

In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 14 million mmBtu for Southern Company, which includes 4 million mmBtu for Alabama Power, 5 million mmBtu for Georgia Power, 2 million mmBtu for Mississippi Power, and 3 million mmBtu for Southern Power.

For cash flow hedges of energy-related derivatives, the estimated pre-tax losses expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2024 are $30 million for Southern Company, $25 million for Southern Company Gas, and immaterial for Southern Power.

Interest Rate Derivatives

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

At September 30, 2023, the following interest rate derivatives were outstanding:

	Notional Amount		Weighted Average Interest Rate Paid	Interest Rate Received	Hedge Maturity Date	Fair Value Gain (Loss) at September 30, 2023
	(in millions)					(in millions)
Fair Value Hedges of Existing Debt
Southern Company parent	$	400	1-month SOFR + 0.80%	1.75%	March 2028	$	(56)
Southern Company parent	1,000		1-month SOFR + 2.48%	3.70%	April 2030	(196)
Southern Company Gas	500		1-month SOFR + 0.49%	1.75%	January 2031	(99)
Southern Company	$	1,900				$	(351)

For cash flow hedges of interest rate derivatives, the estimated pre-tax losses expected to be reclassified from accumulated OCI to interest expense for the 12-month period ending September 30, 2024 are $19 million for Southern Company and immaterial for the traditional electric operating companies and Southern Company Gas. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2052 for Southern Company, Alabama Power, and Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.

Foreign Currency Derivatives

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

At September 30, 2023, the following foreign currency derivatives were outstanding:

	Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at September 30, 2023
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	564	3.78%	€	500	1.85%	June 2026	$	(42)
Fair Value Hedges of Existing Debt
Southern Company parent	1,476		3.39%	1,250		1.88%	September 2027	(150)
Southern Company	$	2,040		€	1,750			$	(192)

For cash flow hedges of foreign currency derivatives, the estimated pre-tax losses expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2024 are $10 million for Southern Power.

Derivative Financial Statement Presentation and Amounts

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

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

	At September 30, 2023				At December 31, 2022
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Southern Company
Energy-related derivatives designated as hedging instruments for regulatory purposes
Assets from risk management activities/Liabilities from risk management activities	$	34	$	134	$	123	$	121
Other deferred charges and assets/Other deferred credits and liabilities	36		77		52		44
Total derivatives designated as hedging instruments for regulatory purposes	70		211		175		165
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities	—		28		3		27
Other deferred charges and assets/Other deferred credits and liabilities	4		2		6		4
Interest rate derivatives:
Assets from risk management activities/Liabilities from risk management activities	—		80		12		62
Other deferred charges and assets/Other deferred credits and liabilities	—		271		—		240
Foreign currency derivatives:
Assets from risk management activities/Liabilities from risk management activities	—		35		—		34
Other deferred charges and assets/Other deferred credits and liabilities	—		157		—		182
Total derivatives designated as hedging instruments in cash flow and fair value hedges	4		573		21		549
Energy-related derivatives not designated as hedging instruments
Assets from risk management activities/Liabilities from risk management activities	5		8		13		13
Other deferred charges and assets/Other deferred credits and liabilities	1		2		2		1
Total derivatives not designated as hedging instruments	6		10		15		14
Gross amounts recognized	80		794		211		728
Gross amounts offset(a)	(37)		(86)		(70)		(111)
Net amounts recognized in the Balance Sheets(b)	$	43	$	708	$	141	$	617

	At September 30, 2023				At December 31, 2022
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Alabama Power(c)
Energy-related derivatives designated as hedging instruments for regulatory purposes
Other current assets/Other current liabilities	$	15	$	46	$	42	$	21
Other deferred charges and assets/Other deferred credits and liabilities	11		29		20		18
Total derivatives designated as hedging instruments for regulatory purposes	26		75		62		39
Gross amounts offset	(17)		(17)		(24)		(24)
Net amounts recognized in the Balance Sheets	$	9	$	58	$	38	$	15
Georgia Power
Energy-related derivatives designated as hedging instruments for regulatory purposes
Other current assets/Other current liabilities	$	4	$	57	$	36	$	43
Other deferred charges and assets/Other deferred credits and liabilities	10		26		6		18
Total derivatives designated as hedging instruments for regulatory purposes	14		83		42		61
Energy-related derivatives not designated as hedging instruments
Other current assets/Other current liabilities	—		—		—		1
Gross amounts recognized	14		83		42		62
Gross amounts offset	(11)		(11)		(21)		(21)
Net amounts recognized in the Balance Sheets	$	3	$	72	$	21	$	41
Mississippi Power(c)
Energy-related derivatives designated as hedging instruments for regulatory purposes
Other current assets/Other current liabilities	$	9	$	22	$	33	$	24
Other deferred charges and assets/Other deferred credits and liabilities	15		22		26		8
Total derivatives designated as hedging instruments for regulatory purposes	24		44		59		32
Gross amounts offset	(17)		(17)		(17)		(17)
Net amounts recognized in the Balance Sheets	$	7	$	27	$	42	$	15

	At September 30, 2023				At December 31, 2022
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	$	—	$	5	$	—	$	12
Other deferred charges and assets/Other deferred credits and liabilities	4		—		5		—
Foreign currency derivatives:
Other current assets/Other current liabilities	—		11		—		11
Other deferred charges and assets/Other deferred credits and liabilities	—		31		—		36
Total derivatives designated as hedging instruments in cash flow and fair value hedges	4		47		5		59
Energy-related derivatives not designated as hedging instruments
Other current assets/Other current liabilities	1		1		2		—
Other deferred charges and assets/Other deferred credits and liabilities	—		—		1		—
Total derivatives not designated as hedging instruments	1		1		3		—
Gross amounts recognized	5		48		8		59
Gross amounts offset	(1)		(1)		—		—
Net amounts recognized in the Balance Sheets	$	4	$	47	$	8	$	59
Southern Company Gas
Energy-related derivatives designated as hedging instruments for regulatory purposes
Other current assets/Other current liabilities	$	6	$	9	$	12	$	33
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	—		23		3		15
Other deferred charges and assets/Other deferred credits and liabilities	—		2		1		4
Interest rate derivatives:
Other current assets/Other current liabilities	—		21		—		14
Other deferred charges and assets/Other deferred credits and liabilities	—		78		—		72
Total derivatives designated as hedging instruments in cash flow and fair value hedges	—		124		4		105
Energy-related derivatives not designated as hedging instruments
Other current assets/Other current liabilities	4		7		11		12
Other deferred charges and assets/Other deferred credits and liabilities	1		2		1		1
Total derivatives not designated as hedging instruments	5		9		12		13
Gross amounts recognized	11		142		28		151
Gross amounts offset(a)	9		(40)		—		(41)
Net amounts recognized in the Balance Sheets(b)	$	20	$	102	$	28	$	110

(a)Gross amounts offset includes cash collateral held on deposit in broker margin accounts of $49 million and $41 million at September 30, 2023 and December 31, 2022, respectively.

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

(c)Energy-related derivatives not designated as hedging instruments were immaterial for Alabama Power and Mississippi Power at December 31, 2022. There were no such instruments for Alabama Power and Mississippi Power at September 30, 2023.

At September 30, 2023 and December 31, 2022, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Company Gas
	(in millions)
At September 30, 2023:
Energy-related derivatives:
Other regulatory assets, current	$	(113)	$	(39)	$	(54)	$	(16)	$	(4)
Other regulatory assets, deferred	(48)		(19)		(18)		(11)		—
Other regulatory liabilities, current	23		8		1		4		10
Other regulatory liabilities, deferred	6		1		2		3		—
Total energy-related derivative gains (losses)	$	(132)	$	(49)	$	(69)	$	(20)	$	6
At December 31, 2022:
Energy-related derivatives:
Other regulatory assets, current	$	(71)	$	(8)	$	(26)	$	(13)	$	(24)
Other regulatory assets, deferred	(23)		(7)		(14)		(2)		—
Other regulatory liabilities, current	72		29		19		22		2
Other regulatory liabilities, deferred	31		9		2		20		—
Total energy-related derivative gains (losses)	$	9	$	23	$	(19)	$	27	$	(22)

For the three and nine months ended September 30, 2023 and 2022, the pre-tax effects of cash flow and fair value hedge accounting on accumulated OCI for the applicable Registrants were as follows:

Gain (Loss) Recognized in OCI on Derivatives	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Southern Company
Cash flow hedges:
Energy-related derivatives	$	(4)	$	11	$	(55)	$	51
Interest rate derivatives	(3)		6		(12)		36
Foreign currency derivatives	(15)		(35)		(6)		(137)
Fair value hedges(*):
Foreign currency derivatives	27		20		28		18
Total	$	5	$	2	$	(45)	$	(32)
Georgia Power
Cash flow hedges:
Interest rate derivatives	$	—	$	—	$	(3)	$	31
Southern Power
Cash flow hedges:
Energy-related derivatives	$	—	$	(11)	$	(14)	$	(4)
Foreign currency derivatives	(15)		(35)		(6)		(137)
Total	$	(15)	$	(46)	$	(20)	$	(141)
Southern Company Gas
Cash flow hedges:
Energy-related derivatives	$	(4)	$	22	$	(41)	$	55
Interest rate derivatives	(4)		5		—		—
Total	$	(8)	$	27	$	(41)	$	55

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

For the three and nine months ended September 30, 2022, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for Alabama Power and there were no such effects in 2023.

For the three and nine months ended September 30, 2023 and 2022, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows:

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Southern Company
Total cost of natural gas	$	102	$	294	$	1,199	$	1,840
Gain (loss) on energy-related cash flow hedges(a)	(4)		9		(32)		28
Total other operations and maintenance	1,424		1,527		4,352		4,568
Gain (loss) on energy-related cash flow hedges(a)	(1)		—		(2)		—
Total depreciation and amortization	1,143		922		3,365		2,728
Gain (loss) on energy-related cash flow hedges(a)	(5)		(1)		(18)		5
Total interest expense, net of amounts capitalized	(620)		(511)		(1,812)		(1,461)
Gain (loss) on interest rate cash flow hedges(a)	(22)		(7)		(31)		(19)
Gain (loss) on foreign currency cash flow hedges(a)	(3)		(3)		(8)		(16)
Gain (loss) on interest rate fair value hedges(b)	(47)		(102)		(50)		(300)
Total other income (expense), net	141		132		428		414
Gain (loss) on foreign currency cash flow hedges(a)(c)	(14)		(32)		(4)		(129)
Gain (loss) on foreign currency fair value hedges	(7)		(59)		19		(180)
Amount excluded from effectiveness testing recognized in earnings	(27)		(21)		(28)		(17)
Southern Power
Total depreciation and amortization	$	130	$	133	$	380	$	384
Gain (loss) on energy-related cash flow hedges(a)	(5)		(1)		(18)		5
Total interest expense, net of amounts capitalized	(32)		(32)		(98)		(105)
Gain (loss) on foreign currency cash flow hedges(a)	(3)		(3)		(8)		(16)
Total other income (expense), net	4		3		8		5
Gain (loss) on foreign currency cash flow hedges(a)(c)	(14)		(32)		(4)		(129)
Southern Company Gas
Total cost of natural gas	$	102	$	294	$	1,199	$	1,840
Gain (loss) on energy-related cash flow hedges(a)	(4)		9		(32)		28
Total other operations and maintenance	264		252		879		824
Gain (loss) on energy-related cash flow hedges(a)	(1)		—		(2)		—
Total interest expense, net of amounts capitalized	(77)		(65)		(226)		(187)
Gain (loss) on interest rate cash flow hedges(a)	(18)		(2)		(18)		(3)
Gain (loss) on interest rate fair value hedges(b)	(11)		(30)		(14)		(87)

(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.

The pre-tax effects of cash flow and fair value hedge accounting on income for interest rate derivatives were immaterial for the traditional electric operating companies for all periods presented.

At September 30, 2023 and December 31, 2022, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:

	Carrying Amount of the Hedged Item				Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items	At September 30, 2023		At December 31, 2022		At September 30, 2023		At December 31, 2022
	(in millions)				(in millions)
Southern Company
Long-term debt	$	(2,873)	$	(2,927)	$	328	$	282
Southern Company Gas
Long-term debt	$	(402)	$	(415)	$	95	$	81

For the three and nine months ended September 30, 2023 and 2022, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows:

		Gain (Loss)
		Three Months Ended September 30,				Nine Months Ended September 30,
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2023		2022		2023		2022
		(in millions)				(in millions)
Energy-related derivatives:	Natural gas revenues(*)	$	—	$	3	$	—	$	(10)
	Cost of natural gas	7		(2)		36		(7)
Total derivatives in non-designated hedging relationships		$	7	$	1	$	36	$	(17)

(*)Excludes $14 million of gains for the nine months ended September 30, 2023, and immaterial amounts for all other periods presented, recorded in natural gas revenues associated with weather derivatives.

For the three and nine months ended September 30, 2023 and 2022, the pre-tax effects of energy-related derivatives not designated as hedging instruments were immaterial for the other Registrants.

Contingent Features

The Registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. At September 30, 2023, the Registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

For Southern Company, the fair value of foreign currency derivative liabilities and interest rate derivative liabilities with contingent features, and the maximum potential collateral requirements arising from the credit-risk-related contingent features at a rating below BBB- and/or Baa3, was $78 million at September 30, 2023. For Southern Power, the fair value of foreign currency derivative liabilities with contingent features, and the maximum potential collateral requirements arising from the credit-risk-related contingent features at a rating below BBB- and/or Baa3, was $20 million at September 30, 2023. For the traditional electric operating companies and Southern Power, energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial at September 30, 2023. 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.

Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions and they may be required to post collateral based on the value of the positions in these accounts and the associated margin requirements. At September 30, 2023, cash collateral posted in these accounts was $18 million for Southern Power and immaterial for Alabama Power. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At September 30, 2023, cash collateral held on deposit in broker margin accounts was $49 million.

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

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

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

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

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Acquisitions and Dispositions

9 Months Ended

Sep. 30, 2023

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 Acquisitions

Southern Power's asset acquisitions during the nine months ended September 30, 2023 are detailed in the following table:

Project Facility	Resource	Seller	Approximate Nameplate Capacity (MW)	Location	Southern Power Ownership Percentage	Expected COD	PPA Contract Period
Millers Branch(*)	Solar	EDF Renewables, Inc.	200	Haskell County, TX	100%	Fourth quarter 2025	20 years
South Cheyenne	Solar	Hanwha Q Cells USA Corp.	150	Laramie County, WY	100%	First quarter 2024	20 years

(*)The project includes an option to expand capacity up to an additional 300 MWs.

The aggregate purchase price for the two projects was $193 million, which is primarily recorded within construction work in progress on the balance sheet.

Southern Company Gas

On September 22, 2023, Southern Company Gas completed the sale of its California natural gas storage facility, resulting in an immaterial loss.

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Segment and Related Information

9 Months Ended

Sep. 30, 2023

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 are vertically integrated utilities providing electric service in three Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy and battery energy storage projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through its natural gas distribution utilities and is involved in several other complementary businesses including gas pipeline investments and gas marketing services.

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 $156 million and $406 million for the three and nine months ended September 30, 2023, respectively, and $336 million and $673 million for the three and nine months ended September 30, 2022, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies and Southern Power were immaterial for all periods presented. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing distributed energy and resilience solutions and deploying microgrids for commercial, industrial, governmental, and utility customers, as well as investments in telecommunications. All other inter-segment revenues are not material.

Financial data for business segments and products and services for the three and nine months ended September 30, 2023 and 2022 was as follows:

	Electric Utilities
	Traditional Electric Operating Companies		Southern Power		Eliminations		Total		Southern Company Gas		All Other		Eliminations		Consolidated
	(in millions)
Three Months Ended September 30, 2023
Operating revenues	$	5,674	$	653	$	(160)	$	6,167	$	689	$	154	$	(30)	$	6,980
Segment net income (loss)(a)(b)(c)	1,419		100		—		1,519		82		(179)		—		1,422
Nine Months Ended September 30, 2023
Operating revenues	$	14,145	$	1,686	$	(417)	$	15,414	$	3,417	$	499	$	(122)	$	19,208
Segment net income (loss)(a)(b)(c)(d)	2,852		288		—		3,140		475		(490)		(4)		3,121
At September 30, 2023
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	144	$	—	$	5,161
Total assets	99,464		13,090		(568)		111,986		24,823		2,370		(858)		138,321
Three Months Ended September 30, 2022
Operating revenues	$	6,938	$	1,180	$	(691)	$	7,427	$	857	$	135	$	(41)	$	8,378
Segment net income (loss)(a)(b)	1,445		95		—		1,540		83		(152)		1		1,472
Nine Months Ended September 30, 2022
Operating revenues	$	16,716	$	2,618	$	(1,391)	$	17,943	$	3,998	$	418	$	(127)	$	22,232
Segment net income (loss)(a)(b)	3,256		265		—		3,521		516		(415)		(11)		3,611
At December 31, 2022
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	144	$	—	$	5,161
Total assets	95,861		13,081		(659)		108,283		24,621		2,665		(678)		134,891

(a)Attributable to Southern Company.

(b)For the traditional electric operating companies, includes pre-tax charges (credits) to income at Georgia Power for the estimated probable loss associated with the construction of Plant Vogtle Units 3 and 4 of $160 million ($120 million after tax) for the three and nine months ended September 30, 2023 and $(70) million ($(52) million after tax) and $(18) million ($(13) million after tax) for the three and nine months ended September 30, 2022, respectively. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.

(c)For Southern Power, includes an $18 million pre-tax loss recovery ($9 million after tax and partnership allocations) for the three and nine months ended September 30, 2023 related to an arbitration interim award and a $16 million pre-tax gain ($12 million after tax) on the sale of spare parts for the nine months ended September 30, 2023. See Note (C) under "General Litigation Matters – Southern Power" for additional information.

(d)For Southern Company Gas, includes a pre-tax charge of approximately $38 million ($28 million after tax) associated with the disallowance of certain capital expenditures at Nicor Gas. See Note (B) under "Southern Company Gas" for additional information.

Products and Services

	Electric Utilities' Revenues
	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2023	$	5,139	$	727	$	301	$	6,167
Three Months Ended September 30, 2022	5,961		1,197		269		7,427
Nine Months Ended September 30, 2023	$	12,597	$	1,930	$	887	$	15,414
Nine Months Ended September 30, 2022	14,363		2,798		782		17,943

	Southern Company Gas' Revenues
	Gas Distribution Operations		Gas Marketing Services		Other		Total
	(in millions)
Three Months Ended September 30, 2023	$	617	$	56	$	16	$	689
Three Months Ended September 30, 2022	748		85		24		857
Nine Months Ended September 30, 2023	$	2,989	$	376	$	52	$	3,417
Nine Months Ended September 30, 2022	3,513		420		65		3,998

Southern Company Gas

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

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

Gas pipeline investments consists of joint ventures in natural gas pipeline investments including a 50% interest in SNG 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. See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.

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 a natural gas storage facility in Texas through its sale in November 2022 and a natural gas storage facility in California through its sale in September 2023. See Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) under "Southern Company Gas" for additional information.

Business segment financial data for the three months ended September 30, 2023 and 2022 was as follows:

	Gas Distribution Operations		Gas Pipeline Investments		Gas Marketing Services		Total		All Other		Eliminations		Consolidated
	(in millions)
Three Months Ended September 30, 2023
Operating revenues	$	619	$	8	$	56	$	683	$	8	$	(2)	$	689
Segment net income (loss)	70		24		2		96		(14)		—		82
Nine Months Ended September 30, 2023
Operating revenues	$	3,002	$	24	$	376	$	3,402	$	30	$	(15)	$	3,417
Segment net income(*)	352		73		59		484		(9)		—		475
Total assets at September 30, 2023	22,625		1,542		1,519		25,686		9,795		(10,658)		24,823
Three Months Ended September 30, 2022
Operating revenues	$	751	$	8	$	85	$	844	$	16	$	(3)	$	857
Segment net income (loss)	59		24		(2)		81		2		—		83
Nine Months Ended September 30, 2022
Operating revenues	$	3,533	$	24	$	420	$	3,977	$	43	$	(22)	$	3,998
Segment net income	365		76		65		506		10		—		516
Total assets at December 31, 2022	22,040		1,577		1,616		25,233		8,943		(9,555)		24,621

(*)For gas distribution operations, includes a pre-tax charge of approximately $38 million ($28 million after tax) associated with the disallowance of certain capital expenditures at Nicor Gas. See Note (B) under "Southern Company Gas" for additional information.

XML

Insider Trading Arrangements	3 Months Ended
	Sep. 30, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

XML

Introduction (Policies)

9 Months Ended

Sep. 30, 2023

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, 2022 have been derived from the audited financial statements of each Registrant. In the opinion of each Registrant's management, the information regarding such Registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2023 and 2022. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each Registrant believes that the disclosures regarding such Registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy and other factors, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

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.

Recently Adopted Accounting Standards

Recently Adopted Accounting Standards

In March 2020 and December 2022, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting and ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, respectively, providing temporary guidance to ease the potential burden in accounting for reference rate reform primarily resulting from the discontinuation of LIBOR through December 31, 2024. See Note 1 to the financial statements under "Recently Adopted Accounting Standards" in Item 8 of the Form 10-K for additional information on the temporary guidance.

Certain provisions in PPAs at Southern Power include references to LIBOR. Contract amendments have been executed to change to a SOFR-based interest rate. Southern Power adopted and applied the practical expedients guidance to these PPAs. Additionally, the Registrants referenced LIBOR for certain debt and hedging arrangements. As of July 1, 2023, all of the debt and hedging arrangements of the Registrants have transitioned to a SOFR-based interest rate based on the terms of the agreements. There were no material impacts from the transition to SOFR and no impacts to any existing accounting conclusions. See Note (J) under "Interest Rate Derivatives" for additional information.

Goodwill

Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if goodwill impairment indicators arise.

Natural Gas for Sale

Natural Gas for Sale

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

Income Taxes

Income TaxesIn the third quarter 2023, Georgia Power started generating advanced nuclear PTCs for Plant Vogtle Unit 3 beginning on the in-service date of July 31, 2023. PTCs are recognized as an income tax benefit based on KWH production. In addition, pursuant to the Global Amendments to the Vogtle Joint Ownership Agreements (as defined in Note (B) under "Georgia Power – Nuclear Construction – Joint Owner Contracts"), Georgia Power is purchasing advanced nuclear PTCs for Plant Vogtle Unit 3 from certain other Vogtle Owners. The gain recognized on the purchase of the joint owner PTCs is recognized as an income tax benefit. See Note 1 to the financial statements under "Income Taxes" in Item 8 of the Form 10-K for additional information regarding accounting policies related to income taxes.

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 two of its acquisitions whereby it is primarily obligated to make generation-based payments to the seller, commencing at the commercial operation of each facility and continuing through 2026 and 2035, respectively. The obligations are primarily categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility's generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.

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

"Other investments" primarily includes 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.

Derivatives

The Registrants are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. 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.

Energy-Related Derivatives

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

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

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

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

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

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

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

Interest Rate Derivatives

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

Foreign Currency Derivatives

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

Derivative Financial Statement Presentation and Amounts

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

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Introduction (Tables)

9 Months Ended

Sep. 30, 2023

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Goodwill

Goodwill at September 30, 2023 and December 31, 2022 was as follows:

	Goodwill
	(in millions)
Southern Company	$	5,161
Southern Company Gas:
Gas distribution operations	$	4,034
Gas marketing services	981
Southern Company Gas total	$	5,015

Schedule of Other Intangible Assets, Indefinite-Lived

Other intangible assets were as follows:

	At September 30, 2023						At December 31, 2022
	Gross Carrying Amount		Accumulated Amortization		Other Intangible Assets, Net		Gross Carrying Amount		Accumulated Amortization		Other Intangible Assets, Net
	(in millions)						(in millions)
Southern Company
Subject to amortization:
Customer relationships	$	211	$	(169)	$	42	$	212	$	(162)	$	50
Trade names	63		(50)		13		64		(44)		20
PPA fair value adjustments	390		(143)		247		390		(129)		261
Other	5		(5)		—		5		(5)		—
Total subject to amortization	$	669	$	(367)	$	302	$	671	$	(340)	$	331
Not subject to amortization:
FCC licenses	75		—		75		75		—		75
Total other intangible assets	$	744	$	(367)	$	377	$	746	$	(340)	$	406
Southern Power(*)
PPA fair value adjustments	$	390	$	(143)	$	247	$	390	$	(129)	$	261
Southern Company Gas(*)
Gas marketing services
Customer relationships	$	156	$	(143)	$	13	$	156	$	(139)	$	17
Trade names	26		(20)		6		26		(17)		9
Total other intangible assets	$	182	$	(163)	$	19	$	182	$	(156)	$	26

(*) All subject to amortization.

Schedule of Other Intangible Assets, Finite-Lived

Other intangible assets were as follows:

	At September 30, 2023						At December 31, 2022
	Gross Carrying Amount		Accumulated Amortization		Other Intangible Assets, Net		Gross Carrying Amount		Accumulated Amortization		Other Intangible Assets, Net
	(in millions)						(in millions)
Southern Company
Subject to amortization:
Customer relationships	$	211	$	(169)	$	42	$	212	$	(162)	$	50
Trade names	63		(50)		13		64		(44)		20
PPA fair value adjustments	390		(143)		247		390		(129)		261
Other	5		(5)		—		5		(5)		—
Total subject to amortization	$	669	$	(367)	$	302	$	671	$	(340)	$	331
Not subject to amortization:
FCC licenses	75		—		75		75		—		75
Total other intangible assets	$	744	$	(367)	$	377	$	746	$	(340)	$	406
Southern Power(*)
PPA fair value adjustments	$	390	$	(143)	$	247	$	390	$	(129)	$	261
Southern Company Gas(*)
Gas marketing services
Customer relationships	$	156	$	(143)	$	13	$	156	$	(139)	$	17
Trade names	26		(20)		6		26		(17)		9
Total other intangible assets	$	182	$	(163)	$	19	$	182	$	(156)	$	26

(*) All subject to amortization.

Schedule of Amortization of Other Intangible Assets

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Nine Months Ended		Three Months Ended		Nine Months Ended
	September 30, 2023				September 30, 2022
	(in millions)
Southern Company(a)	$	10	$	27	$	11	$	30
Southern Power(b)	5		14		5		15
Southern Company Gas	3		7		4		9

(a)Includes $5 million, $14 million, $5 million, and $15 million for the three and nine months ended September 30, 2023 and 2022, respectively, recorded as a reduction to operating revenues.

(b)Recorded as a reduction to operating revenues.

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		Alabama Power		Georgia Power		Southern Power		Southern Company Gas
	(in millions)
At September 30, 2023
Cash and cash equivalents	$	1,676	$	621	$	173	$	236	$	397
Restricted cash(a):
Other current assets	176		108		48		18		2
Other deferred charges and assets	38		—		35		3		—
Total cash, cash equivalents, and restricted cash(b)	$	1,890	$	729	$	256	$	257	$	399
At December 31, 2022
Cash and cash equivalents	$	1,917	$	687	$	364	$	131	$	81
Restricted cash(a):
Other current assets	62		—		60		—		2
Other deferred charges and assets	58		—		56		3		—
Total cash, cash equivalents, and restricted cash(b)	$	2,037	$	687	$	480	$	133	$	83

(a)For Alabama Power, balance at September 30, 2023 reflects proceeds from the issuance of solid waste disposal facility revenue bonds in 2023. For Georgia Power, reflects proceeds from the issuance of solid waste disposal facility revenue bonds in 2022. For Southern Power, reflects $18 million at September 30, 2023 resulting from an arbitration interim award held to fund future replacement costs and $3 million at both September 30, 2023 and December 31, 2022 held to fund estimated construction completion costs at the Deuel Harvest wind facility. See Note (C) under "General Litigation Matters – Southern Power" for additional information. For Southern Company Gas, reflects collateral for workers' compensation, life insurance, and long-term disability insurance.

(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		Alabama Power		Georgia Power		Southern Power		Southern Company Gas
	(in millions)
At September 30, 2023
Cash and cash equivalents	$	1,676	$	621	$	173	$	236	$	397
Restricted cash(a):
Other current assets	176		108		48		18		2
Other deferred charges and assets	38		—		35		3		—
Total cash, cash equivalents, and restricted cash(b)	$	1,890	$	729	$	256	$	257	$	399
At December 31, 2022
Cash and cash equivalents	$	1,917	$	687	$	364	$	131	$	81
Restricted cash(a):
Other current assets	62		—		60		—		2
Other deferred charges and assets	58		—		56		3		—
Total cash, cash equivalents, and restricted cash(b)	$	2,037	$	687	$	480	$	133	$	83

(a)For Alabama Power, balance at September 30, 2023 reflects proceeds from the issuance of solid waste disposal facility revenue bonds in 2023. For Georgia Power, reflects proceeds from the issuance of solid waste disposal facility revenue bonds in 2022. For Southern Power, reflects $18 million at September 30, 2023 resulting from an arbitration interim award held to fund future replacement costs and $3 million at both September 30, 2023 and December 31, 2022 held to fund estimated construction completion costs at the Deuel Harvest wind facility. See Note (C) under "General Litigation Matters – Southern Power" for additional information. For Southern Company Gas, reflects collateral for workers' compensation, life insurance, and long-term disability insurance.

(b)Total may not add due to rounding.

Schedule of Storm Damage Reserve Activity

Storm damage reserve activity for the traditional electric operating companies during the nine months ended September 30, 2023 was as follows:

	Southern Company(*)		Alabama Power		Georgia Power(*)		Mississippi Power
	(in millions)
Balance at December 31, 2022	$	216	$	97	$	83	$	36
Accrual	42		9		24		9
Weather-related damages	(242)		(35)		(204)		(3)
Balance at September 30, 2023	$	16	$	71	$	(97)	$	42

(*)See Note (B) under "Georgia Power – Storm Damage Recovery" for additional information.

Schedule of Asset Retirement Obligations

The estimated costs of decommissioning Plant Farley based on Alabama Power's June 2023 site study are as follows:

	Plant Farley
Decommissioning periods:
Beginning year	2037
Completion year	2087
	(in millions)
Site study costs:
Radiated structures	$	1,402
Spent fuel management	513
Non-radiated structures	133
Total site study costs	$	2,048

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Regulatory Matters (Tables)

9 Months Ended

Sep. 30, 2023

Regulated Operations [Abstract]

Schedule of Cost Recovery Clauses

The recovery balances for certain retail regulatory clauses of the traditional electric operating companies and Southern Company Gas at September 30, 2023 and December 31, 2022 were as follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2023		December 31, 2022
		(in millions)
Alabama Power
Rate CNP Compliance	Other regulatory liabilities, deferred	$	3	$	—
	Other regulatory assets, current	—		47
Rate CNP PPA	Other regulatory assets, current	17		18
	Other regulatory assets, deferred	90		102
Retail Energy Cost Recovery	Other regulatory assets, current	208		102
	Other regulatory assets, deferred	80		520
Georgia Power
Fuel Cost Recovery(*)	Receivables – under recovered fuel clause revenues	$	730	$	—
	Deferred under recovered fuel clause revenues	1,279		2,056
Mississippi Power
Fuel Cost Recovery	Receivables – customer accounts, net	$	25	$	1
Ad Valorem Tax	Other regulatory assets, current	3		12
	Other regulatory assets, deferred	11		19
Southern Company Gas
Natural Gas Cost Recovery	Natural gas cost under recovery	$	—	$	108
	Natural gas cost over recovery	165		—

(*)See "Georgia Power – Fuel Cost Recovery" herein for additional information.

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 July 2023 and March 2024, respectively, is as follows:

	(in millions)
Base project capital cost forecast(a)(b)	$	10,736
Construction contingency estimate	17
Total project capital cost forecast(a)(b)	10,753
Net investment at September 30, 2023(b)	(10,495)
Remaining estimate to complete	$	258

(a)Includes approximately $610 million of costs that are not shared with the other Vogtle Owners, including $33 million of construction monitoring costs approved for recovery by the Georgia PSC in its nineteenth VCM order, and approximately $567 million of incremental costs under the cost-sharing provisions of the joint ownership agreements described below. Excludes financing costs expected to be capitalized through AFUDC of approximately $420 million, of which $385 million had been accrued through September 30, 2023.

(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 and capital projects during the first nine months of 2023 were as follows:

Utility	Program	Nine Months Ended September 30, 2023
		(in millions)
Nicor Gas	Investing in Illinois	$	320
Virginia Natural Gas	SAVE	56
Atlanta Gas Light	System Reinforcement Rider	84
Chattanooga Gas	Pipeline Replacement Program	7
Total		$	467

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Revenue from Contracts with Customers and Lease Income (Tables)

9 Months Ended

Sep. 30, 2023

Revenue from Contract with Customer [Abstract]

Schedule of Disaggregation of Revenue

The following table disaggregates revenue from contracts with customers for the three and nine months ended September 30, 2023 and 2022:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2023
Operating revenues
Retail electric revenues
Residential	$	2,543	$	969	$	1,473	$	101	$	—	$	—
Commercial	1,845		599		1,151		95		—		—
Industrial	1,116		498		528		90		—		—
Other	30		3		25		2		—		—
Total retail electric revenues	5,534		2,069		3,177		288		—		—
Natural gas distribution revenues
Residential	217		—		—		—		—		217
Commercial	56		—		—		—		—		56
Transportation	275		—		—		—		—		275
Industrial	4		—		—		—		—		4
Other	60		—		—		—		—		60
Total natural gas distribution revenues	612		—		—		—		—		612
Wholesale electric revenues
PPA energy revenues	317		66		31		2		226		—
PPA capacity revenues	151		26		13		3		110		—
Non-PPA revenues	101		15		21		137		126		—
Total wholesale electric revenues	569		107		65		142		462		—
Other natural gas revenues
Gas marketing services	54		—		—		—		—		54
Other natural gas revenues	8		—		—		—		—		8
Total natural gas revenues	62		—		—		—		—		62
Other revenues	330		54		146		10		18		—
Total revenue from contracts with customers	7,107		2,230		3,388		440		480		674
Other revenue sources(*)	(127)		(147)		(151)		(4)		173		15
Total operating revenues	$	6,980	$	2,083	$	3,237	$	436	$	653	$	689

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Nine Months Ended September 30, 2023
Operating revenues
Retail electric revenues
Residential	$	5,717	$	2,277	$	3,202	$	238	$	—	$	—
Commercial	4,464		1,493		2,733		238		—		—
Industrial	2,770		1,324		1,195		251		—		—
Other	84		10		68		6		—		—
Total retail electric revenues	13,035		5,104		7,198		733		—		—
Natural gas distribution revenues
Residential	1,443		—		—		—		—		1,443
Commercial	370		—		—		—		—		370
Transportation	878		—		—		—		—		878
Industrial	33		—		—		—		—		33
Other	228		—		—		—		—		228
Total natural gas distribution revenues	2,952		—		—		—		—		2,952
Wholesale electric revenues
PPA energy revenues	853		196		66		8		601		—
PPA capacity revenues	490		130		38		36		289		—
Non-PPA revenues	199		49		30		315		312		—
Total wholesale electric revenues	1,542		375		134		359		1,202		—
Other natural gas revenues
Gas marketing services	358		—		—		—		—		358
Other natural gas revenues	28		—		—		—		—		28
Total natural gas revenues	386		—		—		—		—		386
Other revenues	971		159		422		31		46		—
Total revenue from contracts with customers	18,886		5,638		7,754		1,123		1,248		3,338
Other revenue sources(*)	322		(218)		51		14		438		79
Total operating revenues	$	19,208	$	5,420	$	7,805	$	1,137	$	1,686	$	3,417

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2022
Operating revenues
Retail electric revenues
Residential	$	2,104	$	799	$	1,212	$	93	$	—	$	—
Commercial	1,637		499		1,051		87		—		—
Industrial	1,183		452		642		89		—		—
Other	27		3		22		2		—		—
Total retail electric revenues	4,951		1,753		2,927		271		—		—
Natural gas distribution revenues
Residential	331		—		—		—		—		331
Commercial	93		—		—		—		—		93
Transportation	259		—		—		—		—		259
Industrial	12		—		—		—		—		12
Other	49		—		—		—		—		49
Total natural gas distribution revenues	744		—		—		—		—		744
Wholesale electric revenues
PPA energy revenues	812		187		40		4		591		—
PPA capacity revenues	175		56		12		1		107		—
Non-PPA revenues	58		67		4		242		303		—
Total wholesale electric revenues	1,045		310		56		247		1,001		—
Other natural gas revenues
Gas marketing services	84		—		—		—		—		84
Other natural gas revenues	15		—		—		—		—		15
Total natural gas revenues	99		—		—		—		—		99
Other revenues	277		65		110		13		9		—
Total revenue from contracts with customers	7,116		2,128		3,093		531		1,010		843
Other revenue sources(*)	1,262		316		796		(21)		170		14
Total operating revenues	$	8,378	$	2,444	$	3,889	$	510	$	1,180	$	857

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Nine Months Ended September 30, 2022
Operating revenues
Retail electric revenues
Residential	$	5,282	$	2,049	$	2,995	$	238	$	—	$	—
Commercial	4,202		1,285		2,688		229		—		—
Industrial	2,914		1,143		1,529		242		—		—
Other	79		10		62		7		—		—
Total retail electric revenues	12,477		4,487		7,274		716		—		—
Natural gas distribution revenues
Residential	1,821		—		—		—		—		1,821
Commercial	493		—		—		—		—		493
Transportation	872		—		—		—		—		872
Industrial	60		—		—		—		—		60
Other	244		—		—		—		—		244
Total natural gas distribution revenues	3,490		—		—		—		—		3,490
Wholesale electric revenues
PPA energy revenues	1,739		354		112		11		1,285		—
PPA capacity revenues	443		135		35		4		273		—
Non-PPA revenues	182		166		19		511		572		—
Total wholesale electric revenues	2,364		655		166		526		2,130		—
Other natural gas revenues
Gas marketing services	417		—		—		—		—		417
Other natural gas revenues	41		—		—		—		—		41
Total natural gas revenues	458		—		—		—		—		458
Other revenues	810		173		327		34		27		—
Total revenue from contracts with customers	19,599		5,315		7,767		1,276		2,157		3,948
Other revenue sources(*)	2,633		708		1,451		3		461		50
Total operating revenues	$	22,232	$	6,023	$	9,218	$	1,279	$	2,618	$	3,998

(*)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 (including those related to fuel costs) that meet other scope exceptions for revenues from contracts with customers at the traditional electric operating companies.

Schedule of Contract Balances

The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers at September 30, 2023 and December 31, 2022:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Accounts Receivable
At September 30, 2023	$	2,680	$	858	$	1,175	$	106	$	138	$	331
At December 31, 2022	3,123		696		922		92		237		1,107
Contract Assets
At September 30, 2023	$	267	$	6	$	146	$	—	$	—	$	41
At December 31, 2022	156		2		89		—		—		—
Contract Liabilities
At September 30, 2023	$	62	$	—	$	8	$	2	$	8	$	—
At December 31, 2022	45		4		9		—		1		—

Schedule of Remaining Performance Obligations

Revenues from contracts with customers related to these performance obligations remaining at September 30, 2023 are expected to be recognized as follows:

	2023 (remaining)		2024		2025		2026		2027		Thereafter
	(in millions)
Southern Company	$	166	$	599	$	359	$	318	$	319	$	2,245
Alabama Power	10		24		8		—		—		—
Georgia Power	23		66		34		14		14		23
Southern Power	84		356		302		303		310		2,233
Southern Company Gas	4		29		—		—		—		—

Schedule of Lease Income

Lease income for the three and nine months ended September 30, 2023 and 2022 is as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
For the Three Months Ended September 30, 2023
Lease income - interest income on sales-type leases	$	6	$	—	$	—	$	4	$	2	$	—
Lease income - operating leases	36		3		7		—		21		9
Variable lease income	134		—		—		—		144		—
Total lease income	$	176	$	3	$	7	$	4	$	167	$	9
For the Nine Months Ended September 30, 2023
Lease income - interest income on sales-type leases	$	18	$	—	$	—	$	11	$	7	$	—
Lease income - operating leases	129		32		22		2		64		27
Variable lease income	327		1		—		—		351		—
Total lease income	$	474	$	33	$	22	$	13	$	422	$	27
For the Three Months Ended September 30, 2022
Lease income - interest income on sales-type leases	$	7	$	—	$	—	$	4	$	3	$	—
Lease income - operating leases	50		19		8		1		21		9
Variable lease income	139		—		—		—		145		—
Total lease income	$	196	$	19	$	8	$	5	$	169	$	9
For the Nine Months Ended September 30, 2022
Lease income - interest income on sales-type leases	$	19	$	—	$	—	$	11	$	8	$	—
Lease income - operating leases	149		58		24		1		64		27
Variable lease income	355		1		—		—		372		—
Total lease income	$	523	$	59	$	24	$	12	$	444	$	27

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Consolidated Entities and Equity Method Investments (Tables)

9 Months Ended

Sep. 30, 2023

Regulated Operations [Abstract]

Schedule of Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments at September 30, 2023 and December 31, 2022 and related earnings from those investments for the three and nine months ended September 30, 2023 and 2022 were as follows:

Investment Balance	September 30, 2023		December 31, 2022
	(in millions)
SNG	$	1,210	$	1,243
Other	33		33
Total	$	1,243	$	1,276

Schedule of Earnings (Loss) from Equity Method Investments

	Three Months Ended September 30,				Nine Months Ended September 30,
Earnings from Equity Method Investments	2023		2022		2023		2022
	(in millions)
SNG	$	32	$	34	$	104	$	104
Other	—		—		—		1
Total	$	32	$	34	$	104	$	105

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Financing and Leases (Tables)

9 Months Ended

Sep. 30, 2023

Debt Disclosure [Abstract]

Schedule of Credit Arrangements

At September 30, 2023, committed credit arrangements with banks were as follows:

	Expires
Company	2024		2025		2026		2028		Total		Unused		Expires within One Year
	(in millions)
Southern Company parent(a)	$	150	$	—	$	—	$	1,850	$	2,000	$	1,998	$	150
Alabama Power	—		—		650		700		1,350		1,350		—
Georgia Power	—		—		—		1,750		1,750		1,726		—
Mississippi Power	—		125		150		—		275		275		—
Southern Power(a)(b)	—		—		—		600		600		589		—
Southern Company Gas(c)	100		—		—		1,500		1,600		1,598		100
SEGCO	30		—		—		—		30		30		30
Southern Company	$	280	$	125	$	800	$	6,400	$	7,605	$	7,566	$	280

(a)Arrangement expiring in 2028 represents a $2.45 billion combined arrangement for Southern Company and Southern Power as borrowers. Pursuant to the combined facility, the allocations between Southern Company and Southern Power may be adjusted.

(b)Does not include Southern Power Company's $75 million and $100 million continuing letter of credit facilities for standby letters of credit, expiring in 2025 and 2026, respectively, of which $9 million and $16 million, respectively, was unused at September 30, 2023. In March 2023, Southern Power amended the $100 million letter of credit facility, which, among other things, extended the expiration date from 2025 to 2026 and increased the amount from $75 million. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.

(c)Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $800 million of the credit arrangement expiring in 2028. Southern Company Gas' committed credit arrangement expiring in 2028 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 2028, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. Nicor Gas is also the borrower under a $100 million credit arrangement expiring in 2024.

Schedule of Shares Used to Compute Diluted Earnings Per Share

Shares used to compute diluted EPS were as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2023	2022	2023	2022
	(in millions)
As reported shares	1,092	1,082	1,092	1,070
Effect of stock-based compensation	7	6	6	6
Diluted shares	1,099	1,088	1,098	1,076

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Retirement Benefits (Tables)

9 Months Ended

Sep. 30, 2023

Retirement Benefits [Abstract]

Schedule of Pension Plans and Postretirement Plans

Components of the net periodic benefit costs for the three and nine months ended September 30, 2023 and 2022 are presented in the following tables.

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2023
Pension Plans
Service cost	$	69	$	16	$	17	$	2	$	2	$	6
Interest cost	156		37		48		7		2		11
Expected return on plan assets	(307)		(75)		(97)		(13)		(4)		(22)
Amortization:
Prior service costs	—		—		—		—		—		(1)
Regulatory asset	—		—		—		—		—		4
Net (gain) loss	8		2		4		1		—		(1)
Net periodic pension income	$	(74)	$	(20)	$	(28)	$	(3)	$	—	$	(3)
Postretirement Benefits
Service cost	$	4	$	1	$	1	$	—	$	—	$	—
Interest cost	18		5		6		1		—		2
Expected return on plan assets	(21)		(9)		(7)		(1)		—		(2)
Amortization:
Prior service costs	—		—		1		—		—		—
Regulatory asset	—		—		—		—		—		2
Net gain	(4)		(1)		(1)		—		—		(1)
Net periodic postretirement benefit cost (income)	$	(3)	$	(4)	$	—	$	—	$	—	$	1
Nine Months Ended September 30, 2023
Pension Plans
Service cost	$	207	$	48	$	51	$	8	$	5	$	18
Interest cost	469		109		143		21		6		32
Expected return on plan assets	(922)		(223)		(289)		(41)		(12)		(65)
Amortization:
Prior service costs	—		—		1		—		—		(2)
Regulatory asset	—		—		—		—		—		11
Net (gain) loss	24		7		10		1		—		(3)
Net periodic pension income	$	(222)	$	(59)	$	(84)	$	(11)	$	(1)	$	(9)
Postretirement Benefits
Service cost	$	11	$	3	$	3	$	—	$	—	$	1
Interest cost	53		13		19		2		—		6
Expected return on plan assets	(62)		(26)		(22)		(1)		—		(5)
Amortization:
Prior service costs	1		—		1		—		—		—
Regulatory asset	—		—		—		—		—		5
Net gain	(10)		(2)		(3)		—		—		(3)
Net periodic postretirement benefit cost (income)	$	(7)	$	(12)	$	(2)	$	1	$	—	$	4

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Three Months Ended September 30, 2022
Pension Plans
Service cost	$	103	$	25	$	26	$	5	$	2	$	9
Interest cost	102		24		31		5		2		7
Expected return on plan assets	(316)		(77)		(99)		(15)		(4)		(22)
Amortization:
Prior service costs	—		—		—		—		—		(1)
Regulatory asset	—		—		—		—		—		3
Net loss	60		16		18		2		1		2
Net periodic pension cost (income)	$	(51)	$	(12)	$	(24)	$	(3)	$	1	$	(2)
Postretirement Benefits
Service cost	$	6	$	2	$	2	$	1	$	1	$	—
Interest cost	10		3		4		—		—		1
Expected return on plan assets	(20)		(9)		(8)		—		—		(2)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		2
Net (gain)/loss	1		—		—		—		—		(1)
Net periodic postretirement benefit cost (income)	$	(4)	$	(4)	$	(2)	$	1	$	1	$	—
Nine Months Ended September 30, 2022
Pension Plans
Service cost	$	309	$	74	$	78	$	13	$	7	$	26
Interest cost	306		72		92		14		5		21
Expected return on plan assets	(949)		(229)		(298)		(44)		(12)		(68)
Amortization:
Prior service costs	—		—		1		—		—		(2)
Regulatory asset	—		—		—		—		—		11
Net loss	180		47		55		9		2		5
Net periodic pension cost (income)	$	(154)	$	(36)	$	(72)	$	(8)	$	2	$	(7)
Postretirement Benefits
Service cost	$	17	$	5	$	5	$	1	$	1	$	1
Interest cost	31		8		11		1		—		4
Expected return on plan assets	(60)		(25)		(21)		(1)		—		(6)
Amortization:
Prior service costs	(1)		—		—		—		—		—
Regulatory asset	—		—		—		—		—		5
Net (gain) loss	1		—		1		—		—		(2)
Net periodic postretirement benefit cost (income)	$	(12)	$	(12)	$	(4)	$	1	$	1	$	2

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2023

Fair Value Disclosures [Abstract]

Schedule of Assets and Liabilities Measured at Fair Value

At September 30, 2023, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

	Fair Value Measurements Using:
At September 30, 2023	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)	$	7	$	73	$	—	$	—	$	80
Investments in trusts:(b)
Domestic equity	692		196		—		—		888
Foreign equity	131		154		—		—		285
U.S. Treasury and government agency securities	—		337		—		—		337
Municipal bonds	—		42		—		—		42
Pooled funds – fixed income	—		6		—		—		6
Corporate bonds	—		368		—		—		368
Mortgage and asset backed securities	—		85		—		—		85
Private equity	—		—		—		169		169
Cash and cash equivalents	3		—		—		—		3
Other	33		3		—		8		44
Cash equivalents and restricted cash	919		11		—		—		930
Other investments	9		34		8		—		51
Total	$	1,794	$	1,309	$	8	$	177	$	3,288
Liabilities:
Energy-related derivatives(a)	$	34	$	217	$	—	$	—	$	251
Interest rate derivatives	—		351		—		—		351
Foreign currency derivatives	—		192		—		—		192
Contingent consideration	5		—		19		—		24
Other	—		13		—		—		13
Total	$	39	$	773	$	19	$	—	$	831

	Fair Value Measurements Using:
At September 30, 2023	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	$	—	$	26	$	—	$	—	$	26
Nuclear decommissioning trusts:(b)
Domestic equity	404		188		—		—		592
Foreign equity	131		—		—		—		131
U.S. Treasury and government agency securities	—		20		—		—		20
Municipal bonds	—		1		—		—		1
Corporate bonds	—		215		—		—		215
Mortgage and asset backed securities	—		22		—		—		22
Private equity	—		—		—		169		169
Other	10		—		—		8		18
Cash equivalents and restricted cash	489		11		—		—		500
Other investments	—		34		—		—		34
Total	$	1,034	$	517	$	—	$	177	$	1,728
Liabilities:
Energy-related derivatives	$	—	$	75	$	—	$	—	$	75
Georgia Power
Assets:
Energy-related derivatives	$	—	$	14	$	—	$	—	$	14
Nuclear decommissioning trusts:(b)
Domestic equity	288		1		—		—		289
Foreign equity	—		153		—		—		153
U.S. Treasury and government agency securities	—		317		—		—		317
Municipal bonds	—		41		—		—		41
Corporate bonds	—		153		—		—		153
Mortgage and asset backed securities	—		63		—		—		63
Other	23		3		—		—		26
Total	$	311	$	745	$	—	$	—	$	1,056
Liabilities:
Energy-related derivatives	$	—	$	83	$	—	$	—	$	83

	Fair Value Measurements Using:
At September 30, 2023	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	$	—	$	24	$	—	$	—	$	24
Cash equivalents	3		—		—		—		3
Total	$	3	$	24	$	—	$	—	$	27
Liabilities:
Energy-related derivatives	$	—	$	44	$	—	$	—	$	44
Southern Power
Assets:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5
Cash equivalents	23		—		—		—		23
Total	$	23	$	5	$	—	$	—	$	28
Liabilities:
Energy-related derivatives	$	—	$	6	$	—	$	—	$	6
Foreign currency derivatives	—		42		—		—		42
Contingent consideration	5		—		19		—		24
Other	—		13		—		—		13
Total	$	5	$	61	$	19	$	—	$	85
Southern Company Gas
Assets:
Energy-related derivatives(a)	$	7	$	4	$	—	$	—	$	11
Non-qualified deferred compensation trusts:
Domestic equity	—		7		—		—		7
Foreign equity	—		1		—		—		1
Pooled funds – fixed income	—		6		—		—		6
Cash equivalents	3		—		—		—		3
Cash equivalents	294		—		—		—		294
Total	$	304	$	18	$	—	$	—	$	322
Liabilities:
Energy-related derivatives(a)	$	34	$	9	$	—	$	—	$	43
Interest rate derivatives	—		99		—		—		99
Total	$	34	$	108	$	—	$	—	$	142

(a)Excludes cash collateral of $49 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.

Schedule of Increase (Decrease) In Fair Value Of Funds

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

	Three Months Ended				Nine Months Ended
Fair value increases (decreases)	September 30, 2023		September 30, 2022		September 30, 2023		September 30, 2022
	(in millions)
Southern Company	$	(4)	$	(106)	$	211	$	(486)
Alabama Power	(36)		(53)		54		(245)
Georgia Power	32		(53)		157		(241)

Schedule of Financial Instruments for which Carrying Amount Did Not Equal Fair Value

At September 30, 2023, 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	$	58.8	$	11.2	$	15.8	$	1.6	$	2.7	$	8.1
Fair value	50.8		9.4		13.4		1.3		2.4		6.5

(*)The carrying amount of Southern Company Gas' long-term debt includes fair value adjustments from 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.

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Derivatives (Tables)

9 Months Ended

Sep. 30, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Energy-Related Derivatives

At September 30, 2023, 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(*)	422	2030	2028
Alabama Power	109	2026	—
Georgia Power	104	2026	—
Mississippi Power	80	2027	—
Southern Power	8	2030	2024
Southern Company Gas(*)	121	2027	2028

(*)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 135.5 million mmBtu long natural gas positions and 14.2 million mmBtu short natural gas positions at September 30, 2023, which is also included in Southern Company's total volume.

Schedule of Interest Rate Derivatives

At September 30, 2023, the following interest rate derivatives were outstanding:

	Notional Amount		Weighted Average Interest Rate Paid	Interest Rate Received	Hedge Maturity Date	Fair Value Gain (Loss) at September 30, 2023
	(in millions)					(in millions)
Fair Value Hedges of Existing Debt
Southern Company parent	$	400	1-month SOFR + 0.80%	1.75%	March 2028	$	(56)
Southern Company parent	1,000		1-month SOFR + 2.48%	3.70%	April 2030	(196)
Southern Company Gas	500		1-month SOFR + 0.49%	1.75%	January 2031	(99)
Southern Company	$	1,900				$	(351)

Schedule of Foreign Currency Derivatives

At September 30, 2023, the following foreign currency derivatives were outstanding:

	Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at September 30, 2023
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	564	3.78%	€	500	1.85%	June 2026	$	(42)
Fair Value Hedges of Existing Debt
Southern Company parent	1,476		3.39%	1,250		1.88%	September 2027	(150)
Southern Company	$	2,040		€	1,750			$	(192)

Schedule of Derivative Category and Balance Sheet Location

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

	At September 30, 2023				At December 31, 2022
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Southern Company
Energy-related derivatives designated as hedging instruments for regulatory purposes
Assets from risk management activities/Liabilities from risk management activities	$	34	$	134	$	123	$	121
Other deferred charges and assets/Other deferred credits and liabilities	36		77		52		44
Total derivatives designated as hedging instruments for regulatory purposes	70		211		175		165
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities	—		28		3		27
Other deferred charges and assets/Other deferred credits and liabilities	4		2		6		4
Interest rate derivatives:
Assets from risk management activities/Liabilities from risk management activities	—		80		12		62
Other deferred charges and assets/Other deferred credits and liabilities	—		271		—		240
Foreign currency derivatives:
Assets from risk management activities/Liabilities from risk management activities	—		35		—		34
Other deferred charges and assets/Other deferred credits and liabilities	—		157		—		182
Total derivatives designated as hedging instruments in cash flow and fair value hedges	4		573		21		549
Energy-related derivatives not designated as hedging instruments
Assets from risk management activities/Liabilities from risk management activities	5		8		13		13
Other deferred charges and assets/Other deferred credits and liabilities	1		2		2		1
Total derivatives not designated as hedging instruments	6		10		15		14
Gross amounts recognized	80		794		211		728
Gross amounts offset(a)	(37)		(86)		(70)		(111)
Net amounts recognized in the Balance Sheets(b)	$	43	$	708	$	141	$	617

	At September 30, 2023				At December 31, 2022
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)				(in millions)
Alabama Power(c)
Energy-related derivatives designated as hedging instruments for regulatory purposes
Other current assets/Other current liabilities	$	15	$	46	$	42	$	21
Other deferred charges and assets/Other deferred credits and liabilities	11		29		20		18
Total derivatives designated as hedging instruments for regulatory purposes	26		75		62		39
Gross amounts offset	(17)		(17)		(24)		(24)
Net amounts recognized in the Balance Sheets	$	9	$	58	$	38	$	15
Georgia Power
Energy-related derivatives designated as hedging instruments for regulatory purposes
Other current assets/Other current liabilities	$	4	$	57	$	36	$	43
Other deferred charges and assets/Other deferred credits and liabilities	10		26		6		18
Total derivatives designated as hedging instruments for regulatory purposes	14		83		42		61
Energy-related derivatives not designated as hedging instruments
Other current assets/Other current liabilities	—		—		—		1
Gross amounts recognized	14		83		42		62
Gross amounts offset	(11)		(11)		(21)		(21)
Net amounts recognized in the Balance Sheets	$	3	$	72	$	21	$	41
Mississippi Power(c)
Energy-related derivatives designated as hedging instruments for regulatory purposes
Other current assets/Other current liabilities	$	9	$	22	$	33	$	24
Other deferred charges and assets/Other deferred credits and liabilities	15		22		26		8
Total derivatives designated as hedging instruments for regulatory purposes	24		44		59		32
Gross amounts offset	(17)		(17)		(17)		(17)
Net amounts recognized in the Balance Sheets	$	7	$	27	$	42	$	15

	At September 30, 2023				At December 31, 2022
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	$	—	$	5	$	—	$	12
Other deferred charges and assets/Other deferred credits and liabilities	4		—		5		—
Foreign currency derivatives:
Other current assets/Other current liabilities	—		11		—		11
Other deferred charges and assets/Other deferred credits and liabilities	—		31		—		36
Total derivatives designated as hedging instruments in cash flow and fair value hedges	4		47		5		59
Energy-related derivatives not designated as hedging instruments
Other current assets/Other current liabilities	1		1		2		—
Other deferred charges and assets/Other deferred credits and liabilities	—		—		1		—
Total derivatives not designated as hedging instruments	1		1		3		—
Gross amounts recognized	5		48		8		59
Gross amounts offset	(1)		(1)		—		—
Net amounts recognized in the Balance Sheets	$	4	$	47	$	8	$	59
Southern Company Gas
Energy-related derivatives designated as hedging instruments for regulatory purposes
Other current assets/Other current liabilities	$	6	$	9	$	12	$	33
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	—		23		3		15
Other deferred charges and assets/Other deferred credits and liabilities	—		2		1		4
Interest rate derivatives:
Other current assets/Other current liabilities	—		21		—		14
Other deferred charges and assets/Other deferred credits and liabilities	—		78		—		72
Total derivatives designated as hedging instruments in cash flow and fair value hedges	—		124		4		105
Energy-related derivatives not designated as hedging instruments
Other current assets/Other current liabilities	4		7		11		12
Other deferred charges and assets/Other deferred credits and liabilities	1		2		1		1
Total derivatives not designated as hedging instruments	5		9		12		13
Gross amounts recognized	11		142		28		151
Gross amounts offset(a)	9		(40)		—		(41)
Net amounts recognized in the Balance Sheets(b)	$	20	$	102	$	28	$	110

(a)Gross amounts offset includes cash collateral held on deposit in broker margin accounts of $49 million and $41 million at September 30, 2023 and December 31, 2022, respectively.

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

(c)Energy-related derivatives not designated as hedging instruments were immaterial for Alabama Power and Mississippi Power at December 31, 2022. There were no such instruments for Alabama Power and Mississippi Power at September 30, 2023.

Schedule of Pre-tax Effects of Unrealized Derivative Gains (Losses)

At September 30, 2023 and December 31, 2022, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Company Gas
	(in millions)
At September 30, 2023:
Energy-related derivatives:
Other regulatory assets, current	$	(113)	$	(39)	$	(54)	$	(16)	$	(4)
Other regulatory assets, deferred	(48)		(19)		(18)		(11)		—
Other regulatory liabilities, current	23		8		1		4		10
Other regulatory liabilities, deferred	6		1		2		3		—
Total energy-related derivative gains (losses)	$	(132)	$	(49)	$	(69)	$	(20)	$	6
At December 31, 2022:
Energy-related derivatives:
Other regulatory assets, current	$	(71)	$	(8)	$	(26)	$	(13)	$	(24)
Other regulatory assets, deferred	(23)		(7)		(14)		(2)		—
Other regulatory liabilities, current	72		29		19		22		2
Other regulatory liabilities, deferred	31		9		2		20		—
Total energy-related derivative gains (losses)	$	9	$	23	$	(19)	$	27	$	(22)

Schedule of Pre-Tax Effects of Hedging on AOCI

For the three and nine months ended September 30, 2023 and 2022, the pre-tax effects of cash flow and fair value hedge accounting on accumulated OCI for the applicable Registrants were as follows:

Gain (Loss) Recognized in OCI on Derivatives	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Southern Company
Cash flow hedges:
Energy-related derivatives	$	(4)	$	11	$	(55)	$	51
Interest rate derivatives	(3)		6		(12)		36
Foreign currency derivatives	(15)		(35)		(6)		(137)
Fair value hedges(*):
Foreign currency derivatives	27		20		28		18
Total	$	5	$	2	$	(45)	$	(32)
Georgia Power
Cash flow hedges:
Interest rate derivatives	$	—	$	—	$	(3)	$	31
Southern Power
Cash flow hedges:
Energy-related derivatives	$	—	$	(11)	$	(14)	$	(4)
Foreign currency derivatives	(15)		(35)		(6)		(137)
Total	$	(15)	$	(46)	$	(20)	$	(141)
Southern Company Gas
Cash flow hedges:
Energy-related derivatives	$	(4)	$	22	$	(41)	$	55
Interest rate derivatives	(4)		5		—		—
Total	$	(8)	$	27	$	(41)	$	55

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

Schedule of Pre-Tax Effects of Cash Flow and Fair Value Hedging on Income

For the three and nine months ended September 30, 2023 and 2022, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows:

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2023		2022		2023		2022
	(in millions)				(in millions)
Southern Company
Total cost of natural gas	$	102	$	294	$	1,199	$	1,840
Gain (loss) on energy-related cash flow hedges(a)	(4)		9		(32)		28
Total other operations and maintenance	1,424		1,527		4,352		4,568
Gain (loss) on energy-related cash flow hedges(a)	(1)		—		(2)		—
Total depreciation and amortization	1,143		922		3,365		2,728
Gain (loss) on energy-related cash flow hedges(a)	(5)		(1)		(18)		5
Total interest expense, net of amounts capitalized	(620)		(511)		(1,812)		(1,461)
Gain (loss) on interest rate cash flow hedges(a)	(22)		(7)		(31)		(19)
Gain (loss) on foreign currency cash flow hedges(a)	(3)		(3)		(8)		(16)
Gain (loss) on interest rate fair value hedges(b)	(47)		(102)		(50)		(300)
Total other income (expense), net	141		132		428		414
Gain (loss) on foreign currency cash flow hedges(a)(c)	(14)		(32)		(4)		(129)
Gain (loss) on foreign currency fair value hedges	(7)		(59)		19		(180)
Amount excluded from effectiveness testing recognized in earnings	(27)		(21)		(28)		(17)
Southern Power
Total depreciation and amortization	$	130	$	133	$	380	$	384
Gain (loss) on energy-related cash flow hedges(a)	(5)		(1)		(18)		5
Total interest expense, net of amounts capitalized	(32)		(32)		(98)		(105)
Gain (loss) on foreign currency cash flow hedges(a)	(3)		(3)		(8)		(16)
Total other income (expense), net	4		3		8		5
Gain (loss) on foreign currency cash flow hedges(a)(c)	(14)		(32)		(4)		(129)
Southern Company Gas
Total cost of natural gas	$	102	$	294	$	1,199	$	1,840
Gain (loss) on energy-related cash flow hedges(a)	(4)		9		(32)		28
Total other operations and maintenance	264		252		879		824
Gain (loss) on energy-related cash flow hedges(a)	(1)		—		(2)		—
Total interest expense, net of amounts capitalized	(77)		(65)		(226)		(187)
Gain (loss) on interest rate cash flow hedges(a)	(18)		(2)		(18)		(3)
Gain (loss) on interest rate fair value hedges(b)	(11)		(30)		(14)		(87)

(a)Reclassified from accumulated OCI into earnings.

(b)For fair value hedges, changes in the fair value of the derivative contracts are generally equal to changes in the fair value of the underlying debt and have no material impact on income.

(c)The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.

Schedule of Cumulative Basis Adjustments for Fair Value Hedges

At September 30, 2023 and December 31, 2022, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:

	Carrying Amount of the Hedged Item				Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items	At September 30, 2023		At December 31, 2022		At September 30, 2023		At December 31, 2022
	(in millions)				(in millions)
Southern Company
Long-term debt	$	(2,873)	$	(2,927)	$	328	$	282
Southern Company Gas
Long-term debt	$	(402)	$	(415)	$	95	$	81

Schedule of Pre-tax Effect of Interest Rate and Energy Related Derivatives on Income

For the three and nine months ended September 30, 2023 and 2022, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows:

		Gain (Loss)
		Three Months Ended September 30,				Nine Months Ended September 30,
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2023		2022		2023		2022
		(in millions)				(in millions)
Energy-related derivatives:	Natural gas revenues(*)	$	—	$	3	$	—	$	(10)
	Cost of natural gas	7		(2)		36		(7)
Total derivatives in non-designated hedging relationships		$	7	$	1	$	36	$	(17)

(*)Excludes $14 million of gains for the nine months ended September 30, 2023, and immaterial amounts for all other periods presented, recorded in natural gas revenues associated with weather derivatives.

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Acquisitions and Dispositions (Tables)

9 Months Ended

Sep. 30, 2023

Business Combination and Asset Acquisition [Abstract]

Schedule of Asset Acquisitions

Southern Power's asset acquisitions during the nine months ended September 30, 2023 are detailed in the following table:

Project Facility	Resource	Seller	Approximate Nameplate Capacity (MW)	Location	Southern Power Ownership Percentage	Expected COD	PPA Contract Period
Millers Branch(*)	Solar	EDF Renewables, Inc.	200	Haskell County, TX	100%	Fourth quarter 2025	20 years
South Cheyenne	Solar	Hanwha Q Cells USA Corp.	150	Laramie County, WY	100%	First quarter 2024	20 years

(*)The project includes an option to expand capacity up to an additional 300 MWs.

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Segment and Related Information (Tables)

9 Months Ended

Sep. 30, 2023

Segment Reporting [Abstract]

Schedule of Financial Data for Business Segments

Financial data for business segments and products and services for the three and nine months ended September 30, 2023 and 2022 was as follows:

	Electric Utilities
	Traditional Electric Operating Companies		Southern Power		Eliminations		Total		Southern Company Gas		All Other		Eliminations		Consolidated
	(in millions)
Three Months Ended September 30, 2023
Operating revenues	$	5,674	$	653	$	(160)	$	6,167	$	689	$	154	$	(30)	$	6,980
Segment net income (loss)(a)(b)(c)	1,419		100		—		1,519		82		(179)		—		1,422
Nine Months Ended September 30, 2023
Operating revenues	$	14,145	$	1,686	$	(417)	$	15,414	$	3,417	$	499	$	(122)	$	19,208
Segment net income (loss)(a)(b)(c)(d)	2,852		288		—		3,140		475		(490)		(4)		3,121
At September 30, 2023
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	144	$	—	$	5,161
Total assets	99,464		13,090		(568)		111,986		24,823		2,370		(858)		138,321
Three Months Ended September 30, 2022
Operating revenues	$	6,938	$	1,180	$	(691)	$	7,427	$	857	$	135	$	(41)	$	8,378
Segment net income (loss)(a)(b)	1,445		95		—		1,540		83		(152)		1		1,472
Nine Months Ended September 30, 2022
Operating revenues	$	16,716	$	2,618	$	(1,391)	$	17,943	$	3,998	$	418	$	(127)	$	22,232
Segment net income (loss)(a)(b)	3,256		265		—		3,521		516		(415)		(11)		3,611
At December 31, 2022
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	144	$	—	$	5,161
Total assets	95,861		13,081		(659)		108,283		24,621		2,665		(678)		134,891

(a)Attributable to Southern Company.

(b)For the traditional electric operating companies, includes pre-tax charges (credits) to income at Georgia Power for the estimated probable loss associated with the construction of Plant Vogtle Units 3 and 4 of $160 million ($120 million after tax) for the three and nine months ended September 30, 2023 and $(70) million ($(52) million after tax) and $(18) million ($(13) million after tax) for the three and nine months ended September 30, 2022, respectively. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.

(c)For Southern Power, includes an $18 million pre-tax loss recovery ($9 million after tax and partnership allocations) for the three and nine months ended September 30, 2023 related to an arbitration interim award and a $16 million pre-tax gain ($12 million after tax) on the sale of spare parts for the nine months ended September 30, 2023. See Note (C) under "General Litigation Matters – Southern Power" for additional information.

(d)For Southern Company Gas, includes a pre-tax charge of approximately $38 million ($28 million after tax) associated with the disallowance of certain capital expenditures at Nicor Gas. See Note (B) under "Southern Company Gas" for additional information.

Products and Services

	Electric Utilities' Revenues
	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2023	$	5,139	$	727	$	301	$	6,167
Three Months Ended September 30, 2022	5,961		1,197		269		7,427
Nine Months Ended September 30, 2023	$	12,597	$	1,930	$	887	$	15,414
Nine Months Ended September 30, 2022	14,363		2,798		782		17,943

	Southern Company Gas' Revenues
	Gas Distribution Operations		Gas Marketing Services		Other		Total
	(in millions)
Three Months Ended September 30, 2023	$	617	$	56	$	16	$	689
Three Months Ended September 30, 2022	748		85		24		857
Nine Months Ended September 30, 2023	$	2,989	$	376	$	52	$	3,417
Nine Months Ended September 30, 2022	3,513		420		65		3,998

Business segment financial data for the three months ended September 30, 2023 and 2022 was as follows:

	Gas Distribution Operations		Gas Pipeline Investments		Gas Marketing Services		Total		All Other		Eliminations		Consolidated
	(in millions)
Three Months Ended September 30, 2023
Operating revenues	$	619	$	8	$	56	$	683	$	8	$	(2)	$	689
Segment net income (loss)	70		24		2		96		(14)		—		82
Nine Months Ended September 30, 2023
Operating revenues	$	3,002	$	24	$	376	$	3,402	$	30	$	(15)	$	3,417
Segment net income(*)	352		73		59		484		(9)		—		475
Total assets at September 30, 2023	22,625		1,542		1,519		25,686		9,795		(10,658)		24,823
Three Months Ended September 30, 2022
Operating revenues	$	751	$	8	$	85	$	844	$	16	$	(3)	$	857
Segment net income (loss)	59		24		(2)		81		2		—		83
Nine Months Ended September 30, 2022
Operating revenues	$	3,533	$	24	$	420	$	3,977	$	43	$	(22)	$	3,998
Segment net income	365		76		65		506		10		—		516
Total assets at December 31, 2022	22,040		1,577		1,616		25,233		8,943		(9,555)		24,621

(*)For gas distribution operations, includes a pre-tax charge of approximately $38 million ($28 million after tax) associated with the disallowance of certain capital expenditures at Nicor Gas. See Note (B) under "Southern Company Gas" for additional information.

Schedule of Financial Data for Products and Services

	Electric Utilities' Revenues
	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2023	$	5,139	$	727	$	301	$	6,167
Three Months Ended September 30, 2022	5,961		1,197		269		7,427
Nine Months Ended September 30, 2023	$	12,597	$	1,930	$	887	$	15,414
Nine Months Ended September 30, 2022	14,363		2,798		782		17,943

	Southern Company Gas' Revenues
	Gas Distribution Operations		Gas Marketing Services		Other		Total
	(in millions)
Three Months Ended September 30, 2023	$	617	$	56	$	16	$	689
Three Months Ended September 30, 2022	748		85		24		857
Nine Months Ended September 30, 2023	$	2,989	$	376	$	52	$	3,417
Nine Months Ended September 30, 2022	3,513		420		65		3,998

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Introduction - Schedule of Goodwill (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Goodwill [Line Items]
Goodwill	$ 5,161	$ 5,161
SOUTHERN Co GAS
Goodwill [Line Items]
Goodwill	5,015	5,015
SOUTHERN Co GAS | Gas distribution operations
Goodwill [Line Items]
Goodwill	4,034	4,034
SOUTHERN Co GAS | Gas marketing services
Goodwill [Line Items]
Goodwill	$ 981	$ 981

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Introduction - Schedule of Other Intangible Assets (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Subject to amortization:
Gross Carrying Amount	$ 669	$ 671
Accumulated Amortization	(367)	(340)
Other Intangible Assets, Net	302	331
Not subject to amortization:
FCC licenses	75	75
Total other intangible assets
Gross Carrying Amount	744	746
Accumulated Amortization	(367)	(340)
Other Intangible Assets, Net	377	406
Customer relationships
Subject to amortization:
Gross Carrying Amount	211	212
Accumulated Amortization	(169)	(162)
Other Intangible Assets, Net	42	50
Total other intangible assets
Accumulated Amortization	(169)	(162)
Trade names
Subject to amortization:
Gross Carrying Amount	63	64
Accumulated Amortization	(50)	(44)
Other Intangible Assets, Net	13	20
Total other intangible assets
Accumulated Amortization	(50)	(44)
PPA fair value adjustments
Subject to amortization:
Gross Carrying Amount	390	390
Accumulated Amortization	(143)	(129)
Other Intangible Assets, Net	247	261
Total other intangible assets
Accumulated Amortization	(143)	(129)
Other
Subject to amortization:
Gross Carrying Amount	5	5
Accumulated Amortization	(5)	(5)
Other Intangible Assets, Net	0	0
Total other intangible assets
Accumulated Amortization	(5)	(5)
SOUTHERN POWER CO
Subject to amortization:
Accumulated Amortization	(143)	(129)
Total other intangible assets
Accumulated Amortization	(143)	(129)
SOUTHERN POWER CO | PPA fair value adjustments
Subject to amortization:
Gross Carrying Amount	390	390
Accumulated Amortization	(143)	(129)
Other Intangible Assets, Net	247	261
Total other intangible assets
Accumulated Amortization	(143)	(129)
SOUTHERN Co GAS
Subject to amortization:
Gross Carrying Amount	182	182
Accumulated Amortization	(163)	(156)
Other Intangible Assets, Net	19	26
Total other intangible assets
Accumulated Amortization	(163)	(156)
Other Intangible Assets, Net	19	26
SOUTHERN Co GAS | Customer relationships
Subject to amortization:
Gross Carrying Amount	156	156
Accumulated Amortization	(143)	(139)
Other Intangible Assets, Net	13	17
Total other intangible assets
Accumulated Amortization	(143)	(139)
SOUTHERN Co GAS | Trade names
Subject to amortization:
Gross Carrying Amount	26	26
Accumulated Amortization	(20)	(17)
Other Intangible Assets, Net	6	9
Total other intangible assets
Accumulated Amortization	$ (20)	$ (17)

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Introduction - Schedule of Amortization of Other Intangible Assets (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 10	$ 11	$ 27	$ 30
Decrease in operating revenues	5	14	5	15
SOUTHERN POWER CO
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	5	5	14	15
SOUTHERN Co GAS
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 3	$ 4	$ 7	$ 9

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Introduction - Schedule of Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022	Sep. 30, 2022	Dec. 31, 2021
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	$ 1,676	$ 1,917
Restricted cash:
Total cash, cash equivalents, and restricted cash	1,890	2,037	$ 2,013	$ 1,829
Other current assets
Restricted cash:
Restricted cash	176	62
Other deferred charges and assets
Restricted cash:
Restricted cash	38	58
ALABAMA POWER CO
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	621	687
Restricted cash:
Total cash, cash equivalents, and restricted cash	729	687	1,458	1,060
ALABAMA POWER CO | Other current assets
Restricted cash:
Restricted cash	108	0
ALABAMA POWER CO | Other deferred charges and assets
Restricted cash:
Restricted cash	0	0
GEORGIA POWER CO
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	173	364
Restricted cash:
Total cash, cash equivalents, and restricted cash	256	480	33	33
GEORGIA POWER CO | Other current assets
Restricted cash:
Restricted cash	48	60
GEORGIA POWER CO | Other deferred charges and assets
Restricted cash:
Restricted cash	35	56
SOUTHERN POWER CO
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	236	131
Restricted cash:
Total cash, cash equivalents, and restricted cash	257	133	231	135
SOUTHERN POWER CO | Other current assets
Restricted cash:
Restricted cash	18	0
SOUTHERN POWER CO | Other deferred charges and assets
Restricted cash:
Restricted cash	3	3
SOUTHERN POWER CO | Proceeds From Issuance Of Solid Waste Disposal Facility Revenue Bonds
Restricted cash:
Restricted cash	18
SOUTHERN POWER CO | Estimated Construction Completion Costs | Deuel Harvest
Restricted cash:
Restricted cash	3	3
SOUTHERN Co GAS
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	397	81
Restricted cash:
Total cash, cash equivalents, and restricted cash	399	83	$ 28	$ 48
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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Introduction - Storm Damage Reserves (Details) - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	Aug. 31, 2023	Sep. 30, 2023
Liability for Unpaid Claims and Claims Adjustment Expense [Roll Forward]
Balance at December 31, 2022		$ 216
Balance at September 30, 2023		16
Accrued Storm Reserve
Liability for Unpaid Claims and Claims Adjustment Expense [Roll Forward]
Accrual		42
Storm Reserve
Liability for Unpaid Claims and Claims Adjustment Expense [Roll Forward]
Weather-related damages		(242)
ALABAMA POWER CO
Liability for Unpaid Claims and Claims Adjustment Expense [Roll Forward]
Balance at December 31, 2022		97
Balance at September 30, 2023		71
ALABAMA POWER CO | Accrued Storm Reserve
Liability for Unpaid Claims and Claims Adjustment Expense [Roll Forward]
Accrual		9
ALABAMA POWER CO | Storm Reserve
Liability for Unpaid Claims and Claims Adjustment Expense [Roll Forward]
Weather-related damages		(35)
GEORGIA POWER CO
Liability for Unpaid Claims and Claims Adjustment Expense [Roll Forward]
Balance at December 31, 2022		83
Balance at September 30, 2023		97
GEORGIA POWER CO | Accrued Storm Reserve
Liability for Unpaid Claims and Claims Adjustment Expense [Roll Forward]
Accrual	$ 110	24
GEORGIA POWER CO | Storm Reserve
Liability for Unpaid Claims and Claims Adjustment Expense [Roll Forward]
Weather-related damages		(204)
MISSISSIPPI POWER CO
Liability for Unpaid Claims and Claims Adjustment Expense [Roll Forward]
Balance at December 31, 2022		36
Balance at September 30, 2023		42
MISSISSIPPI POWER CO | Accrued Storm Reserve
Liability for Unpaid Claims and Claims Adjustment Expense [Roll Forward]
Accrual		9
MISSISSIPPI POWER CO | Storm Reserve
Liability for Unpaid Claims and Claims Adjustment Expense [Roll Forward]
Weather-related damages		$ (3)

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Introduction - Asset Retirement Obligations (Details) - USD ($) $ in Millions	1 Months Ended
	Sep. 30, 2023	Jun. 30, 2023	Mar. 06, 2023
GEORGIA POWER CO
Schedule of Asset Retirement Obligation [Line Items]
Asset retirement obligation, period increase (decrease)	$ 175
ALABAMA POWER CO
Schedule of Asset Retirement Obligation [Line Items]
Asset retirement obligation, period increase (decrease)		$ 15
Plant Vogtle Unit 3
Schedule of Asset Retirement Obligation [Line Items]
Asset retirement obligations			$ 90

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Introduction - Decommissioning Expenses (Details) $ in Millions	1 Months Ended	9 Months Ended
	Jun. 30, 2023	Sep. 30, 2023 USD ($)
Estimated Inflation Rate
Liability for Claims and Claims Adjustment Expense [Line Items]
ARO measurement input	0.045
Estimated Trust Earnings
Liability for Claims and Claims Adjustment Expense [Line Items]
ARO measurement input	0.070
ALABAMA POWER CO
Liability for Claims and Claims Adjustment Expense [Line Items]
Total site study costs		$ 2,048
ALABAMA POWER CO | Plant Farley
Liability for Claims and Claims Adjustment Expense [Line Items]
Decommissioning costs (term)		5 years
Radiated structures | ALABAMA POWER CO
Liability for Claims and Claims Adjustment Expense [Line Items]
Total site study costs		$ 1,402
Spent fuel management | ALABAMA POWER CO
Liability for Claims and Claims Adjustment Expense [Line Items]
Total site study costs		513
Non-radiated structures | ALABAMA POWER CO
Liability for Claims and Claims Adjustment Expense [Line Items]
Total site study costs		$ 133

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Regulatory Matters - Schedule of Cost Recovery Clauses (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
ALABAMA POWER CO | Other regulatory assets, current
Loss Contingencies [Line Items]
Rate CNP Compliance	$ 0	$ 47
Rate CNP PPA	17	18
Retail Energy Cost Recovery	208	102
ALABAMA POWER CO | Other regulatory assets, deferred
Loss Contingencies [Line Items]
Rate CNP PPA	90	102
Retail Energy Cost Recovery	80	520
ALABAMA POWER CO | Other Regulatory Liabilities, Deferred
Loss Contingencies [Line Items]
Rate CNP Compliance	3	0
GEORGIA POWER CO | Receivables – under recovered fuel clause revenues
Loss Contingencies [Line Items]
Fuel Cost Recovery(*)	730	0
GEORGIA POWER CO | Deferred under recovered fuel clause revenues
Loss Contingencies [Line Items]
Fuel Cost Recovery(*)	1,279	2,056
MISSISSIPPI POWER CO | Other regulatory assets, current
Loss Contingencies [Line Items]
Ad Valorem Tax	3	12
MISSISSIPPI POWER CO | Other regulatory assets, deferred
Loss Contingencies [Line Items]
Ad Valorem Tax	11	19
MISSISSIPPI POWER CO | Receivables – customer accounts, net
Loss Contingencies [Line Items]
Fuel Cost Recovery(*)	25	1
SOUTHERN Co GAS
Loss Contingencies [Line Items]
Natural gas cost under recovery	0	108
SOUTHERN Co GAS | Other regulatory assets, current
Loss Contingencies [Line Items]
Natural gas cost under recovery	0	108
SOUTHERN Co GAS | Natural gas cost over recovery
Loss Contingencies [Line Items]
Natural gas cost under recovery	$ 165	$ 0

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Regulatory Matters - APC Certificate of Convenience and Necessity (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022	Dec. 31, 2020
Public Utilities, General Disclosures [Line Items]
Construction work in progress	$ 8,496	$ 10,896
Plant in service, net of depreciation	88,374	82,232
ALABAMA POWER CO
Public Utilities, General Disclosures [Line Items]
Construction work in progress	1,759	1,526
Plant in service, net of depreciation	23,271	$ 23,002
ALABAMA POWER CO | Plant Barry Unit 8
Public Utilities, General Disclosures [Line Items]
Estimated in-service cost			$ 652
Construction work in progress	583
Construction in progress, work in progress amount	578
Plant in service, net of depreciation	$ 5

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Regulatory Matters - APC Excess Accumulated Deferred Income Tax Accounting Order (Details) $ in Millions	Oct. 03, 2023 USD ($)
ALABAMA POWER CO | Subsequent Event
Public Utilities, General Disclosures [Line Items]
Deferred income taxes	$ 24

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Regulatory Matters - APC Rate CNP New Plant (Details) $ in Millions	Mar. 24, 2023 USD ($)
ALABAMA POWER CO
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease) amount	$ 78

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Regulatory Matters - APC Renewable Generation Certificate (Details)	Jun. 14, 2023 MW	Jun. 13, 2023 MW	Apr. 04, 2023 claim MW
Public Utilities, General Disclosures [Line Items]
Renewable generation certificate, number of new solar power purchase agreements (in claims) | claim			2
ALABAMA POWER CO
Public Utilities, General Disclosures [Line Items]
Renewable generation certificate, additional generating capacity procured (in MWs)			160
Renewable generation certificate, generating capacity (in MWs)			490
Renewable generation certificate, authorized generating capacity (in MWs)			500
Renewable generation certificate, additional renewable capacity (in MWs)	2,400
Renewable generation certificate, size of allowable projects (in MWs)	200	80
Renewable generation certificate, annual approval limit (in MWs)	400	160

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Regulatory Matters - APC Reliability Reserve Accounting Matter (Details) - USD ($) $ in Millions	Sep. 30, 2023	Aug. 18, 2023	Dec. 31, 2022
Public Utilities, General Disclosures [Line Items]
Reliability reserve balance	$ 16		$ 216
ALABAMA POWER CO
Public Utilities, General Disclosures [Line Items]
Reliability reserve balance	$ 71		$ 97
Reliability Reserve | ALABAMA POWER CO
Public Utilities, General Disclosures [Line Items]
Reliability reserve balance		$ 166

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Regulatory Matters - GPC Rate Matters (Details) - GEORGIA POWER CO - Subsequent Event $ in Millions	Oct. 02, 2023 USD ($)
Traditional Base
Public Utilities, General Disclosures [Line Items]
Increase (decrease) in tariff	$ 275
Environmental Compliance Cost Recovery, Traditional
Public Utilities, General Disclosures [Line Items]
Increase (decrease) in tariff	(99)
Demand Side-Management
Public Utilities, General Disclosures [Line Items]
Increase (decrease) in tariff	10
Municipal Franchise Fee
Public Utilities, General Disclosures [Line Items]
Increase (decrease) in tariff	$ 5

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Regulatory Matters - GPC Plant Vogtle Unit 3 and Common Facilities Rate Proceeding (Details) - GEORGIA POWER CO - USD ($) $ in Millions				1 Months Ended	9 Months Ended	12 Months Ended
	Aug. 30, 2023	Aug. 01, 2023	May 16, 2023	Nov. 30, 2021	Sep. 30, 2023	Dec. 31, 2022	Dec. 31, 2009	Aug. 31, 2018
Loss Contingencies [Line Items]
Requested rate increase (decrease) amount			$ 1,100
Requested revenues increase (decrease) percentage			54.00%
Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Recovery of construction and capital costs	$ 7,562
Requested recovery of associated retail base items	1,020
Estimated in-service capital cost							$ 4,418
Approved rate increase (decrease)	5,462			$ 2,100
Approved recovery of retail rate items				$ 362
Associated retail rate base items	656
Return on equity reduction, negative impact on earnings					$ 12	$ 300
Requested rate increase (decrease) amount	$ 729
Requested revenues increase (decrease) percentage	5.00%
Percentage of ownership interest required for voting for continuing construction								90.00%
Percentage of costs, disallowed for recovery					6.00%
Plant Vogtle Unit 3
Loss Contingencies [Line Items]
Requested rate increase, annual amount		$ 318
Seventeenth Vogtle Construction Monitoring Report | Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Recovery of construction and capital costs	$ 8,826
Requested recovery of associated retail base items	$ 1,070
Twenty Fourth Vogtle Construction Monitoring Report | Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Cost settlement agreement revised forecast, net of payments					$ 7,300

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Regulatory Matters - GPC Fuel Cost Recovery (Details) $ in Millions	May 16, 2023 USD ($)
Public Utilities, General Disclosures [Line Items]
Under recovered fuel balance to be recovered	$ 2,200
GEORGIA POWER CO
Public Utilities, General Disclosures [Line Items]
Requested revenues increase (decrease) percentage	54.00%
Requested rate increase (decrease) amount	$ 1,100
Under recovered fuel balance to be recovered, period of recovery	3 years
GEORGIA POWER CO | Maximum
Public Utilities, General Disclosures [Line Items]
Approved rate increase, percentage	40.00%
Approved rate increase (decrease)	$ 200

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Regulatory Matters - GPC Integrated Resource Plan (Details) - GEORGIA POWER CO $ in Millions		1 Months Ended	60 Months Ended	61 Months Ended
	Oct. 27, 2023 turbine MW	Aug. 31, 2022 USD ($)	Dec. 31, 2028 MW	Dec. 31, 2028 MW
Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Requested additional generating capacity (in MWs)			750
Subsequent Event
Public Utilities, General Disclosures [Line Items]
Number of turbines | turbine	3
Subsequent Event | Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Requested additional generating capacity (in MWs)				230
Subsequent Event | Maximum
Public Utilities, General Disclosures [Line Items]
Requested additional generating capacity (in MWs)	1,000
Plant Tugalo
Public Utilities, General Disclosures [Line Items]
Planned expenses to modernize plant | $		$ 115
Plant Yates | Subsequent Event | Maximum
Public Utilities, General Disclosures [Line Items]
Requested additional generating capacity (in MWs)	1,400

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Regulatory Matters - GPC Storm Damage Recovery (Details) - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	Aug. 31, 2023	Sep. 30, 2023
Accrued Storm Reserve
Public Utilities, General Disclosures [Line Items]
Accrual		$ 42
GEORGIA POWER CO
Public Utilities, General Disclosures [Line Items]
Weather-related damages		31
Regulatory balance		97
GEORGIA POWER CO | Accrued Storm Reserve
Public Utilities, General Disclosures [Line Items]
Accrual	$ 110	24
ALABAMA POWER CO | Accrued Storm Reserve
Public Utilities, General Disclosures [Line Items]
Accrual		$ 9

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Regulatory Matters - GPC Nuclear Construction (Details) - GEORGIA POWER CO $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2023 USD ($)	Dec. 31, 2012 utility MW	Oct. 06, 2023 pump	Sep. 20, 2023 USD ($)	Aug. 31, 2018
Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Proportionate ownership share	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	$ 3,500
Estimated cost to complete, construction contingency estimate, financing costs, incurred to date	3,400
Construction contingency estimate				$ 43
Monthly AFUDC	$ 25
Percentage of ownership interest required for voting for continuing construction					90.00%
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
Plant Vogtle Unit 4 | Subsequent Event
Loss Contingencies [Line Items]
Number of RPCs | pump			1
Minimum | Plant Vogtle Units 3 And 4 | COVID-19
Loss Contingencies [Line Items]
Loss contingency, estimate of possible loss, loss of productivity, term	3 months
Maximum | Plant Vogtle Units 3 And 4 | Subsequent Event
Loss Contingencies [Line Items]
Number of RPCs | pump			7
Maximum | 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
Maximum | Plant Vogtle Unit 4 | Subsequent Event
Loss Contingencies [Line Items]
Number of RPCs | pump			4

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Regulatory Matters - GPC Nuclear Construction Cost and Schedule (Details) - GEORGIA POWER CO - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12003 Months Ended
	Sep. 30, 2023	Sep. 30, 2023	Dec. 31, 2022
Loss Contingencies [Line Items]
Pre-tax charge to income	$ 160		$ 407
Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Base project capital cost forecast	10,736	$ 10,736
Construction contingency estimate	17	17
Total project capital cost forecast	10,753	10,753
Net investment as of end of the period	(10,495)	(10,495)
Remaining estimate to complete	258	258
Estimated cost to complete, costs not shared with other owners	610	610
Estimated cost to complete, construction monitoring costs approved for recovery	33	33
Pre-tax charge to income			$ 567
Expected capitalized costs		420
Capitalized interest accrued	385	385
Plant Vogtle Units 3 And 4 | Twenty Fifth Vogtle Construction Monitoring Report
Loss Contingencies [Line Items]
Guarantor obligations	$ 1,700	1,700
Customer refund		$ 188

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Regulatory Matters - GPC Amendments to the Vogtle Joint Ownership Agreements (Details) - USD ($) $ in Millions				1 Months Ended	3 Months Ended	9 Months Ended	12003 Months Ended
	Oct. 17, 2023	Oct. 05, 2023	Jan. 11, 2018	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2023	Dec. 31, 2022	Jul. 31, 2022	Jun. 30, 2022	Aug. 31, 2018
Public Utilities, General Disclosures [Line Items]
Agreement with third party, amount of costs over projected forecast to be paid by company				20.00%
GEORGIA POWER CO
Public Utilities, General Disclosures [Line Items]
Pre-tax charge to income					$ 160		$ 407
After tax charge to income					120		304
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO
Public Utilities, General Disclosures [Line Items]
Production tax credits, aggregate purchase price, maximum						$ 300
Preliminary estimated cost to complete					$ 10,753	$ 10,753
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
Estimated cost to complete, starting dollar amount								$ 18,380
Pre-tax charge to income							$ 567
Proportionate ownership share					45.70%	45.70%
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | Subsequent Event
Public Utilities, General Disclosures [Line Items]
Additional construction capital costs	$ 17	$ 308
Remaining share of construction costs, agreement to pay, percentage		66.00%
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | Vogtle Owners | Tender Provision Dispute
Public Utilities, General Disclosures [Line Items]
Estimated cost to complete, starting dollar amount									$ 17,100
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | MEAG Power
Public Utilities, General Disclosures [Line Items]
Payment of power costs				$ 92
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | Oglethorpe Power Corporation | Subsequent Event
Public Utilities, General Disclosures [Line Items]
Payment of power costs		$ 105
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | Dalton Utilities | Subsequent Event
Public Utilities, General Disclosures [Line Items]
Payment of power costs	$ 6
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | Category I
Public Utilities, General Disclosures [Line Items]
Preliminary estimated cost to complete					$ 8,400	$ 8,400
Additional construction capital costs, threshold						$ 800
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | Category II
Public Utilities, General Disclosures [Line Items]
Percentage of construction costs, responsibility to pay						55.70%
Additional construction capital costs						$ 80
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | Category II | Vogtle Owners
Public Utilities, General Disclosures [Line Items]
Percentage of construction costs, responsibility to pay						44.30%
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | Category II | Minimum
Public Utilities, General Disclosures [Line Items]
Additional construction capital costs, threshold						$ 800
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | Category II | Maximum
Public Utilities, General Disclosures [Line Items]
Additional construction capital costs, threshold						$ 1,600
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | Category III
Public Utilities, General Disclosures [Line Items]
Percentage of construction costs, responsibility to pay						65.70%
Additional construction capital costs						$ 100
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | Category III | Vogtle Owners
Public Utilities, General Disclosures [Line Items]
Percentage of construction costs, responsibility to pay						34.30%
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | Category III | Minimum
Public Utilities, General Disclosures [Line Items]
Additional construction capital costs, threshold						$ 1,600
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO | 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 CO $ in Millions							6 Months Ended		9 Months Ended	12 Months Ended
	Jan. 01, 2023 USD ($)	Jan. 01, 2021	Jan. 01, 2020	Jan. 11, 2018 USD ($)	Jan. 01, 2018	Jan. 01, 2016	Jun. 30, 2023 USD ($)	Jun. 30, 2022 USD ($) claim	Sep. 30, 2023 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2009 USD ($)	Jun. 30, 2021 report	Jun. 30, 2018 USD ($)	Dec. 31, 2013
Public Utilities, General Disclosures [Line Items]
Estimated in-service capital cost													$ 4,418
Financing costs collected, net of tax									$ 3,000
Increase (decrease) in tariff	$ 36
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%	10.00%
Public utilities, approved return on equity, monthly percentage increase (decrease)									(0.10%)
Return on equity reduction, negative impact on earnings									$ 12			$ 300
Increase to base capital cost forecast not seeking recovery															$ 700
Twenty Fourth Vogtle Construction Monitoring Report
Public Utilities, General Disclosures [Line Items]
Cost settlement agreement revised forecast, net of payments									7,300
Twenty Fifth Vogtle Construction Monitoring Report
Public Utilities, General Disclosures [Line Items]
Number of approved construction management reports | report														25
Requested capital construction costs									7,900
Guarantor obligations									1,700
Customer refund									$ 188
Twenty Sixth Vogtle Construction Monitoring Report
Public Utilities, General Disclosures [Line Items]
Requested capital construction costs								$ 1,600
Number of additional reports reviewed | claim								3
Twenty Ninth Vogtle Construction Monitoring Report
Public Utilities, General Disclosures [Line Items]
Cost settlement agreement revised forecast, net of payments							$ 10,600
Requested capital construction costs							$ 390
Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Return on equity reduction, negative impact on earnings										$ 60	$ 290

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Regulatory Matters - MPC (Details) $ in Millions					1 Months Ended
	Jul. 31, 2023 USD ($)	May 02, 2023 USD ($)	Apr. 04, 2023 USD ($)	Apr. 03, 2023 USD ($)	Oct. 31, 2023 MW	Jul. 31, 2022 USD ($)
Loss Contingencies [Line Items]
Minimum annual accrual, amount				$ 8
MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Approved rate increase (decrease)			$ 12
MISSISSIPPI POWER CO | Subsequent Event
Loss Contingencies [Line Items]
Approved capacity increase (in MWs) | MW					750
MISSISSIPPI POWER CO | Ad Valorem Tax Adjustment
Loss Contingencies [Line Items]
Requested rate increase (decrease) amount		$ (7)
MISSISSIPPI POWER CO | ECO Plan
Loss Contingencies [Line Items]
Approved rate increase (decrease)			$ 3
MISSISSIPPI POWER CO | Municipal And Rural Associations Tariff
Loss Contingencies [Line Items]
Requested rate increase (decrease) amount	$ 16					$ 23
Customer refund payments	$ 6

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Regulatory Matters - GAS Schedule of Infrastructure Replacement Programs and Capital Projects (Details) - SOUTHERN Co GAS $ in Millions	9 Months Ended
	Sep. 30, 2023 USD ($)
Public Utilities, General Disclosures [Line Items]
Capital expenditures	$ 467
Investing in Illinois
Public Utilities, General Disclosures [Line Items]
Capital expenditures	320
SAVE
Public Utilities, General Disclosures [Line Items]
Capital expenditures	56
System Reinforcement Rider
Public Utilities, General Disclosures [Line Items]
Capital expenditures	84
Pipeline Replacement Program
Public Utilities, General Disclosures [Line Items]
Capital expenditures	$ 7

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Regulatory Matters - GAS Nicor Gas (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended		12 Months Ended
	Sep. 30, 2023	Jun. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2019
Public Utilities, General Disclosures [Line Items]
Total operating revenues	$ (6,980)		$ (8,378)	$ (19,208)	$ (22,232)
Total operating expenses	4,870		$ 6,185	$ 14,589	$ 17,000
Nicor Gas
Public Utilities, General Disclosures [Line Items]
Pre-tax charge to income	38
After-tax charge to income	$ 28
Nicor Gas | Investing in Illinois
Public Utilities, General Disclosures [Line Items]
Capital expenditures disallowed						$ 32
Capital expenditures						$ 415
Total operating revenues		$ 8
Total operating expenses		$ 30

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Regulatory Matters - GAS Atlanta Gas Light (Details) $ in Millions	Jul. 14, 2023 USD ($)
SOUTHERN Co GAS
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease) amount	$ 53

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Regulatory Matters - GAS Virginia Natural Gas (Details) - Virginia Natural Gas - USD ($) $ in Millions	Jun. 07, 2023	Jan. 01, 2023
Public Utilities, General Disclosures [Line Items]
Approved rate increase (decrease)	$ 48
Public utilities, approved return on equity percentage	9.70%
Public utilities, approved equity capital structure percentage	49.06%
Requested rate increase (decrease) amount		$ 69

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Contingencies - General Litigation Matters (Details) $ in Millions	1 Months Ended		3 Months Ended		9 Months Ended		12 Months Ended	16 Months Ended
	Jul. 31, 2023 USD ($)	Mar. 31, 2019 plaintiff	Sep. 30, 2023 USD ($)	Sep. 30, 2022 USD ($)	Sep. 30, 2023 USD ($)	Sep. 30, 2022 USD ($)	Dec. 31, 2018 USD ($) defendant plaintiff	Jan. 31, 2023 claim	Jul. 31, 2021 project
Loss Contingencies [Line Items]
Amount awarded					$ 18.0
Increase in other revenues			$ 6,980.0	$ 8,378.0	19,208.0	$ 22,232.0
Allocation to NCI			10.0	12.0	(68.0)	(55.0)
Other revenues
Loss Contingencies [Line Items]
Increase in other revenues			222.0	178.0	662.0	519.0
GEORGIA POWER CO
Loss Contingencies [Line Items]
Increase in other revenues			3,237.0	3,889.0	7,805.0	9,218.0
GEORGIA POWER CO | Other revenues
Loss Contingencies [Line Items]
Increase in other revenues			172.0	130.0	516.0	403.0
GEORGIA POWER CO | Pending Litigation | Class Action Lawsuit
Loss Contingencies [Line Items]
Complaints filed | claim								8
MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Increase in other revenues			436.0	510.0	1,137.0	1,279.0
MISSISSIPPI POWER CO | Other revenues
Loss Contingencies [Line Items]
Increase in other revenues			10.0	13.0	31.0	34.0
MISSISSIPPI POWER CO | Pending Litigation | Purported Violations of Mississippi Consumer Protection Act
Loss Contingencies [Line Items]
Number of plaintiffs | plaintiff							10
Number of defendants | defendant							3
Number of additional plaintiffs | plaintiff		4
Underpayment of refunds							$ 23.5
SOUTHERN POWER CO
Loss Contingencies [Line Items]
Amount awarded			18.0
Increase in other revenues			653.0	1,180.0	1,686.0	2,618.0
Allocation to NCI			10.0	12.0	(68.0)	(55.0)
SOUTHERN POWER CO | Other revenues
Loss Contingencies [Line Items]
Increase in other revenues			18.0	$ 9.0	$ 46.0	$ 27.0
SOUTHERN POWER CO | Settled Litigation | Southern Power vs First Solar
Loss Contingencies [Line Items]
Number of solar projects | project									5
Proceeds from legal settlements	$ 36.0
Amount awarded	$ 18.0		18.0
Reduction to other operations and maintenance expense			11.0
Allocation to NCI			6.0
SOUTHERN POWER CO | Settled Litigation | Southern Power vs First Solar | Other revenues
Loss Contingencies [Line Items]
Increase in other revenues			$ 7.0

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Contingencies - Environmental Remediation (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
GEORGIA POWER CO
Loss Contingencies [Line Items]
Environmental remediation liability, current and former sites	$ 14	$ 15
SOUTHERN Co GAS
Loss Contingencies [Line Items]
Environmental remediation liability, current and former sites	$ 234	$ 256

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Contingencies - Other Matters (Details) - USD ($) $ in Millions			1 Months Ended		9 Months Ended
	Oct. 05, 2023	Oct. 03, 2023	Aug. 31, 2022	Apr. 30, 2019	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2019	Dec. 31, 2022	Dec. 31, 2017	Dec. 31, 2011
Loss Contingencies [Line Items]
Associated penalties and interest previously paid					$ (67)	$ (119)
Penalties and interest final payment					(1,031)	805
Regulatory asset					16			$ 216
ALABAMA POWER CO
Loss Contingencies [Line Items]
Associated penalties and interest previously paid					(21)	(98)
Penalties and interest final payment					(358)	(22)
Regulatory asset					71			97
ALABAMA POWER CO | AT&T
Loss Contingencies [Line Items]
Potential refund amount owed				$ 87
Refund payment period				6 years
MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Total amount due including penalties and interest			$ 28
Associated penalties and interest previously paid			$ 7		12	36
Penalties and interest final payment					(83)	$ 41
Regulatory asset					$ 42			36
MISSISSIPPI POWER CO | Kemper IGCC
Loss Contingencies [Line Items]
DOE awards									$ 137	$ 270
Government grants received							$ 387
MISSISSIPPI POWER CO | Taxes and Interest
Loss Contingencies [Line Items]
Regulatory asset								$ 3
MISSISSIPPI POWER CO | Subsequent Event
Loss Contingencies [Line Items]
Assessment including penalties and interest		$ 11
Penalties and interest final payment	$ 4

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Revenue from Contracts with Customers and Lease Income - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	$ 7,107	$ 7,116	$ 18,886	$ 19,599
Total operating revenues	6,980	8,378	19,208	22,232
Retail electric revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	5,139	5,961	12,597	14,363
Retail electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	5,534	4,951	13,035	12,477
Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	2,543	2,104	5,717	5,282
Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,845	1,637	4,464	4,202
Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,116	1,183	2,770	2,914
Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	30	27	84	79
Natural Gas
Disaggregation of Revenue [Line Items]
Total operating revenues	689	857	3,417	3,998
Natural gas distribution revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	612	744	2,952	3,490
Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	217	331	1,443	1,821
Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	56	93	370	493
Transportation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	275	259	878	872
Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	4	12	33	60
Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	60	49	228	244
Wholesale electric revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	727	1,197	1,930	2,798
Wholesale electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	569	1,045	1,542	2,364
PPA energy revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	317	812	853	1,739
PPA capacity revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	151	175	490	443
Non-PPA revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	101	58	199	182
Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	62	99	386	458
Gas marketing services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	54	84	358	417
Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	8	15	28	41
Other revenue sources
Disaggregation of Revenue [Line Items]
Other revenues	(127)	1,262	322	2,633
Other revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	330	277	971	810
ALABAMA POWER CO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	2,230	2,128	5,638	5,315
Total operating revenues	2,083	2,444	5,420	6,023
ALABAMA POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	1,860	2,008	4,708	5,015
ALABAMA POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	2,069	1,753	5,104	4,487
ALABAMA POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	969	799	2,277	2,049
ALABAMA POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	599	499	1,493	1,285
ALABAMA POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	498	452	1,324	1,143
ALABAMA POWER CO | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	3	3	10	10
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	107	310	375	655
ALABAMA POWER CO | PPA energy revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	66	187	196	354
ALABAMA POWER CO | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	26	56	130	135
ALABAMA POWER CO | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	15	67	49	166
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 | 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 revenue sources
Disaggregation of Revenue [Line Items]
Other revenues	(147)	316	(218)	708
ALABAMA POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	54	65	159	173
GEORGIA POWER CO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	3,388	3,093	7,754	7,767
Total operating revenues	3,237	3,889	7,805	9,218
GEORGIA POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	2,996	3,703	7,142	8,629
GEORGIA POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	3,177	2,927	7,198	7,274
GEORGIA POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,473	1,212	3,202	2,995
GEORGIA POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,151	1,051	2,733	2,688
GEORGIA POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	528	642	1,195	1,529
GEORGIA POWER CO | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	25	22	68	62
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 operating revenues	69	56	147	186
GEORGIA POWER CO | Wholesale electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	65	56	134	166
GEORGIA POWER CO | PPA energy revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	31	40	66	112
GEORGIA POWER CO | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	13	12	38	35
GEORGIA POWER CO | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	21	4	30	19
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 | 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 revenue sources
Disaggregation of Revenue [Line Items]
Other revenues	(151)	796	51	1,451
GEORGIA POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	146	110	422	327
MISSISSIPPI POWER CO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	440	531	1,123	1,276
Total operating revenues	436	510	1,137	1,279
MISSISSIPPI POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	284	250	747	718
MISSISSIPPI POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	288	271	733	716
MISSISSIPPI POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	101	93	238	238
MISSISSIPPI POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	95	87	238	229
MISSISSIPPI POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	90	89	251	242
MISSISSIPPI POWER CO | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	2	2	6	7
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	142	247	359	526
MISSISSIPPI POWER CO | PPA energy revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	2	4	8	11
MISSISSIPPI POWER CO | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	3	1	36	4
MISSISSIPPI POWER CO | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	137	242	315	511
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 | 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 revenue sources
Disaggregation of Revenue [Line Items]
Other revenues	(4)	(21)	14	3
MISSISSIPPI POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	10	13	31	34
SOUTHERN POWER CO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	480	1,010	1,248	2,157
Total operating revenues	653	1,180	1,686	2,618
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	462	1,001	1,202	2,130
SOUTHERN POWER CO | PPA energy revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	226	591	601	1,285
SOUTHERN POWER CO | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	110	107	289	273
SOUTHERN POWER CO | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	126	303	312	572
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 | 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 revenue sources
Disaggregation of Revenue [Line Items]
Other revenues	173	170	438	461
SOUTHERN POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	18	9	46	27
SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	674	843	3,338	3,948
Total operating revenues	689	857	3,417	3,998
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	612	744	2,952	3,490
SOUTHERN Co GAS | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	217	331	1,443	1,821
SOUTHERN Co GAS | Commercial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	56	93	370	493
SOUTHERN Co GAS | Transportation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	275	259	878	872
SOUTHERN Co GAS | Industrial
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	4	12	33	60
SOUTHERN Co GAS | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	60	49	228	244
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	62	99	386	458
SOUTHERN Co GAS | Gas marketing services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	54	84	358	417
SOUTHERN Co GAS | Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	8	15	28	41
SOUTHERN Co GAS | Other revenue sources
Disaggregation of Revenue [Line Items]
Other revenues	15	14	79	50
SOUTHERN Co GAS | Other revenues
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	$ 0	$ 0	$ 0	$ 0

XML

Revenue from Contracts with Customers and Lease Income - Schedule of Contract Balances (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Disaggregation of Revenue [Line Items]
Accounts Receivable	$ 2,680	$ 3,123
Contract Assets	267	156
Contract Liabilities	62	45
ALABAMA POWER CO
Disaggregation of Revenue [Line Items]
Accounts Receivable	858	696
Contract Assets	6	2
Contract Liabilities	0	4
GEORGIA POWER CO
Disaggregation of Revenue [Line Items]
Accounts Receivable	1,175	922
Contract Assets	146	89
Contract Liabilities	8	9
MISSISSIPPI POWER CO
Disaggregation of Revenue [Line Items]
Accounts Receivable	106	92
Contract Assets	0	0
Contract Liabilities	2	0
SOUTHERN POWER CO
Disaggregation of Revenue [Line Items]
Accounts Receivable	138	237
Contract Assets	0	0
Contract Liabilities	8	1
SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Accounts Receivable	331	1,107
Contract Assets	41	0
Contract Liabilities	$ 0	$ 0

XML

Revenue from Contracts with Customers and Lease Income - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2023	Dec. 31, 2022
Disaggregation of Revenue [Line Items]
Contract liabilities	$ 62	$ 62	$ 45
Contract assets	267	267	156
GEORGIA POWER CO
Disaggregation of Revenue [Line Items]
Contract liabilities	8	8	9
Contract assets	146	146	89
Revenue from contracts with customers recognized	0	0
SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Contract liabilities	0	0	0
Contract assets	41	41	0
Revenue from contracts with customers recognized	0	0
ALABAMA POWER CO
Disaggregation of Revenue [Line Items]
Contract liabilities	0	0	4
Contract assets	6	6	2
Revenue from contracts with customers recognized	0	0
MISSISSIPPI POWER CO
Disaggregation of Revenue [Line Items]
Contract liabilities	2	2	0
Contract assets	0	0	0
Revenue from contracts with customers recognized	0	0
SOUTHERN POWER CO
Disaggregation of Revenue [Line Items]
Contract liabilities	8	8	1
Contract assets	0	0	0
Revenue from contracts with customers recognized	0	$ 0
Retail Customer Fixed Bill Programs | GEORGIA POWER CO
Disaggregation of Revenue [Line Items]
Contract term		1 year
Energy Efficiency Enhancement And Upgrade | SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Contract liabilities	51	$ 51
Unregulated Distributed Generation
Disaggregation of Revenue [Line Items]
Contract liabilities	47	47	32
Contract assets	$ 75	$ 75	$ 65

XML

Revenue from Contracts with Customers and Lease Income - Schedule of Remaining Performance Obligations (Details) $ in Millions	Sep. 30, 2023 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 166
Performance obligation, expected timing of satisfaction	3 months
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	$ 599
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	$ 359
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	$ 318
Performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 319
Performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 2,245
Performance obligation, expected timing of satisfaction
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 10
Performance obligation, expected timing of satisfaction	3 months
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	$ 24
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	$ 8
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	1 year
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 0
Performance obligation, expected timing of satisfaction	1 year
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
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]: 2023-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 23
Performance obligation, expected timing of satisfaction	3 months
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	$ 66
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	$ 34
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	$ 14
Performance obligation, expected timing of satisfaction	1 year
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 14
Performance obligation, expected timing of satisfaction	1 year
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 23
Performance obligation, expected timing of satisfaction
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 84
Performance obligation, expected timing of satisfaction	3 months
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	$ 356
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	$ 302
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	$ 303
Performance obligation, expected timing of satisfaction	1 year
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 310
Performance obligation, expected timing of satisfaction	1 year
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 2,233
Performance obligation, expected timing of satisfaction
SOUTHERN Co GAS | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 4
Performance obligation, expected timing of satisfaction	3 months
SOUTHERN Co GAS | 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	$ 29
Performance obligation, expected timing of satisfaction	1 year
SOUTHERN Co GAS | 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	$ 0
Performance obligation, expected timing of satisfaction	1 year
SOUTHERN Co GAS | 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	1 year
SOUTHERN Co GAS | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 0
Performance obligation, expected timing of satisfaction	1 year
SOUTHERN Co GAS | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 0
Performance obligation, expected timing of satisfaction

XML

Revenue from Contracts with Customers and Lease Income - Schedule of Lease Income (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	$ 6	$ 7	$ 18	$ 19
Lease income - operating leases	36	50	129	149
Variable lease income	134	139	327	355
Total lease income	176	196	474	523
ALABAMA POWER CO
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	0	0	0	0
Lease income - operating leases	3	19	32	58
Variable lease income	0	0	1	1
Total lease income	3	19	33	59
GEORGIA POWER CO
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	0	0	0	0
Lease income - operating leases	7	8	22	24
Variable lease income	0	0	0	0
Total lease income	7	8	22	24
MISSISSIPPI POWER CO
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	4	4	11	11
Lease income - operating leases	0	1	2	1
Variable lease income	0	0	0	0
Total lease income	4	5	13	12
SOUTHERN POWER CO
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	2	3	7	8
Lease income - operating leases	21	21	64	64
Variable lease income	144	145	351	372
Total lease income	167	169	422	444
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	27	27
Variable lease income	0	0	0	0
Total lease income	$ 9	$ 9	$ 27	$ 27

XML

Consolidated Entities and Equity Method Investments - Narrative (Details) $ in Millions	3 Months Ended	9 Months Ended
	Mar. 31, 2023 USD ($)	Sep. 30, 2023 USD ($) investor	Dec. 31, 2022 USD ($)
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries		$ 1,376	$ 1,443
Assets		138,321	134,891
Liabilities		103,017	100,359
Southern Holdings Company
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries		126	112
SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries		0	49
Assets		13,090	13,081
Liabilities		$ 6,247	6,165
Proceeds from sale of equity method investments	$ 50
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		$ 5,800	5,900
Liabilities		400	400
Noncontrolling interests related to other partners' interests		1,100
Variable Interest Entity, Primary Beneficiary | SP Wind | SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Assets		2,200	2,200
Liabilities		184	169
Noncontrolling interests related to other partners' interests		$ 38	39
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		$ 1,700	1,800
Liabilities		200	200
Noncontrolling interests related to other partners' interests		$ 800	$ 800

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Consolidated Entities and Equity Method Investments - Schedule of Equity Method Investments (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Schedule of Equity Method Investments [Line Items]
Investment Balance	$ 1,376	$ 1,443
SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Investment Balance	1,243	1,276
SOUTHERN Co GAS | SNG
Schedule of Equity Method Investments [Line Items]
Investment Balance	1,210	1,243
SOUTHERN Co GAS | Other
Schedule of Equity Method Investments [Line Items]
Investment Balance	$ 33	$ 33

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Consolidated Entities and Equity Method Investments - Schedule of Earnings (Loss) from Equity Method Investments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	$ 32	$ 28	$ 110	$ 109
SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	32	34	104	105
SOUTHERN Co GAS | SNG
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	32	34	104	104
SOUTHERN Co GAS | Other
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	$ 0	$ 0	$ 0	$ 1

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Financing and Leases - Schedule of Credit Arrangements (Details) - USD ($) $ in Millions	Sep. 30, 2023	Aug. 01, 2023	Jul. 31, 2023	Jun. 30, 2023	May 31, 2023	Apr. 30, 2023
Line of Credit Facility [Line Items]
Expires, 2024	$ 280
Expires, 2025	125
Expires, 2026	800
Expires, 2028	6,400
Total	7,605
Unused	7,566
Expires within One Year	280
Southern Company parent
Line of Credit Facility [Line Items]
Expires, 2024	150
Expires, 2025	0
Expires, 2026	0
Expires, 2028	1,850				$ 1,850
Total	2,000			$ 150
Unused	1,998
Expires within One Year	150
ALABAMA POWER CO
Line of Credit Facility [Line Items]
Expires, 2024	0
Expires, 2025	0
Expires, 2026	650
Expires, 2028	700
Total	1,350	$ 650	$ 550
Unused	1,350
Expires within One Year	0
GEORGIA POWER CO
Line of Credit Facility [Line Items]
Expires, 2024	0
Expires, 2025	0
Expires, 2026	0
Expires, 2028	1,750
Total	1,750
Unused	1,726
Expires within One Year	0
MISSISSIPPI POWER CO
Line of Credit Facility [Line Items]
Expires, 2024	0
Expires, 2025	125
Expires, 2026	150
Expires, 2028	0
Total	275				150
Unused	275
Expires within One Year	0
SOUTHERN POWER CO
Line of Credit Facility [Line Items]
Expires, 2024	0
Expires, 2025	0
Expires, 2026	0
Expires, 2028	600				600
Total	600
Unused	589
Expires within One Year	0
SOUTHERN POWER CO | Continuing Letter of Credit Facility A
Line of Credit Facility [Line Items]
Expires, 2025	75
Expires, 2026	100
Unused	9
SOUTHERN POWER CO | Continuing Letter of Credit Facility B
Line of Credit Facility [Line Items]
Unused	16
SOUTHERN Co GAS
Line of Credit Facility [Line Items]
Expires, 2024	100
Expires, 2025	0
Expires, 2026	0
Expires, 2028	1,500
Total	1,600
Unused	1,598
Expires within One Year	100
SEGCO
Line of Credit Facility [Line Items]
Expires, 2024	30
Expires, 2025	0
Expires, 2026	0
Expires, 2028	0
Total	30
Unused	30
Expires within One Year	30
Southern Company and Southern Power
Line of Credit Facility [Line Items]
Expires, 2028	2,450				2,450
Southern Company Gas Capital
Line of Credit Facility [Line Items]
Expires, 2028	800
Nicor Gas
Line of Credit Facility [Line Items]
Expires, 2024	100
Expires, 2028	$ 700
Total					$ 100	$ 250

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Financing and Leases - Narrative (Details) - USD ($) $ in Millions	Sep. 30, 2023	Aug. 01, 2023	Jul. 31, 2023	Jun. 30, 2023	May 31, 2023	Apr. 30, 2023
Debt Instrument [Line Items]
Expires, 2028	$ 6,400
Line of credit facility, maximum borrowing capacity	7,605
Variable rate pollution control revenue bonds outstanding	1,700
Southern Company and Southern Power
Debt Instrument [Line Items]
Expires, 2028	2,450				$ 2,450
Southern Company parent
Debt Instrument [Line Items]
Expires, 2028	1,850				1,850
Line of credit facility, maximum borrowing capacity	2,000			$ 150
SOUTHERN POWER CO
Debt Instrument [Line Items]
Expires, 2028	600				600
Line of credit facility, maximum borrowing capacity	600
MISSISSIPPI POWER CO
Debt Instrument [Line Items]
Expires, 2028	0
Line of credit facility, maximum borrowing capacity	275				150
Variable rate pollution control revenue bonds outstanding	69
Nicor Gas
Debt Instrument [Line Items]
Expires, 2028	700
Line of credit facility, maximum borrowing capacity					$ 100	$ 250
ALABAMA POWER CO
Debt Instrument [Line Items]
Expires, 2028	700
Line of credit facility, maximum borrowing capacity	1,350	$ 650	$ 550
Variable rate pollution control revenue bonds outstanding	818
Fixed rate pollution control revenue bonds outstanding	120
GEORGIA POWER CO
Debt Instrument [Line Items]
Expires, 2028	1,750
Line of credit facility, maximum borrowing capacity	1,750
Variable rate pollution control revenue bonds outstanding	819
Fixed rate pollution control revenue bonds outstanding	$ 325

XML

Financing and Leases - Convertible Senior Notes (Details) - Series 2023A Convertible Senior Notes Due 2025 - Convertible Debt $ / shares in Units, $ in Millions		1 Months Ended
	Feb. 28, 2023 USD ($) $ / shares	Feb. 28, 2023 USD ($) d $ / shares	Mar. 31, 2023 USD ($)
Debt Instrument [Line Items]
Aggregate principal amount | $	$ 1,500	$ 1,500	$ 225
Interest rate	3.875%	3.875%
Conversion ratio		0.0118818
Conversion price (in dollars per share) | $ / shares	$ 84.16	$ 84.16
Redemption price	100.00%
Debt Conversion Terms One
Debt Instrument [Line Items]
Trading day threshold		20
Consecutive trading day threshold		30
Stock price trigger threshold, percentage		130.00%
Debt Conversion Terms Two
Debt Instrument [Line Items]
Trading day threshold		5
Consecutive trading day threshold		10
Stock price trigger threshold, percentage		98.00%

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Financing and Leases - Schedule of Shares Used to Compute Diluted Earnings Per Share (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Debt Disclosure [Abstract]
As reported shares (in shares)	1,092	1,082	1,092	1,070
Effect of stock-based compensation (in shares)	7	6	6	6
Diluted (in shares)	1,099	1,088	1,098	1,076
Antidilutive securities excluded from computation of earnings per share (in shares)	0	0	0	0

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Income Taxes - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Dec. 31, 2023	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Income Tax Contingency [Line Items]
Effective tax (benefit) rate		13.90%	20.00%
ALABAMA POWER CO
Income Tax Contingency [Line Items]
Effective tax (benefit) rate		8.30%	23.70%
GEORGIA POWER CO
Income Tax Contingency [Line Items]
Effective tax (benefit) rate		18.20%	18.50%
Unrecognized tax positions		$ 86.0
MISSISSIPPI POWER CO
Income Tax Contingency [Line Items]
Effective tax (benefit) rate		16.90%	20.10%
SOUTHERN POWER CO
Income Tax Contingency [Line Items]
Effective tax (benefit) rate		14.80%	18.80%
SOUTHERN POWER CO | ITC and PTC carryforwards
Income Tax Contingency [Line Items]
Deferred tax assets		$ 1,000.0		$ 1,100.0
Southern Company parent
Income Tax Contingency [Line Items]
Unrecognized tax positions		$ 167.0		$ 80.0
Southern Company parent | Scenario, Forecast
Income Tax Contingency [Line Items]
Tax position as a result of expiration of statue of limitations	$ 44.0

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Retirement Benefits (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
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	69,000,000	$ 103,000,000	207,000,000	$ 309,000,000
Interest cost	156,000,000	102,000,000	469,000,000	306,000,000
Expected return on plan assets	(307,000,000)	(316,000,000)	(922,000,000)	(949,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain) loss	8,000,000	60,000,000	24,000,000	180,000,000
Net periodic pension income	(74,000,000)	(51,000,000)	(222,000,000)	(154,000,000)
Pension Plans | ALABAMA POWER CO
Pension Plans and Postretirement Plans
Service cost	16,000,000	25,000,000	48,000,000	74,000,000
Interest cost	37,000,000	24,000,000	109,000,000	72,000,000
Expected return on plan assets	(75,000,000)	(77,000,000)	(223,000,000)	(229,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain) loss	2,000,000	16,000,000	7,000,000	47,000,000
Net periodic pension income	(20,000,000)	(12,000,000)	(59,000,000)	(36,000,000)
Pension Plans | GEORGIA POWER CO
Pension Plans and Postretirement Plans
Service cost	17,000,000	26,000,000	51,000,000	78,000,000
Interest cost	48,000,000	31,000,000	143,000,000	92,000,000
Expected return on plan assets	(97,000,000)	(99,000,000)	(289,000,000)	(298,000,000)
Amortization:
Prior service costs	0	0	1,000,000	1,000,000
Regulatory asset	0	0	0	0
Net (gain) loss	4,000,000	18,000,000	10,000,000	55,000,000
Net periodic pension income	(28,000,000)	(24,000,000)	(84,000,000)	(72,000,000)
Pension Plans | MISSISSIPPI POWER CO
Pension Plans and Postretirement Plans
Service cost	2,000,000	5,000,000	8,000,000	13,000,000
Interest cost	7,000,000	5,000,000	21,000,000	14,000,000
Expected return on plan assets	(13,000,000)	(15,000,000)	(41,000,000)	(44,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain) loss	1,000,000	2,000,000	1,000,000	9,000,000
Net periodic pension income	(3,000,000)	(3,000,000)	(11,000,000)	(8,000,000)
Pension Plans | SOUTHERN POWER CO
Pension Plans and Postretirement Plans
Service cost	2,000,000	2,000,000	5,000,000	7,000,000
Interest cost	2,000,000	2,000,000	6,000,000	5,000,000
Expected return on plan assets	(4,000,000)	(4,000,000)	(12,000,000)	(12,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain) loss	0	1,000,000	0	2,000,000
Net periodic pension income	0	1,000,000	(1,000,000)	2,000,000
Pension Plans | SOUTHERN Co GAS
Pension Plans and Postretirement Plans
Service cost	6,000,000	9,000,000	18,000,000	26,000,000
Interest cost	11,000,000	7,000,000	32,000,000	21,000,000
Expected return on plan assets	(22,000,000)	(22,000,000)	(65,000,000)	(68,000,000)
Amortization:
Prior service costs	(1,000,000)	(1,000,000)	(2,000,000)	(2,000,000)
Regulatory asset	4,000,000	3,000,000	11,000,000	11,000,000
Net (gain) loss	(1,000,000)	2,000,000	(3,000,000)	5,000,000
Net periodic pension income	(3,000,000)	(2,000,000)	(9,000,000)	(7,000,000)
Postretirement Benefits
Pension Plans and Postretirement Plans
Service cost	4,000,000	6,000,000	11,000,000	17,000,000
Interest cost	18,000,000	10,000,000	53,000,000	31,000,000
Expected return on plan assets	(21,000,000)	(20,000,000)	(62,000,000)	(60,000,000)
Amortization:
Prior service costs	0	(1,000,000)	1,000,000	(1,000,000)
Regulatory asset	0	0	0	0
Net (gain) loss	(4,000,000)	1,000,000	(10,000,000)	1,000,000
Net periodic pension income	(3,000,000)	(4,000,000)	(7,000,000)	(12,000,000)
Postretirement Benefits | ALABAMA POWER CO
Pension Plans and Postretirement Plans
Service cost	1,000,000	2,000,000	3,000,000	5,000,000
Interest cost	5,000,000	3,000,000	13,000,000	8,000,000
Expected return on plan assets	(9,000,000)	(9,000,000)	(26,000,000)	(25,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain) loss	(1,000,000)	0	(2,000,000)	0
Net periodic pension income	(4,000,000)	(4,000,000)	(12,000,000)	(12,000,000)
Postretirement Benefits | GEORGIA POWER CO
Pension Plans and Postretirement Plans
Service cost	1,000,000	2,000,000	3,000,000	5,000,000
Interest cost	6,000,000	4,000,000	19,000,000	11,000,000
Expected return on plan assets	(7,000,000)	(8,000,000)	(22,000,000)	(21,000,000)
Amortization:
Prior service costs	1,000,000	0	1,000,000	0
Regulatory asset	0	0	0	0
Net (gain) loss	(1,000,000)	0	(3,000,000)	1,000,000
Net periodic pension income	0	(2,000,000)	(2,000,000)	(4,000,000)
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	0	2,000,000	1,000,000
Expected return on plan assets	(1,000,000)	0	(1,000,000)	(1,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain) loss	0	0	0	0
Net periodic pension income	0	1,000,000	1,000,000	1,000,000
Postretirement Benefits | SOUTHERN POWER CO
Pension Plans and Postretirement Plans
Service cost	0	1,000,000	0	1,000,000
Interest cost	0	0	0	0
Expected return on plan assets	0	0	0	0
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain) loss	0	0	0	0
Net periodic pension income	0	1,000,000	0	1,000,000
Postretirement Benefits | SOUTHERN Co GAS
Pension Plans and Postretirement Plans
Service cost	0	0	1,000,000	1,000,000
Interest cost	2,000,000	1,000,000	6,000,000	4,000,000
Expected return on plan assets	(2,000,000)	(2,000,000)	(5,000,000)	(6,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	2,000,000	2,000,000	5,000,000	5,000,000
Net (gain) loss	(1,000,000)	(1,000,000)	(3,000,000)	(2,000,000)
Net periodic pension income	$ 1,000,000	$ 0	$ 4,000,000	$ 2,000,000

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Fair Value Measurements - Schedule of Assets and Liabilities Measured at Fair Value (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Assets:
Derivatives	$ 43	$ 141
Liabilities:
Derivatives	708	617
Other	13
Collateral already posted, assets, aggregate fair value	49
Quoted Prices in Active Markets for Identical Assets (Level 1)
Liabilities:
Other	0
Significant Other Observable Inputs (Level 2)
Liabilities:
Other	13
Significant Unobservable Inputs (Level 3)
Liabilities:
Other	0
ALABAMA POWER CO
Assets:
Derivatives	9	38
Liabilities:
Derivatives	58	15
Collateral already posted, assets, aggregate fair value	0
GEORGIA POWER CO
Assets:
Derivatives	3	21
Liabilities:
Derivatives	72	41
MISSISSIPPI POWER CO
Assets:
Derivatives	7	42
Liabilities:
Derivatives	27	15
SOUTHERN POWER CO
Assets:
Derivatives	4	8
Liabilities:
Derivatives	47	59
Other	13
Collateral already posted, assets, aggregate fair value	18
SOUTHERN POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Liabilities:
Other	0
SOUTHERN POWER CO | Significant Other Observable Inputs (Level 2)
Liabilities:
Other	13
SOUTHERN POWER CO | Significant Unobservable Inputs (Level 3)
Liabilities:
Other	0
SOUTHERN Co GAS
Assets:
Derivatives	20	28
Liabilities:
Derivatives	102	110
Total
Collateral already posted, assets, aggregate fair value	49	$ 41
Fair Value, Measurements, Recurring
Assets:
Cash equivalents and restricted cash	930
Other investments	51
Total	3,288
Liabilities:
Contingent consideration	24
Total	831
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents and restricted cash	919
Other investments	9
Total	1,794
Liabilities:
Contingent consideration	5
Total	39
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents and restricted cash	11
Other investments	34
Total	1,309
Liabilities:
Contingent consideration	0
Total	773
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Cash equivalents and restricted cash	0
Other investments	8
Total	8
Liabilities:
Contingent consideration	19
Total	19
Fair Value, Measurements, Recurring | Net Asset Value as a Practical Expedient (NAV)
Assets:
Total	177
Fair Value, Measurements, Recurring | Energy-related derivatives
Assets:
Derivatives	80
Liabilities:
Derivatives	251
Fair Value, Measurements, Recurring | Energy-related derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	7
Liabilities:
Derivatives	34
Fair Value, Measurements, Recurring | Energy-related derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	73
Liabilities:
Derivatives	217
Fair Value, Measurements, Recurring | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | Interest rate derivatives
Liabilities:
Derivatives	351
Fair Value, Measurements, Recurring | Interest rate derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | Interest rate derivatives | Significant Other Observable Inputs (Level 2)
Liabilities:
Derivatives	351
Fair Value, Measurements, Recurring | Interest rate derivatives | Significant Unobservable Inputs (Level 3)
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | Domestic equity
Assets:
Investments in trusts	888
Fair Value, Measurements, Recurring | Domestic equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	692
Fair Value, Measurements, Recurring | Domestic equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	196
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	285
Fair Value, Measurements, Recurring | Foreign equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	131
Fair Value, Measurements, Recurring | Foreign equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	154
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	337
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	337
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	42
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	42
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	6
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	6
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	368
Fair Value, Measurements, Recurring | Corporate bonds | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Corporate bonds | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	368
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	85
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	85
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	169
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	169
Fair Value, Measurements, Recurring | Cash and cash equivalents
Assets:
Investments in trusts	3
Fair Value, Measurements, Recurring | Cash and cash equivalents | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	3
Fair Value, Measurements, Recurring | Cash and cash equivalents | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Cash and cash equivalents | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Other
Assets:
Investments in trusts	44
Fair Value, Measurements, Recurring | Other | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	33
Fair Value, Measurements, Recurring | Other | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	3
Fair Value, Measurements, Recurring | Other | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Other | Net Asset Value as a Practical Expedient (NAV)
Assets:
Investments in trusts	8
Fair Value, Measurements, Recurring | Foreign currency derivatives
Liabilities:
Derivatives	192
Fair Value, Measurements, Recurring | Foreign currency derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | Foreign currency derivatives | Significant Other Observable Inputs (Level 2)
Liabilities:
Derivatives	192
Fair Value, Measurements, Recurring | Foreign currency derivatives | Significant Unobservable Inputs (Level 3)
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO
Assets:
Cash equivalents and restricted cash	500
Other investments	34
Total	1,728
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents and restricted cash	489
Other investments	0
Total	1,034
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents and restricted cash	11
Other investments	34
Total	517
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Unobservable Inputs (Level 3)
Assets:
Cash equivalents and restricted cash	0
Other investments	0
Total	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Net Asset Value as a Practical Expedient (NAV)
Assets:
Total	177
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Energy-related derivatives
Assets:
Derivatives	26
Liabilities:
Derivatives	75
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	26
Liabilities:
Derivatives	75
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	592
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Domestic equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	404
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Domestic equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	188
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	131
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Foreign equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	131
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	20
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	20
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	215
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Corporate bonds | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Corporate bonds | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	215
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Corporate bonds | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Mortgage and asset backed securities
Assets:
Investments in trusts	22
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Mortgage and asset backed securities | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Mortgage and asset backed securities | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	22
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Mortgage and asset backed securities | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Private equity
Assets:
Investments in trusts	169
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	169
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Other
Assets:
Investments in trusts	18
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Other | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	10
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 | ALABAMA POWER CO | Other | Net Asset Value as a Practical Expedient (NAV)
Assets:
Investments in trusts	8
Fair Value, Measurements, Recurring | GEORGIA POWER CO
Assets:
Total	1,056
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Total	311
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Total	745
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	14
Liabilities:
Derivatives	83
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	14
Liabilities:
Derivatives	83
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	289
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Domestic equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	288
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Domestic equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	1
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Domestic equity | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Foreign equity
Assets:
Investments in trusts	153
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Foreign equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Foreign equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	153
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Foreign equity | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | U.S. Treasury and government agency securities
Assets:
Investments in trusts	317
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	317
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	41
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	41
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	153
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	153
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	63
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	63
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	26
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	3
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 and restricted cash	3
Total	27
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents and restricted cash	3
Total	3
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents and restricted cash	0
Total	24
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3)
Assets:
Cash equivalents and restricted cash	0
Total	0
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Energy-related derivatives
Assets:
Derivatives	24
Liabilities:
Derivatives	44
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	24
Liabilities:
Derivatives	44
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN POWER CO
Assets:
Cash equivalents and restricted cash	23
Total	28
Liabilities:
Contingent consideration	24
Total	85
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents and restricted cash	23
Total	23
Liabilities:
Contingent consideration	5
Total	5
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents and restricted cash	0
Total	5
Liabilities:
Contingent consideration	0
Total	61
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Significant Unobservable Inputs (Level 3)
Assets:
Cash equivalents and restricted cash	0
Total	0
Liabilities:
Contingent consideration	19
Total	19
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Energy-related derivatives
Assets:
Derivatives	5
Liabilities:
Derivatives	6
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Energy-related derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Energy-related derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	5
Liabilities:
Derivatives	6
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Foreign currency derivatives
Liabilities:
Derivatives	42
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Foreign currency derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Foreign currency derivatives | Significant Other Observable Inputs (Level 2)
Liabilities:
Derivatives	42
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Foreign currency derivatives | Significant Unobservable Inputs (Level 3)
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS
Assets:
Cash equivalents and restricted cash	294
Total	322
Liabilities:
Total	142
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents and restricted cash	294
Total	304
Liabilities:
Total	34
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents and restricted cash	0
Total	18
Liabilities:
Total	108
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3)
Assets:
Cash equivalents and restricted cash	0
Total	0
Liabilities:
Total	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Energy-related derivatives
Assets:
Derivatives	11
Liabilities:
Derivatives	43
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Energy-related derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	7
Liabilities:
Derivatives	34
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Energy-related derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	4
Liabilities:
Derivatives	9
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Interest rate derivatives
Liabilities:
Derivatives	99
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Interest rate derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Interest rate derivatives | Significant Other Observable Inputs (Level 2)
Liabilities:
Derivatives	99
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Interest rate derivatives | Significant Unobservable Inputs (Level 3)
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Domestic equity
Assets:
Non-qualified deferred compensation trusts	7
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	7
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	1
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	1
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	6
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	6
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Pooled funds – fixed income | Significant Unobservable Inputs (Level 3)
Assets:
Non-qualified deferred compensation trusts	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Cash equivalents
Assets:
Non-qualified deferred compensation trusts	3
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Cash equivalents | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Non-qualified deferred compensation trusts	3
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Cash equivalents | Significant Other Observable Inputs (Level 2)
Assets:
Non-qualified deferred compensation trusts	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Cash equivalents | Significant Unobservable Inputs (Level 3)
Assets:
Non-qualified deferred compensation trusts	$ 0

XML

Fair Value Measurements - Schedule of Increase (Decrease) In Fair Value Of Funds (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	$ (4)	$ (106)	$ 211	$ (486)
ALABAMA POWER CO
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	(36)	(53)	54	(245)
GEORGIA POWER CO
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	$ 32	$ (53)	$ 157	$ (241)

XML

Fair Value Measurements - Narrative (Details) - ALABAMA POWER CO - Private equity $ in Millions	Sep. 30, 2023 USD ($)
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair value	$ 177
Unfunded commitments	$ 72

XML

Fair Value Measurements - Schedule of Financial Instruments for which Carrying Amount did not Equal Fair Value (Details) $ in Billions	Sep. 30, 2023 USD ($)
Long-term debt, including securities due within one year:
Carrying amount	$ 58.8
Fair value	50.8
ALABAMA POWER CO
Long-term debt, including securities due within one year:
Carrying amount	11.2
Fair value	9.4
GEORGIA POWER CO
Long-term debt, including securities due within one year:
Carrying amount	15.8
Fair value	13.4
MISSISSIPPI POWER CO
Long-term debt, including securities due within one year:
Carrying amount	1.6
Fair value	1.3
SOUTHERN POWER CO
Long-term debt, including securities due within one year:
Carrying amount	2.7
Fair value	2.4
SOUTHERN Co GAS
Long-term debt, including securities due within one year:
Carrying amount	8.1
Fair value	$ 6.5

XML

Derivatives - Schedule of Energy-Related Derivatives (Details) - Energy-related, Natural Gas MMBTU in Millions	Sep. 30, 2023 MMBTU
Energy-related derivative contracts
Net Purchased mmBtu	422.0
ALABAMA POWER CO
Energy-related derivative contracts
Net Purchased mmBtu	109.0
GEORGIA POWER CO
Energy-related derivative contracts
Net Purchased mmBtu	104.0
MISSISSIPPI POWER CO
Energy-related derivative contracts
Net Purchased mmBtu	80.0
SOUTHERN POWER CO
Energy-related derivative contracts
Net Purchased mmBtu	8.0
SOUTHERN Co GAS
Energy-related derivative contracts
Net Purchased mmBtu	121.0
SOUTHERN Co GAS | Energy-related derivatives not designated as hedging instruments | Long
Energy-related derivative contracts
Derivative nonmonetary notional amount net long short position volume	135.5
SOUTHERN Co GAS | Energy-related derivatives not designated as hedging instruments | Short
Energy-related derivative contracts
Derivative nonmonetary notional amount net long short position volume	14.2

XML

Derivatives - Narrative (Details) MMBTU in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023 USD ($)	Sep. 30, 2022 USD ($)	Sep. 30, 2023 USD ($) MMBTU	Sep. 30, 2022 USD ($)	Sep. 30, 2024 USD ($)	Dec. 31, 2022 USD ($)
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU			14
Gain (Loss) Recognized in OCI on Derivatives	$ 5,000,000	$ 2,000,000	$ (45,000,000)	$ (32,000,000)
Collateral already posted, assets, aggregate fair value	49,000,000		49,000,000
Derivatives	708,000,000		708,000,000			$ 617,000,000
Scenario, Forecast
Derivative [Line Items]
Energy-related derivative hedge gain (loss) to be reclassified within twelve months					$ 30,000,000
Interest rate derivatives
Derivative [Line Items]
Derivatives	78,000,000		78,000,000
Interest rate derivatives | Scenario, Forecast
Derivative [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months					19,000,000
Interest rate derivatives | Cash Flow Hedging
Derivative [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	(3,000,000)	6,000,000	(12,000,000)	36,000,000
Interest rate derivatives | Cash Flow Hedging | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	(22,000,000)	(7,000,000)	(31,000,000)	(19,000,000)
Interest rate derivatives | Fair Value Hedging | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	(47,000,000)	(102,000,000)	(50,000,000)	(300,000,000)
Energy-related derivatives | Energy-related derivatives not designated as hedging instruments
Derivative [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	7,000,000	1,000,000	36,000,000	(17,000,000)
Energy-related derivatives | Cash Flow Hedging
Derivative [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	(4,000,000)	11,000,000	$ (55,000,000)	51,000,000
SOUTHERN POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU			3
Gain (Loss) Recognized in OCI on Derivatives	(15,000,000)	(46,000,000)	$ (20,000,000)	(141,000,000)
Collateral already posted, assets, aggregate fair value	18,000,000		18,000,000
Derivatives	47,000,000		47,000,000			59,000,000
SOUTHERN POWER CO | Scenario, Forecast
Derivative [Line Items]
Foreign currency cash flow hedge gain (loss to be reclassified					10,000,000
SOUTHERN POWER CO | Interest rate derivatives
Derivative [Line Items]
Derivatives	20,000,000		20,000,000
SOUTHERN POWER CO | Interest rate derivatives | Scenario, Forecast
Derivative [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months					0
SOUTHERN POWER CO | Energy-related derivatives | Energy-related derivatives not designated as hedging instruments
Derivative [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	0	0	0	0
SOUTHERN POWER CO | Energy-related derivatives | Cash Flow Hedging
Derivative [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	0	(11,000,000)	(14,000,000)	(4,000,000)
SOUTHERN Co GAS
Derivative [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	(8,000,000)	27,000,000	(41,000,000)	55,000,000
Collateral already posted, assets, aggregate fair value	49,000,000		49,000,000			41,000,000
Derivatives	102,000,000		102,000,000			110,000,000
SOUTHERN Co GAS | Scenario, Forecast
Derivative [Line Items]
Energy-related derivative hedge gain (loss) to be reclassified within twelve months					25,000,000
SOUTHERN Co GAS | Interest rate derivatives | Scenario, Forecast
Derivative [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months					0
SOUTHERN Co GAS | Interest rate derivatives | Cash Flow Hedging
Derivative [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	(4,000,000)	5,000,000	0	0
SOUTHERN Co GAS | Interest rate derivatives | Cash Flow Hedging | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	(18,000,000)	(2,000,000)	(18,000,000)	(3,000,000)
SOUTHERN Co GAS | Interest rate derivatives | Fair Value Hedging | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	(11,000,000)	(30,000,000)	(14,000,000)	(87,000,000)
SOUTHERN Co GAS | Energy-related derivatives | Cash Flow Hedging
Derivative [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	(4,000,000)	22,000,000	$ (41,000,000)	55,000,000
ALABAMA POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU			4
Collateral already posted, assets, aggregate fair value	0		$ 0
Derivatives	58,000,000		58,000,000			15,000,000
ALABAMA POWER CO | Interest rate derivatives | Scenario, Forecast
Derivative [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months					0
ALABAMA POWER CO | Energy-related derivatives | Energy-related derivatives not designated as hedging instruments
Derivative [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	0	0	0	0
ALABAMA POWER CO | Energy-related derivatives | Cash Flow Hedging
Derivative [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	0	0	$ 0	0
GEORGIA POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU			5
Derivatives	72,000,000		$ 72,000,000			41,000,000
GEORGIA POWER CO | Interest rate derivatives | Scenario, Forecast
Derivative [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months					0
GEORGIA POWER CO | Interest rate derivatives | Cash Flow Hedging
Derivative [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	0	0	(3,000,000)	31,000,000
GEORGIA POWER CO | Energy-related derivatives | Energy-related derivatives not designated as hedging instruments
Derivative [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	0	0	$ 0	0
MISSISSIPPI POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU			2
Derivatives	27,000,000		$ 27,000,000			$ 15,000,000
MISSISSIPPI POWER CO | Interest rate derivatives | Scenario, Forecast
Derivative [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months					$ 0
MISSISSIPPI POWER CO | Energy-related derivatives | Energy-related derivatives not designated as hedging instruments
Derivative [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	0	0	0	0
MISSISSIPPI POWER CO | Energy-related derivatives | Cash Flow Hedging
Derivative [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	0	0	0	0
Registrants | Derivative Counterparties
Derivative [Line Items]
Collateral already posted, assets, aggregate fair value	0		0
Traditional Electric Operating Companies | Interest rate derivatives | Cash Flow Hedging | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	0	0	0	0
Traditional Electric Operating Companies | Interest rate derivatives | Fair Value Hedging | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	$ 0	$ 0	$ 0	$ 0

XML

Derivatives - Schedule of Interest Rate Derivatives (Details) - Interest rate derivatives $ in Millions	9 Months Ended
	Sep. 30, 2023 USD ($)
Derivative [Line Items]
Notional Amount	$ 1,900
Fair Value Gain (Loss)	(351)
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)	$ (56)
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)	$ (196)
SOUTHERN Co GAS | Fair Value Hedges of Existing Debt
Derivative [Line Items]
Fair Value Gain (Loss)	(99)
SOUTHERN Co GAS | Fair Value Hedges of Existing Debt | January 2031
Derivative [Line Items]
Notional Amount	$ 500
Interest Rate Received	1.75%
Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Southern Company parent | Fair Value Hedges of Existing Debt | March 2028
Derivative [Line Items]
Weighted Average Interest Rate Paid	0.80%
Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Southern Company parent | Fair Value Hedges of Existing Debt | April 2030
Derivative [Line Items]
Weighted Average Interest Rate Paid	2.48%
Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | SOUTHERN Co GAS | Fair Value Hedges of Existing Debt | January 2031
Derivative [Line Items]
Weighted Average Interest Rate Paid	0.49%

XML

Derivatives - Schedule of Foreign Currency Derivatives (Details) - 9 months ended Sep. 30, 2023 - Foreign currency derivatives € in Millions, $ in Millions	USD ($)	EUR (€)
Derivative [Line Items]
Pay Notional	$ 2,040
Receive Notional | €		€ 1,750
Fair Value Gain (Loss)	(192)
Cash Flow Hedges of Forecasted Debt | SOUTHERN POWER CO
Derivative [Line Items]
Pay Notional	$ 564
Pay Rate	3.78%
Receive Notional | €		500
Receive Rate	1.85%
Fair Value Gain (Loss)	$ (42)
Fair Value Hedges of Existing Debt | Southern Company parent
Derivative [Line Items]
Pay Notional	$ 1,476
Pay Rate	3.39%
Receive Notional | €		€ 1,250
Receive Rate	1.88%
Fair Value Gain (Loss)	$ (150)

XML

Derivatives - Schedule of Derivative Category and Balance Sheet Location (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	$ 80	$ 211
Derivative asset, Gross amounts offset	(37)	(70)
Derivative asset, net amounts recognized in the balance sheets	43	141
Derivative liability, gross amount recognized	794	728
Derivative liability, Gross amounts offset	(86)	(111)
Derivative liability, net amounts recognized in the balance sheets	708	617
Collateral already posted, assets, aggregate fair value	49
Interest rate derivatives
Derivatives, Fair Value [Line Items]
Derivative liability, net amounts recognized in the balance sheets	78
Energy-related derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	6	15
Derivative liability, gross amount recognized	10	14
Energy-related derivatives not designated as hedging instruments | Energy-related derivatives | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	5	13
Energy-related derivatives not designated as hedging instruments | Energy-related derivatives | Liabilities from risk management activities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	8	13
Energy-related derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	1	2
Energy-related derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	2	1
Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	70	175
Derivative liability, gross amount recognized	211	165
Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related 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	34	123
Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Liabilities from risk management activities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	134	121
Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related 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	36	52
Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related 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	77	44
Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	4	21
Derivative liability, gross amount recognized	573	549
Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related 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	0	3
Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Liabilities from risk management activities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	28	27
Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	4	6
Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related 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	4
Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related 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	0	12
Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related 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	80	62
Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related 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 | Energy-related 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	271	240
Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related 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	0	0
Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Liabilities from risk management activities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	35	34
Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related 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	0	0
Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related 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	157	182
ALABAMA POWER CO
Derivatives, Fair Value [Line Items]
Derivative asset, Gross amounts offset	(17)	(24)
Derivative asset, net amounts recognized in the balance sheets	9	38
Derivative liability, Gross amounts offset	(17)	(24)
Derivative liability, net amounts recognized in the balance sheets	58	15
Collateral already posted, assets, aggregate fair value	0
ALABAMA POWER CO | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	26	62
Derivative liability, gross amount recognized	75	39
ALABAMA POWER CO | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	15	42
ALABAMA POWER CO | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	46	21
ALABAMA POWER CO | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related 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	11	20
ALABAMA POWER CO | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related 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	29	18
GEORGIA POWER CO
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	14	42
Derivative asset, Gross amounts offset	(11)	(21)
Derivative asset, net amounts recognized in the balance sheets	3	21
Derivative liability, gross amount recognized	83	62
Derivative liability, Gross amounts offset	(11)	(21)
Derivative liability, net amounts recognized in the balance sheets	72	41
GEORGIA POWER CO | Energy-related derivatives not designated as hedging instruments | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	0	0
GEORGIA POWER CO | Energy-related derivatives not designated as hedging instruments | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	0	1
GEORGIA POWER CO | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	14	42
Derivative liability, gross amount recognized	83	61
GEORGIA POWER CO | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related 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	4	36
GEORGIA POWER CO | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	57	43
GEORGIA POWER CO | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related 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	10	6
GEORGIA POWER CO | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related 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	26	18
MISSISSIPPI POWER CO
Derivatives, Fair Value [Line Items]
Derivative asset, Gross amounts offset	(17)	(17)
Derivative asset, net amounts recognized in the balance sheets	7	42
Derivative liability, Gross amounts offset	(17)	(17)
Derivative liability, net amounts recognized in the balance sheets	27	15
MISSISSIPPI POWER CO | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	24	59
Derivative liability, gross amount recognized	44	32
MISSISSIPPI POWER CO | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related 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	33
MISSISSIPPI POWER CO | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	22	24
MISSISSIPPI POWER CO | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related 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	26
MISSISSIPPI POWER CO | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related 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	22	8
SOUTHERN POWER CO
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	5	8
Derivative asset, Gross amounts offset	(1)	0
Derivative asset, net amounts recognized in the balance sheets	4	8
Derivative liability, gross amount recognized	48	59
Derivative liability, Gross amounts offset	(1)	0
Derivative liability, net amounts recognized in the balance sheets	47	59
Collateral already posted, assets, aggregate fair value	18
SOUTHERN POWER CO | Interest rate derivatives
Derivatives, Fair Value [Line Items]
Derivative liability, net amounts recognized in the balance sheets	20
SOUTHERN POWER CO | Energy-related derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	1	3
Derivative liability, gross amount recognized	1	0
SOUTHERN POWER CO | Energy-related derivatives not designated as hedging instruments | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	1	2
SOUTHERN POWER CO | Energy-related derivatives not designated as hedging instruments | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	1	0
SOUTHERN POWER CO | Energy-related 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	1
SOUTHERN POWER CO | Energy-related 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	0
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	4	5
Derivative liability, gross amount recognized	47	59
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	0	0
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	5	12
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	4	5
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	0	0
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	0	0
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	11	11
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related 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	0	0
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related 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	31	36
SOUTHERN Co GAS
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	11	28
Derivative asset, Gross amounts offset	9	0
Derivative asset, net amounts recognized in the balance sheets	20	28
Derivative liability, gross amount recognized	142	151
Derivative liability, Gross amounts offset	(40)	(41)
Derivative liability, net amounts recognized in the balance sheets	102	110
Collateral already posted, assets, aggregate fair value	49	41
SOUTHERN Co GAS | Energy-related derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	5	12
Derivative liability, gross amount recognized	9	13
SOUTHERN Co GAS | Energy-related derivatives not designated as hedging instruments | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	4	11
SOUTHERN Co GAS | Energy-related derivatives not designated as hedging instruments | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	7	12
SOUTHERN Co GAS | Energy-related derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	1	1
SOUTHERN Co GAS | Energy-related derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	2	1
SOUTHERN Co GAS | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	6	12
SOUTHERN Co GAS | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	9	33
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	0	4
Derivative liability, gross amount recognized	124	105
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	0	3
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	23	15
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related 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	0	1
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related 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	4
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	0	0
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	21	14
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivative asset, gross amount recognized	0	0
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Energy-related 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	$ 78	$ 72

XML

Derivatives - Schedule of Pre-tax Effects of Unrealized Derivative Gains (Losses) (Details) - Energy-related derivatives - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	$ (132)	$ 9
Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(113)	(71)
Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(48)	(23)
Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	23	72
Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	6	31
ALABAMA POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(49)	23
ALABAMA POWER CO | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(39)	(8)
ALABAMA POWER CO | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(19)	(7)
ALABAMA POWER CO | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	8	29
ALABAMA POWER CO | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	1	9
GEORGIA POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(69)	(19)
GEORGIA POWER CO | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(54)	(26)
GEORGIA POWER CO | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(18)	(14)
GEORGIA POWER CO | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	1	19
GEORGIA POWER CO | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	2	2
MISSISSIPPI POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(20)	27
MISSISSIPPI POWER CO | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(16)	(13)
MISSISSIPPI POWER CO | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(11)	(2)
MISSISSIPPI POWER CO | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	4	22
MISSISSIPPI POWER CO | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	3	20
SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	6	(22)
SOUTHERN Co GAS | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(4)	(24)
SOUTHERN Co GAS | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	0	0
SOUTHERN Co GAS | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	10	2
SOUTHERN Co GAS | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	$ 0	$ 0

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Derivatives - Schedule of Pre-Tax Effects of Hedging on AOCI (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	$ 5	$ 2	$ (45)	$ (32)
Cash Flow Hedging | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	(4)	11	(55)	51
Cash Flow Hedging | Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	(3)	6	(12)	36
Cash Flow Hedging | Foreign currency derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	(15)	(35)	(6)	(137)
Fair Value Hedging | Foreign currency derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	27	20	28	18
GEORGIA POWER CO | Cash Flow Hedging | Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	0	0	(3)	31
SOUTHERN POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	(15)	(46)	(20)	(141)
SOUTHERN POWER CO | Cash Flow Hedging | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	0	(11)	(14)	(4)
SOUTHERN POWER CO | Cash Flow Hedging | Foreign currency derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	(15)	(35)	(6)	(137)
SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	(8)	27	(41)	55
SOUTHERN Co GAS | Cash Flow Hedging | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	(4)	22	(41)	55
SOUTHERN Co GAS | Cash Flow Hedging | Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	$ (4)	$ 5	$ 0	$ 0

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Derivatives - Schedule of Pre-Tax Effects of Cash Flow and Fair Value Hedging on Income (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Derivative [Line Items]
Depreciation and amortization	$ 1,143	$ 922	$ 3,365	$ 2,728
Total interest expense, net of amounts capitalized	(620)	(511)	(1,812)	(1,461)
Total other income (expense), net	141	132	428	414
Utilities Operating Expense, Maintenance and Operations	1,424	1,527	4,352	4,568
Natural gas
Derivative [Line Items]
Total cost of sales	102	294	1,199	1,840
Other Income (Expense)
Derivative [Line Items]
Amount excluded from effectiveness testing recognized in earnings	(27)	(21)	(28)	(17)
Cash Flow Hedging | Energy-related derivatives | Cost of Sales
Derivative [Line Items]
Gain (loss) on hedges	(4)	9	(32)	28
Cash Flow Hedging | Energy-related derivatives | Depreciation and Amortization
Derivative [Line Items]
Gain (loss) on hedges	(5)	(1)	(18)	5
Cash Flow Hedging | Energy-related derivatives | Operating Expense
Derivative [Line Items]
Gain (loss) on hedges	(1)	0	(2)	0
Cash Flow Hedging | Interest rate derivatives | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	(22)	(7)	(31)	(19)
Cash Flow Hedging | Foreign currency derivatives | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	(3)	(3)	(8)	(16)
Cash Flow Hedging | Foreign currency derivatives | Other Income (Expense)
Derivative [Line Items]
Gain (loss) on hedges	(14)	(32)	(4)	(129)
Fair Value Hedging | Interest rate derivatives | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	(47)	(102)	(50)	(300)
Fair Value Hedging | Foreign currency derivatives | Other Income (Expense)
Derivative [Line Items]
Gain (loss) on hedges	(7)	(59)	19	(180)
SOUTHERN POWER CO
Derivative [Line Items]
Depreciation and amortization	130	133	380	384
Total interest expense, net of amounts capitalized	(32)	(32)	(98)	(105)
Total other income (expense), net	4	3	8	5
Utilities Operating Expense, Maintenance and Operations	104	113	327	332
SOUTHERN POWER CO | Cash Flow Hedging | Energy-related derivatives | Depreciation and Amortization
Derivative [Line Items]
Gain (loss) on hedges	(5)	(1)	(18)	5
SOUTHERN POWER CO | Cash Flow Hedging | Foreign currency derivatives | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	(3)	(3)	(8)	(16)
SOUTHERN POWER CO | Cash Flow Hedging | Foreign currency derivatives | Other Income (Expense)
Derivative [Line Items]
Gain (loss) on hedges	(14)	(32)	(4)	(129)
SOUTHERN Co GAS
Derivative [Line Items]
Depreciation and amortization	145	140	429	414
Total interest expense, net of amounts capitalized	(77)	(65)	(226)	(187)
Total other income (expense), net	19	15	50	47
Utilities Operating Expense, Maintenance and Operations	264	252	879	824
SOUTHERN Co GAS | Natural gas
Derivative [Line Items]
Total cost of sales	102	294	1,199	1,840
SOUTHERN Co GAS | Cash Flow Hedging | Energy-related derivatives | Cost of Sales
Derivative [Line Items]
Gain (loss) on hedges	(4)	9	(32)	28
SOUTHERN Co GAS | Cash Flow Hedging | Energy-related derivatives | Operating Expense
Derivative [Line Items]
Gain (loss) on hedges	(1)	0	(2)	0
SOUTHERN Co GAS | Cash Flow Hedging | Interest rate derivatives | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	(18)	(2)	(18)	(3)
SOUTHERN Co GAS | Fair Value Hedging | Interest rate derivatives | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	(11)	(30)	(14)	(87)
Traditional Electric Operating Companies | Cash Flow Hedging | Interest rate derivatives | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	0	0	0	0
Traditional Electric Operating Companies | Fair Value Hedging | Interest rate derivatives | Interest Expense
Derivative [Line Items]
Gain (loss) on hedges	$ 0	$ 0	$ 0	$ 0

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Derivatives - Schedule of Cumulative Basis Adjustments for Fair Value Hedges (Details) - Fair Value Hedging - Long-term debt - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Derivative [Line Items]
Carrying Amount of the Hedged Item	$ (2,873)	$ (2,927)
Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item	328	282
SOUTHERN Co GAS
Derivative [Line Items]
Carrying Amount of the Hedged Item	(402)	(415)
Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item	$ 95	$ 81

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Derivatives - Schedule of Pre-tax Effect of Interest Rate and Energy Related Derivatives on Income (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Weather Derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	$ 0	$ 0	$ 14	$ 0
Energy-related derivatives not designated as hedging instruments | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	7	1	36	(17)
Energy-related derivatives not designated as hedging instruments | Energy-related derivatives | Natural gas revenues
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	0	3	0	(10)
Energy-related derivatives not designated as hedging instruments | Energy-related derivatives | Cost of natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	$ 7	$ (2)	$ 36	$ (7)

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Acquisitions and Dispositions - Southern Power (Details) - SOUTHERN POWER CO $ in Millions	9 Months Ended
	Sep. 30, 2023 USD ($) MW
Millers Branch Solar Development
Business Acquisition [Line Items]
Approximate nameplate capacity	200
Ownership percentage by parent	100.00%
Life output of plant (in years)	20 years
South Cheyenne Solar Facility
Business Acquisition [Line Items]
Approximate nameplate capacity	150
Ownership percentage by parent	10000.00%
Life output of plant (in years)	20 years
South Cheyenne Solar Facility and Millers Branch Solar Development
Business Acquisition [Line Items]
Payments to Acquire Businesses and Interest in Affiliates | $	$ 193
Maximum | Millers Branch Solar Development
Business Acquisition [Line Items]
Approximate nameplate capacity	300

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Acquisitions and Dispositions - Southern Company Gas (Details) $ in Millions	Sep. 22, 2023 USD ($)
Disposal Group, Disposed of by Sale | California Natural Gas | Natural Gas Storage Facility | SOUTHERN Co GAS
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Immaterial loss on sale	$ 0

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Segment and Related Information - Narrative (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023 USD ($) state	Sep. 30, 2022 USD ($)	Sep. 30, 2023 USD ($) state segment	Sep. 30, 2022 USD ($)
Segment Reporting Information [Line Items]
Number of states in which entity operates | state	3		3
Operating revenues	$ 7,107	$ 7,116	$ 18,886	$ 19,599
SOUTHERN POWER CO
Segment Reporting Information [Line Items]
Operating revenues	$ 480	1,010	$ 1,248	2,157
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Number of states in which entity operates | state	4		4
Operating revenues	$ 674	843	$ 3,338	3,948
Number of reportable segments | segment			3
SOUTHERN Co GAS | Southern Natural Gas Company, LLC
Segment Reporting Information [Line Items]
Ownership percentage, equity method investment	50.00%		50.00%
SOUTHERN Co GAS | Dalton Pipeline
Segment Reporting Information [Line Items]
Ownership percentage, equity method investment	50.00%		50.00%
Traditional Electric Operating Companies | Wholesale revenues, affiliates | SOUTHERN POWER CO
Segment Reporting Information [Line Items]
Operating revenues	$ 156	336	$ 406	673
Traditional Electric Operating Companies | Natural Gas | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	$ 0	$ 0	$ 0	$ 0

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Segment and Related Information - Schedule of Financial Data for Business Segments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Segment Reporting Information [Line Items]
Operating revenues	$ 6,980	$ 8,378	$ 19,208	$ 22,232
Net income	1,422	1,472	3,121	3,611
Goodwill	5,161		5,161		$ 5,161
Total assets	138,321		138,321		134,891
Amount awarded			18
SOUTHERN POWER CO
Segment Reporting Information [Line Items]
Operating revenues	653	1,180	1,686	2,618
Net income	100	95	288	265
Total assets	13,090		13,090		13,081
Amount awarded	18
After tax amount awarded	9		9
SOUTHERN POWER CO | Disposal Group, Disposed of by Sale | Spare Parts
Segment Reporting Information [Line Items]
Gain (loss) on sale			16
Gain (loss) on sale, after tax			12
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	689	857	3,417	3,998
Net income	82	83	475	516
Goodwill	5,015		5,015		5,015
Total assets	24,823		24,823		24,621
GEORGIA POWER CO
Segment Reporting Information [Line Items]
Operating revenues	3,237	3,889	7,805	9,218
Total assets	56,149		56,149		53,163
GEORGIA POWER CO | Disposal Group, Disposed of by Sale | Spare Parts
Segment Reporting Information [Line Items]
Gain (loss) on sale		(70)		(18)
Gain (loss) on sale, after tax		(52)		(13)
Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	6,167	7,427	15,414	17,943
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	689	857	3,417	3,998
Operating Segments | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	683	844	3,402	3,977
Net income	96	81	484	506
Total assets	25,686		25,686		25,233
Operating Segments | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	6,167	7,427	15,414	17,943
Net income	1,519	1,540	3,140	3,521
Goodwill	2		2		2
Total assets	111,986		111,986		108,283
Operating Segments | Traditional Electric Operating Companies
Segment Reporting Information [Line Items]
Operating revenues	5,674	6,938	14,145	16,716
Net income	1,419	1,445	2,852	3,256
Goodwill	0		0		0
Total assets	99,464		99,464		95,861
Operating Segments | SOUTHERN POWER CO
Segment Reporting Information [Line Items]
Operating revenues	653	1,180	1,686	2,618
Net income	100	95	288	265
Goodwill	2		2		2
Total assets	13,090		13,090		13,081
Operating Segments | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	689	857	3,417	3,998
Net income	82	83	475	516
Goodwill	5,015		5,015		5,015
Total assets	24,823		24,823		24,621
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues	154	135	499	418
Net income	(179)	(152)	(490)	(415)
Goodwill	144		144		144
Total assets	2,370		2,370		2,665
Operating Segments | All Other | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	8	16	30	43
Net income	(14)	2	(9)	10
Total assets	9,795		9,795		8,943
Eliminations
Segment Reporting Information [Line Items]
Operating revenues	(30)	(41)	(122)	(127)
Net income	0	1	(4)	(11)
Goodwill	0		0		0
Total assets	(858)		(858)		(678)
Eliminations | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	(2)	(3)	(15)	(22)
Net income	0	0	0	0
Total assets	(10,658)		(10,658)		(9,555)
Eliminations | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	(160)	(691)	(417)	(1,391)
Net income	0	$ 0	0	$ 0
Goodwill	0		0		0
Total assets	$ (568)		$ (568)		$ (659)

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Segment and Related Information - Schedule of Financial Data for Products and Services (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Concentration Risk [Line Items]
Operating revenues	$ 6,980	$ 8,378	$ 19,208	$ 22,232
Electric Utilities
Concentration Risk [Line Items]
Operating revenues	6,167	7,427	15,414	17,943
Southern Company Gas' Revenues
Concentration Risk [Line Items]
Operating revenues	689	857	3,417	3,998
Retail electric revenues
Concentration Risk [Line Items]
Operating revenues	5,139	5,961	12,597	14,363
Retail electric revenues | Electric Utilities
Concentration Risk [Line Items]
Operating revenues	5,139	5,961	12,597	14,363
Wholesale electric revenues
Concentration Risk [Line Items]
Operating revenues	727	1,197	1,930	2,798
Wholesale electric revenues | Electric Utilities
Concentration Risk [Line Items]
Operating revenues	727	1,197	1,930	2,798
Other Revenue | Electric Utilities
Concentration Risk [Line Items]
Operating revenues	301	269	887	782
Other electric revenues
Concentration Risk [Line Items]
Operating revenues	203	185	602	554
Natural Gas
Concentration Risk [Line Items]
Operating revenues	689	857	3,417	3,998
Gas Distribution Operations | Southern Company Gas' Revenues
Concentration Risk [Line Items]
Operating revenues	617	748	2,989	3,513
Gas marketing services | Southern Company Gas' Revenues
Concentration Risk [Line Items]
Operating revenues	56	85	376	420
Other | Southern Company Gas' Revenues
Concentration Risk [Line Items]
Operating revenues	16	24	52	65
Other revenues
Concentration Risk [Line Items]
Operating revenues	$ 222	$ 178	$ 662	$ 519

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Segment and Related Information - Schedule of Business Segment Financial Data (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Segment Reporting Information [Line Items]
Total operating revenues	$ 6,980	$ 8,378	$ 19,208	$ 22,232
Net income after dividends on preferred stock	1,422	1,472	3,121	3,611
Total assets	138,321		138,321		$ 134,891
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Total operating revenues	689	857	3,417	3,998
Net income after dividends on preferred stock	82	83	475	516
Total assets	24,823		24,823		24,621
SOUTHERN POWER CO
Segment Reporting Information [Line Items]
Total operating revenues	653	1,180	1,686	2,618
Net income after dividends on preferred stock	100	95	288	265
Total assets	13,090		13,090		13,081
Operating Segments | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Total operating revenues	683	844	3,402	3,977
Net income after dividends on preferred stock	96	81	484	506
Total assets	25,686		25,686		25,233
Operating Segments | Gas distribution operations | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Total operating revenues	619	751	3,002	3,533
Net income after dividends on preferred stock	70	59	352	365
Total assets	22,625		22,625		22,040
Operating Segments | Gas Pipeline Investments | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Total operating revenues	8	8	24	24
Net income after dividends on preferred stock	24	24	73	76
Total assets	1,542		1,542		1,577
Operating Segments | Gas marketing services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Total operating revenues	56	85	376	420
Net income after dividends on preferred stock	2	(2)	59	65
Total assets	1,519		1,519		1,616
Operating Segments | All Other
Segment Reporting Information [Line Items]
Total operating revenues	154	135	499	418
Net income after dividends on preferred stock	(179)	(152)	(490)	(415)
Total assets	2,370		2,370		2,665
Operating Segments | All Other | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Total operating revenues	8	16	30	43
Net income after dividends on preferred stock	(14)	2	(9)	10
Total assets	9,795		9,795		8,943
Eliminations
Segment Reporting Information [Line Items]
Total operating revenues	(30)	(41)	(122)	(127)
Net income after dividends on preferred stock	0	1	(4)	(11)
Total assets	(858)		(858)		(678)
Eliminations | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Total operating revenues	(2)	(3)	(15)	(22)
Net income after dividends on preferred stock	0	$ 0	0	$ 0
Total assets	$ (10,658)		$ (10,658)		$ (9,555)