UNITED STATES
 SECURITIES AND EXCHANGE COMMISSION
 Washington, D.C. 20549
 FORM 10-K
 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
 OF THE SECURITIES EXCHANGE ACT OF 1934
 For the Fiscal Year Ended December 31, 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
 58-0690070

 (A Delaware Corporation)
 30 Ivan Allen Jr. Boulevard, N.W.
 Atlanta, Georgia 30308
 ( 404) 506-5000

 1-3164
 63-0004250

 (An Alabama Corporation)
 600 North 18th Street
 Birmingham, Alabama 35203
 ( 205) 257-1000

 1-6468
 58-0257110

 (A Georgia Corporation)
 241 Ralph McGill Boulevard, N.E.
 Atlanta, Georgia 30308
 ( 404) 506-6526

 001-11229
 64-0205820

 (A Mississippi Corporation)
 2992 West Beach Boulevard
 Gulfport, Mississippi 39501
 ( 228) 864-1211

 001-37803
 58-2598670

 (A Delaware Corporation)
 30 Ivan Allen Jr. Boulevard, N.W.
 Atlanta, Georgia 30308
 ( 404) 506-5000

 1-14174
 58-2210952

 (A Georgia Corporation)
 Ten Peachtree Place, N.E.
 Atlanta, Georgia 30309
 ( 404) 584-4000

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

 Title of Each Class
 Trading
Symbol(s)
 Name of Each Exchange
on Which Registered

 Common Stock, par value $5 per share
 SO
 New York Stock Exchange

 (NYSE)

 Series 2017B 5.25% Junior Subordinated Notes due 2077
 SOJC
 NYSE

 Series 2020A 4.95% Junior Subordinated Notes due 2080
 SOJD
 NYSE

 Series 2020C 4.20% Junior Subordinated Notes due 2060
 SOJE
 NYSE

 Series 2021B 1.875% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2081
 SO 81
 NYSE

 Series 2017A 5.00% Junior Subordinated Notes due 2077
 GPJA
 NYSE

 Series 2016B 1.850% Senior Notes due 2026
 SO/26A
 NYSE

 Securities registered pursuant to Section 12(g) of the Act: None
 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

 Yes
 No

 X

 X

 X

 X

 X

 X

 Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No x (Response applicable to all registrants.)
 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 x 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 x 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.

 Large Accelerated Filer
 Accelerated
Filer
 Non-accelerated Filer
 Smaller
Reporting
 Emerging Growth Company

 X

 X

 X

 X

 X

 X

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

 Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.

 Yes
 No

 X

 X

 X

 X

 X

 X

 If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
 Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to § 240.10D-1(b).
 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No x (Response applicable to all registrants.)
 Aggregate market value of The Southern Company's common stock held by non-affiliates of The Southern Company at June 30, 2023: $ 76.6 billion. All of the common stock of the other registrants is held by The Southern Company. A description of each registrant's common stock follows:

 Description of
 Shares Outstanding at January 31, 2024

 Par Value $5 Per Share
 1,091,015,113

 Par Value $40 Per Share
 30,537,500

 Without Par Value
 9,261,500

 Without Par Value
 1,121,000

 Par Value $0.01 Per Share
 1,000

 Par Value $0.01 Per Share

 Documents incorporated by reference: specified portions of The Southern Company's Definitive Proxy Statement on Schedule 14A relating to the 2024 Annual Meeting of Stockholders are incorporated by reference into PART III.
 Each of Alabama Power Company, Georgia Power Company, Mississippi Power Company, Southern Power Company, and Southern Company Gas meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format specified in General Instructions I(2)(b), (c), and (d) of Form 10-K.
 This combined Form 10-K 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.

 Page

 Definitions

 ii

 Cautionary Statement Regarding Forward-Looking Information

 vi

 Item 1

 Business

 I- 1

 The Southern Company System

 I- 1

 Construction Programs

 I- 4

 Financing Programs

 I- 4

 Fuel Supply

 I- 5

 Territory Served by the Southern Company System

 I- 6

 Competition

 I- 8

 Seasonality

 I- 9

 Regulation

 I- 9

 Rate Matters

 I- 11

 Human Capital

 I- 13

 Item 1A

 Risk Factors

 I- 15

 Item 1B

 Unresolved Staff Comments

 I- 26

 Item 1C

 Cybersecurity

 I- 26

 Item 2

 Properties

 I- 29

 Item 3

 Legal Proceedings

 I- 36

 Item 4

 Mine Safety Disclosures

 I- 36

 Information about Our Executive Officers – Southern Company

 I- 37

 Item 5

 Market for Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 II- 1

 Item 6

 Reserved

 II-1

 Item 7

 Management's Discussion and Analysis of Financial Condition and Results of Operations

 II- 2

 Item 7A

 Quantitative and Qualitative Disclosures about Market Risk

 II- 2

 Item 8

 Financial Statements and Supplementary Data

 II- 72

 Item 9

 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 II- 255

 Item 9A

 Controls and Procedures

 II- 255

 Item 9B

 Other Information

 II- 255

 Item 9C

 Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

 II-255

 Item 10

 Directors, Executive Officers and Corporate Governance

 III- 1

 Item 11

 Executive Compensation

 III- 1

 Item 12

 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 III- 1

 Item 13

 Certain Relationships and Related Transactions, and Director Independence

 III- 1

 Item 14

 Principal Accountant Fees and Services

 III- 2

 Item 15

 Exhibits and Financial Statement Schedules

 IV- 1

 Item 16

 Form 10-K Summary

 IV- 1

 Signatures

 i

 DEFINITIONS

 When used in this Form 10-K, the following terms will have the meanings indicated.
 Term
 Meaning

 ARP
 Georgia Power's Alternate Rate Plans approved by the Georgia PSC; 2019 ARP for the years 2020 through 2022 and 2022 ARP for the years 2023 through 2025

 AFUDC
 Allowance for funds used during construction

 AMEA
 Alabama Municipal Electric Authority

 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

 AOCI
 Accumulated other comprehensive income

 ARO
 Asset retirement obligation

 ASU
 Accounting Standards Update

 Atlanta Gas Light Company, a wholly-owned subsidiary of Southern Company Gas

 Bcf
 Billion cubic feet

 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

 CCN
 Certificate of convenience and necessity

 CCR
 Coal combustion residuals

 CCR Rule
 Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015

 Chattanooga Gas Company, a wholly-owned subsidiary of Southern Company Gas

 Clean Air Act
 Clean Air Act Amendments of 1990

 CO2

 Carbon dioxide

 COD
 Commercial operation date

 Contractor Settlement Agreement
 The December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the Vogtle 3 and 4 Agreement

 Cooperative Energy
 Electric 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

 CPCN
 Certificate of public convenience and necessity

 CWIP

 Dalton
 City of Dalton, Georgia, an incorporated municipality in the State of Georgia, acting by and through its Board of Water, Light, and Sinking Fund Commissioners

 Dalton Pipeline
 A pipeline facility in Georgia in which Southern Company Gas has a 50% undivided ownership interest

 DOE
 U.S. Department of Energy

 ECCR
 Georgia Power's Environmental Compliance Cost Recovery tariff

 ECO Plan
 Mississippi Power's environmental compliance overview plan

 ELG
 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

 EMC
 Electric membership corporation

 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

 ii

 DEFINITIONS
 (continued)

 Term
 Meaning

 FFB
 Federal Financing Bank

 FFB Credit Facilities
 Note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities

 Fitch
 Fitch Ratings, Inc.

 FP&L
 Florida Power and Light Company

 GAAP
 U.S. generally accepted accounting principles

 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 FP&L, with FP&L 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

 IBEW
 International Brotherhood of Electrical Workers

 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

 Internal Revenue Code
 Internal Revenue Code of 1986, as amended

 IPP
 Independent power producer

 IRA

 Inflation Reduction Act

 IRP
 Integrated resource plan

 IRS
 Internal Revenue Service

 ITAAC
 Inspections, Tests, Analyses, and Acceptance Criteria, standards established by the NRC

 ITC
 Investment tax credit

 JEA
 Jacksonville Electric Authority

 KW
 Kilowatt

 KWH
 Kilowatt-hour

 LIBOR
 London Interbank Offered Rate

 LIFO
 Last-in, first-out

 LNG
 Liquefied natural gas

 LTSA
 Long-term service agreement

 Marketers
 Marketers selling retail natural gas in Georgia and certificated by the Georgia PSC

 MEAG Power
 Municipal Electric Authority of Georgia

 mmBtu
 Million British thermal units

 Moody's
 Moody's Investors Service, Inc.

 MPUS
 Mississippi Public Utilities Staff

 MRA
 Municipal and Rural Associations

 MW
 Megawatt

 natural gas distribution utilities
 Southern Company Gas' natural gas distribution utilities (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas)

 NCCR
 Georgia Power's Nuclear Construction Cost Recovery tariff

 iii

 DEFINITIONS
 (continued)

 Term
 Meaning

 NDR
 Alabama Power's Natural Disaster Reserve

 NextEra Energy
 NextEra Energy, Inc.

 Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas

 NOX

 Nitrogen oxide

 NRC
 U.S. Nuclear Regulatory Commission

 NYMEX
 New York Mercantile Exchange, Inc.

 NYSE
 New York Stock Exchange

 OCI

 OPC
 Oglethorpe Power Corporation (an EMC)

 OTC
 Over-the-counter

 PennEast Pipeline
 PennEast Pipeline Company, LLC, a joint venture in which Southern Company Gas has a 20% ownership interest

 PEP
 Mississippi Power's Performance Evaluation Plan

 PowerSecure
 PowerSecure, Inc., a wholly-owned subsidiary of Southern Company

 PowerSouth
 PowerSouth Energy Cooperative

 PPA
 Power purchase agreements, as well as, for Southern Power, contracts for differences that provide the owner of a renewable facility a certain fixed price for the electricity sold to the grid

 PSC
 Public Service Commission

 PTC
 Production tax credit

 Rate CNP
 Alabama Power's Rate Certificated New Plant, consisting of Rate CNP New Plant, Rate CNP Compliance, Rate CNP PPA, and Rate CNP Depreciation

 Rate ECR
 Alabama Power's Rate Energy Cost Recovery

 Rate NDR
 Alabama Power's Rate Natural Disaster Reserve

 Rate RSE
 Alabama Power's Rate Stabilization and Equalization

 Registrants
 Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power Company, and Southern Company Gas

 ROE
 Return on equity

 S&P
 S&P Global Ratings, a division of S&P Global Inc.

 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

 SEPA
 Southeastern Power Administration

 Sequent
 Sequent Energy Management, L.P. and Sequent Energy Canada Corp., wholly-owned subsidiaries of Southern Company Gas through June 30, 2021

 SERC
 SERC Reliability Corporation

 SNG
 Southern Natural Gas Company, L.L.C., a pipeline system in which Southern Company Gas has a 50% ownership interest

 SO2

 Sulfur dioxide

 SOFR
 Secured Overnight Financing Rate

 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

 iv

 DEFINITIONS
 (continued)

 Term
 Meaning

 Southern Company system
 Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas, SEGCO, Southern Nuclear, SCS, Southern Linc, 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 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

 Tax Reform Legislation
 The Tax Cuts and Jobs Act, which became effective on January 1, 2018

 Toshiba
 Toshiba Corporation, the parent company of Westinghouse

 traditional electric operating companies
 Alabama Power, Georgia Power, and Mississippi Power

 VCM
 Vogtle Construction Monitoring

 VIE
 Variable interest entity

 Virginia Commission
 Virginia State Corporation Commission

 Virginia Natural Gas, Inc., a wholly-owned subsidiary of Southern Company Gas

 Vogtle 3 and 4 Agreement
 Agreement entered into with the EPC Contractor in 2008 by Georgia Power, acting for itself and as agent for the Vogtle Owners, and rejected in bankruptcy in July 2017, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4

 Vogtle Owners
 Georgia Power, 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

 Westinghouse
 Westinghouse Electric Company LLC

 Williams Field Services Group

 Williams Field Services Group, LLC

 v

 CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
 This Annual Report on Form 10-K contains forward-looking statements. Forward-looking statements include, among other things, statements concerning regulated rates, the strategic goals for the business, customer and sales growth, economic conditions, including inflation, cost recovery and other rate actions, projected equity ratios, current and proposed environmental regulations and related compliance plans and estimated expenditures, GHG emissions reduction goals, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plans, postretirement benefit plans, and nuclear decommissioning trust fund contributions, 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, federal and state income tax benefits, estimated sales and purchases under power sale and purchase agreements, 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 several 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; challenges related to 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 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 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 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, including PSC approvals and FERC 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;
 vi

 CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
 (continued)
 • in the event Georgia Power becomes obligated to provide funding to MEAG Power with respect to the portion of MEAG Power's ownership interest in Plant Vogtle Units 3 and 4 involving JEA, any inability of Georgia Power to receive repayment of such funding;
 • the ability to construct facilities in accordance with the requirements of permits and licenses (including satisfaction of NRC requirements), to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;
 • investment performance of the employee and retiree benefit plans and nuclear decommissioning trust funds;
 • advances in technology, including the pace and extent of development of low- to no-carbon energy and battery energy storage technologies and negative carbon concepts;
 • performance of counterparties under ongoing renewable energy partnerships and development agreements;
 • state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions 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 geopolitical conflicts, 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 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 filed by the Registrants from time to time with the SEC.
 The Registrants expressly disclaim any obligation to update any forward-looking statements.
 vii

 Item 1. BUSINESS
 Southern Company is a holding company that owns all of the outstanding common stock of three traditional electric operating companies, Southern Power Company, and Southern Company Gas.
 • The traditional electric operating companies – Alabama Power, Georgia Power, and Mississippi Power – are each operating public utility companies providing electric service to retail customers in three Southeastern states in addition to wholesale customers in the Southeast.
 • Southern Power Company is also an operating public utility company. The term "Southern Power" when used herein refers to Southern Power Company and its subsidiaries, while the term "Southern Power Company" when used herein refers only to the Southern Power parent company. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market.
 • Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas in four states – Illinois, Georgia, Virginia, and Tennessee – through the natural gas distribution utilities. Southern Company Gas is also involved in several other businesses that are complementary to the distribution of natural gas.
 Southern Company also owns SCS, Southern Linc, Southern Holdings, Southern Nuclear, PowerSecure, and other direct and indirect subsidiaries. SCS, the system service company, has contracted with Southern Company, each of the Subsidiary Registrants, Southern Nuclear, SEGCO, and other subsidiaries to furnish, at direct or allocated cost and upon request, the following services: general executive and advisory, general and design engineering, operations, purchasing, accounting, finance, treasury, legal, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, cellular tower space, and other services with respect to business and operations, construction management, and Southern Company power pool transactions. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services through its subsidiary, Southern Telecom, Inc. Southern Linc's system covers approximately 122,000 square miles in the Southeast. Southern Holdings is an intermediate holding company subsidiary, which invests in various projects. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants and is currently managing construction and start-up of Plant Vogtle Unit 4, which is co-owned by Georgia Power. PowerSecure develops distributed energy and resilience solutions and deploys microgrids for commercial, industrial, governmental, and utility customers.
 See "The Southern Company System" herein for additional information. Also see Note 15 to the financial statements in Item 8 herein for information regarding recent acquisition and disposition activity. Segment information for Southern Company and Southern Company Gas is included in Note 16 to the financial statements in Item 8 herein. 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.
 The Registrants' Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports are made available on Southern Company's website, free of charge, as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. Southern Company's internet address is www.southerncompany.com.

 The Southern Company System
 Traditional Electric Operating Companies
 The traditional electric operating companies are vertically integrated utilities that own generation, transmission, and distribution facilities. See PROPERTIES in Item 2 herein for additional information on the traditional electric operating companies' generating facilities. Each company's transmission facilities are connected to the respective company's own generating plants and other sources of power (including certain generating plants owned by Southern Power) and are interconnected with the transmission facilities of the other traditional electric operating companies and SEGCO. For information on the State of Georgia's integrated transmission system, see "Territory Served by the Southern Company System – Traditional Electric Operating Companies and Southern Power" herein.
 Agreements in effect with principal neighboring utility systems provide for capacity and energy transactions that may be entered into for reasons related to reliability or economics. Additionally, the traditional electric operating companies have entered into various reliability agreements with certain neighboring utilities, each of which provides for the establishment and periodic review of principles and procedures for planning and operation of generation and transmission facilities, maintenance
 I-1

 schedules, load retention programs, emergency operations, and other matters affecting the reliability of bulk power supply. The traditional electric operating companies have joined with other utilities in the Southeast to form the SERC to augment further the reliability and adequacy of bulk power supply. Through the SERC, the traditional electric operating companies are represented at the North American Electric Reliability Corporation. In November 2022, the Southeast Energy Exchange Market (SEEM) began service. SEEM, whose members include the traditional electric operating companies and many of the other electric service providers in the Southeast, is an extension of the existing bilateral market where participants use an automated, intra-hour energy exchange to buy and sell power close to the time the energy is consumed, utilizing available unreserved transmission. On July 14, 2023, the U.S. Court of Appeals for the District of Columbia Circuit vacated certain FERC orders related to SEEM and remanded the proceeding to the FERC. The ultimate outcome of this matter cannot be determined at this time.
 The utility assets of the traditional electric operating companies and certain utility assets of Southern Power Company are operated as a single integrated electric system, or Southern Company power pool, pursuant to the IIC. Activities under the IIC are administered by SCS, which acts as agent for the traditional electric operating companies and Southern Power Company. The fundamental purpose of the Southern Company power pool is to provide for the coordinated operation of the electric facilities in an effort to achieve the maximum possible economies consistent with the highest practicable reliability of service. Subject to service requirements and other operating limitations, system resources are committed and controlled through the application of centralized economic dispatch. Under the IIC, each traditional electric operating company and Southern Power Company retains its lowest cost energy resources for the benefit of its own customers and delivers any excess energy to the Southern Company power pool for use in serving customers of other traditional electric operating companies or Southern Power Company or for sale by the Southern Company power pool to third parties. The IIC provides for the recovery of specified costs associated with the affiliated operations thereunder, as well as the proportionate sharing of costs and revenues resulting from Southern Company power pool transactions with third parties.
 Southern Power and Southern Linc have secured from the traditional electric operating companies certain services which are furnished in compliance with FERC regulations.
 Alabama Power and Georgia Power each have agreements with Southern Nuclear to operate the Southern Company system's existing nuclear plants, Plants Farley, Hatch, and Vogtle (Units 1, 2, and 3). In addition, Georgia Power has an agreement with Southern Nuclear to develop, license, construct, and operate Plant Vogtle Unit 4. See "Regulation – Nuclear Regulation" herein for additional information.

 Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates (under authority from the FERC) in the wholesale market. Southern Power seeks opportunities to execute its strategy to create value through various transactions including acquisitions, dispositions, and sales of partnership interests, development and construction of new generating facilities, and entry into PPAs, including contracts for differences that provide the owner of a renewable facility a certain fixed price for electricity sold to the grid, primarily with investor-owned utilities, IPPs, municipalities, electric cooperatives, and other load-serving entities, as well as commercial and industrial customers. The electricity from the natural gas generating facilities owned by Southern Power is primarily sold under long-term, fixed-price capacity PPAs both with unaffiliated wholesale purchasers as well as with the traditional electric operating companies. Southern Power has attempted to insulate itself from significant fuel supply, fuel transportation, and electric transmission risks by generally making such risks the responsibility of the counterparties to its PPAs. However, Southern Power's future earnings will depend on the parameters of the wholesale market and the efficient operation of its wholesale generating assets, as well as Southern Power's ability to execute its growth strategy and to develop and construct generating facilities. Southern Power's business activities are not subject to traditional state regulation like the traditional electric operating companies, but the majority of its business activities are subject to regulation by the FERC. For additional information on Southern Power's business activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Business Activities" in Item 7 herein.
 Southern Power Company directly owns and manages generation assets primarily in the Southeast, which are included in the Southern Company power pool, and has various subsidiaries whose generation assets are not included in the Southern Company power pool. These subsidiaries were created to own, operate, and pursue power generation facilities, either wholly or in partnership with various third parties. At December 31, 2023, Southern Power's generation fleet, which is owned in part with various partners, totaled 12,498 MWs of nameplate capacity in commercial operation (including 5,118 MWs of nameplate capacity owned by its subsidiaries). See "Traditional Electric Operating Companies" herein for additional information on the Southern Company power pool.
 A majority of Southern Power's partnerships in renewable facilities allow for the sharing of cash distributions and tax benefits at differing percentages, with Southern Power being the controlling partner and thus consolidating the assets and operations of
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 the partnerships. At December 31, 2023, Southern Power had eight tax equity partnership arrangements where the tax equity investors receive substantially all of the tax benefits from the facilities, including ITCs and PTCs. In addition, Southern Power holds controlling interests in non-tax equity partnerships with its ownership interests primarily ranging from 51% to 66%.
 See PROPERTIES in Item 2 herein for additional detail regarding Southern Power's partnership arrangements and Note 15 to the financial statements under "Southern Power" in Item 8 herein for additional information regarding Southern Power's acquisitions, dispositions, construction, and development projects.
 Southern Power calculates an 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. With the inclusion of investments associated with facilities under construction, as well as other capacity and energy contracts, Southern Power's average investment coverage ratio at December 31, 2023 was 97% through 2028 and 89% through 2033, with an average remaining contract duration of approximately 12 years. For the year ended December 31, 2023, approximately 41% of contracted MWs were with AAA to A- or equivalent rated counterparties, 47% were with BBB+ to BBB- or equivalent rated counterparties, and 10% were with unrated entities that either have ratemaking authority or have posted collateral to cover potential credit exposure.
 Southern Power's electricity sales from natural gas generating facilities are primarily through long-term PPAs that consist of two types of agreements. The first type, referred to as a unit or block sale, is a customer purchase from a dedicated plant unit where all or a portion of the generation from that unit is reserved for that customer. Southern Power typically has the ability to serve the unit or block sale customer from an alternate resource. The second type, referred to as requirements service, provides that Southern Power serves the customer's capacity and energy requirements from a combination of the customer's own generating units and from Southern Power resources not dedicated to serve unit or block sales. Southern Power has rights to purchase power provided by the requirements customers' resources when economically viable. Capacity charges that form part of the PPA payments are designed to recover fixed and variable operations and maintenance costs based on dollars-per-kilowatt year and to provide a return on investment.
 Southern Power's electricity sales from solar and wind generating facilities are also primarily through long-term PPAs; however, these 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 provide Southern Power a certain fixed price for the electricity sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Generally, under the renewable generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits.
 Southern Power actively pursues replacement PPAs prior to the expiration of its current PPAs and anticipates that the revenues attributable to one customer may be replaced by revenues from a new customer; however, the expiration of any of Southern Power's current PPAs without the successful remarketing of a replacement PPA could have a material negative impact on Southern Power's earnings but is not expected to have a material impact on Southern Company's earnings.

 Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. Southern Company Gas is also involved in several other businesses that are complementary to the distribution of natural gas, including gas pipeline investments and gas marketing services. Southern Company Gas also has an "all other" non-reportable segment that includes segments below the quantitative threshold for separate disclosure. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 herein for information regarding Southern Company Gas' recent dispositions.
 Gas distribution operations, the largest segment of Southern Company Gas' business, operates, constructs, and maintains approximately 77,900 miles of natural gas pipelines and 14 storage facilities, with total capacity of 157 Bcf, to provide natural gas to residential, commercial, and industrial customers. Gas distribution operations serves approximately 4.4 million customers across four states.
 Gas pipeline investments primarily 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. SNG, the largest natural gas pipeline investment, is the owner of a 7,000-mile pipeline connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee.
 Gas marketing services is comprised of SouthStar, which serves approximately 665,000 natural gas commodity customers, markets gas to residential, commercial, and industrial customers and offers energy-related products that provide natural gas price stability and utility bill management in competitive markets or markets that provide for customer choice.
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 Construction Programs
 The subsidiary companies of Southern Company are engaged in continuous construction programs, including capital expenditures to accommodate existing and estimated future loads on their respective systems and to comply with environmental laws and regulations, as applicable. In 2024, the Southern Company system's construction program is expected to be apportioned approximately as follows:

 system(a)(b)

Power
 Power

 New generation
 $
 1.1
 $
 —
 $
 1.0
 $
 —

 Environmental compliance(c)

 0.1
 —
 0.1
 —

 Generation maintenance
 1.3
 0.5
 0.7
 0.1

 Transmission
 1.7
 0.3
 1.4
 —

 Distribution
 1.7
 0.5
 1.1
 0.1

 Nuclear fuel
 0.3
 0.1
 0.2
 —

 General plant
 1.6
 0.7
 0.9
 0.1

 7.8
 2.1
 5.4
 0.3

 Southern Power(d)

 0.3

 Southern Company Gas(e)

 1.8

 Other subsidiaries
 0.1

 Total(a)

 $
 10.0
 $
 2.1
 $
 5.4
 $
 0.3

 (a)Totals may not add due to rounding.
 (b)Includes the Subsidiary Registrants, as well as other subsidiaries.
 (c)Reflects cost estimates for environmental laws and regulations. These estimated expenditures do not include potential compliance costs associated with any future regulation of CO2 emissions from fossil fuel-fired electric generating units or the proposed ELG Supplemental Rule, or costs associated with closure and monitoring of ash ponds and landfills in accordance with the CCR Rule and the related state rules. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" and FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" in Item 7 herein for additional information. No material capital expenditures are expected for non-environmental government regulations.
 (d)Does not include approximately $0.8 billion for planned acquisitions and placeholder growth, which may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy.
 (e)Includes costs for ongoing capital projects associated with infrastructure improvement programs for certain natural gas distribution utilities that have been previously approved by their applicable state regulatory agencies. See Note 2 to the financial statements under "Southern Company Gas" in Item 8 herein for additional information.
 The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors.
 The traditional electric operating companies also anticipate continued expenditures associated with closure and monitoring of ash ponds and landfills in accordance with the CCR Rule and the related state rules, which are reflected in the applicable Registrants' ARO liabilities. Estimated costs for 2024 total $728 million for Southern Company, primarily consisting of $346 million for Alabama Power, $338 million for Georgia Power, and $24 million for Mississippi Power.
 See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" in Item 7 herein for additional information, including estimated expenditures for construction, environmental compliance, and closure and monitoring of ash ponds and landfills for the years 2025 through 2028.
 Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" in Item 7 herein for additional information with respect to certain existing and proposed environmental requirements and PROPERTIES – "Electric – Jointly-Owned Facilities" and – "Natural Gas – Jointly-Owned Properties" in Item 2 herein and Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information concerning the Registrants' joint ownership of certain facilities.

 Financing Programs
 See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY in Item 7 herein and Note 8 to the financial statements in Item 8 herein for information concerning financing programs.
 I-4

 Fuel Supply
 The traditional electric operating companies' and SEGCO's supply of electricity is primarily fueled by natural gas and coal, as well as nuclear for Alabama Power and Georgia Power. Southern Power's supply of electricity is primarily fueled by natural gas. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATION – "Southern Company – Electricity Business – Fuel and Purchased Power Expenses" and MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATION under "Fuel and Purchased Power Expenses" for each of the traditional electric operating companies in Item 7 herein for information regarding the electricity generated and the average cost of fuel in cents per net KWH generated for the years 2022 and 2023.
 SCS, acting on behalf of the traditional electric operating companies and Southern Power Company, has agreements in place for the natural gas burn requirements of the Southern Company system. For 2024, SCS has contracted for 620 Bcf of natural gas supply under agreements with remaining terms up to 10 years. In addition to natural gas supply, SCS has contracts in place for both firm natural gas transportation and storage. Management believes these contracts provide sufficient natural gas supplies, transportation, and storage to ensure normal operations of the Southern Company system's natural gas generating units. See "Natural Gas" herein for information on the natural gas market.
 The traditional electric operating companies have agreements in place from which they expect to receive substantially all of their 2024 coal burn requirements. These agreements have terms ranging between one and three years. Fuel procurement specifications, emission allowances, environmental control systems, and fuel changes have allowed the traditional electric operating companies to remain within limits set by applicable environmental regulations. As new environmental regulations are proposed that impact the utilization of coal, the traditional electric operating companies' fuel mix will be monitored to help ensure compliance with applicable laws and regulations. Southern Company and the traditional electric operating companies will continue to evaluate the need to purchase additional emissions allowances, the timing of capital expenditures for environmental control equipment, and potential unit retirements and replacements. While none of Southern Company's subsidiaries are currently subject to renewable portfolio standards or similar requirements, management of the traditional electric operating companies is working with applicable regulators through their IRP processes to continue the generating fleet transition in a manner responsible to customers, communities, employees, and other stakeholders. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" in Item 7 herein and Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order," "Georgia Power – Integrated Resource Plans," and "Mississippi Power – Integrated Resource Plan" in Item 8 herein for additional information, including the Southern Company system's electric generating mix and plans to retire or convert to natural gas certain coal-fired generating capacity.
 Alabama Power and Georgia Power have multiple contracts covering their nuclear fuel needs for uranium, conversion services, enrichment services, and fuel fabrication with remaining terms up to 11 years. Management believes suppliers have sufficient nuclear fuel production capability to permit normal operation of the Southern Company system's nuclear generating units. Alabama Power and Georgia Power also have contracts with the United States, acting through the DOE, that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent fuel in 1998, as required by the contracts, and Alabama Power and Georgia Power have pursued and are pursuing legal remedies against the government for breach of contract. See Note 3 to the financial statements under "Nuclear Fuel Disposal Costs" in Item 8 herein for additional information.
 Changes in fuel prices to the traditional electric operating companies are generally reflected in fuel adjustment clauses contained in rate schedules. See "Rate Matters – Rate Structure and Cost Recovery Plans" herein for additional information. Southern Power's natural gas PPAs generally provide that the counterparty is responsible for substantially all of the cost of fuel.

 Natural gas remains a volatile commodity. Slight supply and demand imbalances can quickly result in significant price moves both up and down. These price movements may be short-lived, but the impacts can be pronounced. Natural gas supplies, primarily from the Permian and Haynesville regions, have continued to grow; however, this growth has been accompanied by LNG export growth. Forward curves project prices will remain in the range of mid-to high- $3 per mmBtu, approaching $4 per mmBtu, through 2030; however, short-term price volatility is expected and future prices could be materially impacted by various factors, including unexpected geopolitical events as well as government policies related to natural gas infrastructure development, production, and exports.
 Southern Company Gas' procurement plans for natural gas supply and transportation to serve regulated utility customers are reviewed and approved by the regulatory agencies in the states where it operates. Southern Company Gas purchases natural gas supplies in the open market by contracting with producers and marketers and, for Atlanta Gas Light and Chattanooga Gas, under asset management agreements approved by the applicable state regulatory agency. Southern Company Gas also contracts
 I-5

 for transportation and storage services from interstate pipelines that are regulated by the FERC. When firm pipeline services are temporarily not needed, Southern Company Gas may release the services in the secondary market under FERC-approved capacity release provisions or utilize asset management arrangements, thereby reducing the net cost of natural gas charged to customers for most of the natural gas distribution utilities. Peak-use requirements are met through utilization of company-owned storage facilities, pipeline transportation capacity, purchased storage services, peaking facilities, and other supply sources, arranged by either transportation customers or Southern Company Gas.
 With the exception of Atlanta Gas Light, the natural gas distribution utilities are authorized by the relevant regulatory agencies in the states in which they serve to use natural gas cost recovery mechanisms that adjust rates to reflect changes in the wholesale cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. See Note 2 to the financial statements under "Southern Company Gas – Natural Gas Cost Recovery" in Item 8 herein for additional information.

 Territory Served by the Southern Company System
 Traditional Electric Operating Companies and Southern Power
 The territory in which the traditional electric operating companies provide retail electric service comprises most of the states of Alabama and Georgia, together with southeastern Mississippi. In this territory there are non-affiliated electric distribution systems that obtain some or all of their power requirements either directly or indirectly from the traditional electric operating companies. As of December 31, 2023, the territory had an area of approximately 116,000 square miles and an estimated population of approximately 17 million. Southern Power sells wholesale electricity at market-based rates across various U.S. utility markets, primarily to investor-owned utilities, IPPs, municipalities, and other load-serving entities, as well as commercial and industrial customers.
 Alabama Power is engaged, within the State of Alabama, in the generation, transmission, distribution, and purchase of electricity and the sale of electric service, at retail in approximately 400 cities and towns (including Anniston, Birmingham, Gadsden, Mobile, Montgomery, and Tuscaloosa), as well as in rural areas, and at wholesale to 11 municipally-owned electric distribution systems, all of which are served indirectly through sales to AMEA, and two rural distributing cooperative associations. The sales contract with AMEA will expire on December 31, 2025. In addition, Alabama Power sells, and cooperates with dealers in promoting the sale of, electric appliances and products and also markets and sells outdoor lighting services.
 Georgia Power is engaged in the generation, transmission, distribution, and purchase of electricity and the sale of electric service within the State of Georgia, at retail in over 530 cities and towns (including Athens, Atlanta, Augusta, Columbus, Macon, Rome, and Savannah), as well as in rural areas, and at wholesale to OPC, MEAG Power, Dalton, various EMCs, and non-affiliated utilities. Georgia Power also markets and sells outdoor lighting services and other customer-focused utility services.
 Mississippi Power is engaged in the generation, transmission, distribution, and purchase of electricity and the sale of electric service within 23 counties in southeastern Mississippi, at retail in 123 communities (including Biloxi, Gulfport, Hattiesburg, Laurel, Meridian, and Pascagoula), as well as in rural areas, and at wholesale to one municipality, six rural electric distribution cooperative associations, and one generating and transmitting cooperative.
 The following table provides the number of retail customers served by customer classification for the traditional electric operating companies at December 31, 2023:

 Total(*)

 (in thousands)

 1,328
 2,406
 3,890

 —

 Other
 —

 Total(*)

 1,541
 2,754
 4,487

 (*)Totals may not add due to rounding.
 I-6

 For information relating to KWH sales by customer classification for the traditional electric operating companies, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS in Item 7 herein. Also, for information relating to the sources of revenues for Southern Company, each traditional electric operating company, and Southern Power, see Item 7 herein and Note 1 to the financial statements under "Revenues – Traditional Electric Operating Companies" and " – Southern Power" and Note 4 to the financial statements in Item 8 herein.
 As of December 31, 2023, there were 62 electric cooperative distribution systems operating in the territories in which the traditional electric operating companies provide electric service at retail or wholesale.
 PowerSouth is a generating and transmitting cooperative selling power to several distributing cooperatives, municipal systems, and other customers in south Alabama. As of December 31, 2023, PowerSouth owned generating units with more than 1,600 MWs of nameplate capacity, including an undivided 8.16% ownership interest in Alabama Power's Plant Miller Units 1 and 2. See PROPERTIES – "Electric – Jointly-Owned Facilities" in Item 2 herein and Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information.
 In accordance with an agreement executed in 2021, Alabama Power began providing approximately 100 MWs of year-round capacity service to PowerSouth on February 1, 2024.
 In 2021, Alabama Power and PowerSouth began operations under a coordinated planning and operations agreement, with a minimum term of 10 years. The agreement includes combined operations (including joint commitment and dispatch) and real-time energy sales and purchases and is expected to create energy cost savings and enhanced system reliability for both parties. Projected revenues are expected to offset any increased administrative costs incurred by Alabama Power. Under the agreement, Alabama Power has the right to participate in a portion of PowerSouth's future incremental load growth.
 Alabama Power also has a separate agreement with PowerSouth involving interconnection between their systems. The delivery of capacity and energy from PowerSouth to certain distributing cooperatives in the service territory of Alabama Power is governed by the Southern Company/PowerSouth Network Transmission Service Agreement. The rates for this service to PowerSouth are on file with the FERC.
 OPC is an EMC owned by its 38 retail electric distribution cooperatives, which provide retail electric service to customers in Georgia. OPC provides wholesale electric power to its members through its generation assets, some of which are jointly owned with Georgia Power, and power purchased from other suppliers. OPC and the 38 retail electric distribution cooperatives are members of Georgia Transmission Corporation, an EMC (GTC), which provides transmission services to its members and third parties. See PROPERTIES – "Electric – Jointly-Owned Facilities" in Item 2 herein and Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information regarding Georgia Power's jointly-owned facilities.
 Mississippi Power has an interchange agreement with Cooperative Energy, a generating and transmitting cooperative, pursuant to which various services are provided. Cooperative Energy also has a 10-year network integration transmission service agreement with SCS for transmission service to certain delivery points on Mississippi Power's transmission system through March 31, 2031. See Note 2 to the financial statements under "Mississippi Power – Municipal and Rural Associations Tariff" in Item 8 herein for information on a separate shared service agreement between Mississippi Power and Cooperative Energy.
 As of December 31, 2023, there were 72 municipally-owned electric distribution systems operating in the territory in which the traditional electric operating companies provide electric service at retail or wholesale.
 As of December 31, 2023, 48 municipally-owned electric distribution systems and one county-owned system received their requirements through MEAG Power. MEAG Power serves these requirements from self-owned generation facilities, some of which are jointly-owned with Georgia Power, and purchases from other resources. MEAG Power also has a pseudo scheduling and services agreement with Georgia Power. Dalton serves its requirements from self-owned generation facilities, some of which are jointly-owned with Georgia Power, and through purchases from Southern Power through a service agreement. See PROPERTIES – "Electric – Jointly-Owned Facilities" in Item 2 herein and Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information.
 Georgia Power has entered into substantially similar agreements with GTC, MEAG Power, and Dalton providing for the establishment of an integrated transmission system to carry the power and energy of all parties. The agreements require an investment by each party in the integrated transmission system in proportion to its respective share of the aggregate system load. See PROPERTIES – "Electric – Jointly-Owned Facilities" in Item 2 herein for additional information.
 Southern Power has PPAs with Georgia Power, investor-owned utilities, IPPs, municipalities, electric cooperatives, and other load-serving entities, as well as commercial and industrial customers. See "The Southern Company System – Southern Power" herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Southern Power's Power Sales Agreements" in Item 7 herein for additional information.
 I-7

 SCS, acting on behalf of the traditional electric operating companies, also has a contract with SEPA providing for the use of the traditional electric operating companies' facilities at government expense to deliver to certain cooperatives and municipalities, entitled by federal statute to preference in the purchase of power from SEPA, quantities of power equivalent to the amounts of power allocated to them by SEPA from certain U.S. government hydroelectric projects.

 Southern Company Gas is engaged in the distribution of natural gas in four states through the natural gas distribution utilities. The natural gas distribution utilities construct, manage, and maintain intrastate natural gas pipelines and distribution facilities. Details of the natural gas distribution utilities at December 31, 2023 are as follows:

 Utility
 State
 Number of customers
 Approximate miles of pipe

 (in thousands)

 Illinois
 2,276
 34.7

 1,714
 35.6

 Virginia
 5.9

 Tennessee
 1.7

 Total
 4,374
 77.9

 For information relating to the sources of revenue for Southern Company Gas, see Item 7 herein and Note 1 to the financial statements under "Revenues – Southern Company Gas" and Note 4 to the financial statements in Item 8 herein.

 Competition
 The electric utility industry in the U.S. is continuing to evolve as a result of regulatory and competitive factors. The competition for retail energy sales among competing suppliers of energy is influenced by various factors, including price, availability, technological advancements, service, and reliability. These factors are, in turn, affected by, among other influences, regulatory, political, and environmental considerations, taxation, and supply.
 The retail service rights of all electric suppliers in the State of Georgia are regulated by the Territorial Electric Service Act of 1973. Pursuant to standards set forth in this Act, the Georgia PSC has assigned substantially all of the land area in the state to a supplier. Notwithstanding such assignments, this Act provides that any new customer locating outside of 1973 municipal limits and having a connected load of at least 900 KWs may exercise a one-time choice for the life of the premises to receive electric service from the supplier of its choice.
 Pursuant to the 1956 Utility Act, the Mississippi PSC issued "Grandfather Certificates" of public convenience and necessity to Mississippi Power and to six distribution rural cooperatives operating in southeastern Mississippi, then served in whole or in part by Mississippi Power, authorizing them to distribute electricity in certain specified geographically described areas of the state. The six cooperatives serve approximately 325,000 retail customers in a certificated area of approximately 10,300 square miles. In areas included in a "Grandfather Certificate," the utility holding such certificate may extend or maintain its electric system subject to certain regulatory approvals; extensions of facilities by such utility, or extensions of facilities into that area by other utilities, may not be made unless the Mississippi PSC grants a CPCN. Areas included in a CPCN that are subsequently annexed to municipalities may continue to be served by the holder of the CPCN, irrespective of whether it has a franchise in the annexing municipality. On the other hand, the holder of the municipal franchise may not extend service into such newly annexed area without authorization by the Mississippi PSC.
 Generally, the traditional electric operating companies have experienced, and expect to continue to experience, competition in their respective retail service territories in varying degrees from the development and deployment of alternative energy sources such as self-generation (as described below) and distributed generation technologies, as well as other factors. Further technological advancements or the implementation of policies in support of alternative energy sources may result in further competition.
 Southern Power competes with investor-owned utilities, IPPs, and others for wholesale energy sales across various U.S. utility markets. The needs of these markets are driven by the demands of end users and the generation available. Southern Power's success in wholesale energy sales is influenced by various factors including reliability and availability of Southern Power's plants, availability of transmission to serve the demand, price, and Southern Power's ability to contain costs.
 I-8

 As of December 31, 2023, Alabama Power had cogeneration contracts in effect with seven industrial customers. Under the terms of these contracts, Alabama Power purchases excess energy generated by such companies. During 2023, Alabama Power purchased approximately 113 million KWHs from such companies. The related costs were immaterial.
 As of December 31, 2023, Georgia Power had contracts in effect to purchase generation from 36 small IPPs. During 2023, Georgia Power purchased 5.9 billion KWHs from such companies at a cost of $303 million. Georgia Power also has PPAs for electricity with seven cogeneration facilities. Payments are subject to reductions for failure to meet minimum capacity output. During 2023, Georgia Power purchased 349 million KWHs at a cost of $31 million from these facilities.
 As of December 31, 2023, Mississippi Power had a cogeneration agreement in effect with one of its industrial customers. Under the terms of this contract, Mississippi Power purchases any excess generation. During 2023, Mississippi Power did not make any such purchases.

 Southern Company Gas' natural gas distribution utilities do not compete with other distributors of natural gas in their exclusive franchise territories but face competition from other energy products. Their principal competitors are electric utilities and fuel oil and propane providers serving the residential, commercial, and industrial markets in their service areas for customers who are considering switching to or from a natural gas appliance.
 Competition for heating as well as general household and small commercial energy needs generally occurs at the initial installation phase when the customer or builder makes decisions as to which types of equipment to install. Customers generally use the chosen energy source for the life of the equipment.
 Customer demand for natural gas could be affected by numerous factors, including:
 • changes in the availability or price of natural gas and other forms of energy;
 • general economic conditions;
 • energy conservation, including state-supported energy efficiency programs;
 • legislation and regulations, including certain bans on the use of natural gas in new or existing construction and electrification initiatives;
 • the cost and capability to convert from natural gas to alternative energy products; and
 • technological or regulatory changes resulting in displacement or replacement of natural gas appliances.
 Southern Company Gas has natural gas-related programs that generally emphasize natural gas as the fuel of choice for customers and seek to expand the use of natural gas through a variety of promotional activities. In addition, Southern Company Gas partners with third-party entities to market the benefits of natural gas appliances.

 Seasonality and Demand
 The demand for electric power and natural gas supply is affected by seasonal differences in the weather. While the electric power sales of some electric utilities peak in the summer, others peak in the winter. In the aggregate, during normal weather conditions, the Southern Company system's electric power sales peak during both the summer and winter. In most of the areas Southern Company Gas serves, natural gas demand peaks during the winter. As a result, the overall operating results of the Registrants in the future may fluctuate substantially on a seasonal basis. In addition, the Subsidiary Registrants have historically sold less power and natural gas when weather conditions are milder.
 See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "General" and – RESULTS OF OPERATIONS – "Southern Company Gas" in Item 7 herein for information regarding trends in market demand for electricity and natural gas and the impact of seasonality on Southern Company Gas' business, respectively.

 Regulation
 States
 The traditional electric operating companies and the natural gas distribution utilities are subject to the jurisdiction of their respective state PSCs or applicable state regulatory agencies. These regulatory bodies have broad powers of supervision and regulation over public utilities operating in the respective states, including their rates, service regulations, sales of securities (except for the Mississippi PSC), and, in the cases of the Georgia PSC and the Mississippi PSC, in part, retail service territories. See "Territory Served by the Southern Company System" and "Rate Matters" herein for additional information.
 I-9

 Federal Power Act
 The traditional electric operating companies, Southern Power Company and certain of its generation subsidiaries, and SEGCO are all public utilities engaged in wholesale sales of energy in interstate commerce and, therefore, are subject to the rate, financial, and accounting jurisdiction of the FERC under the Federal Power Act. The FERC must approve certain financings and allows an "at cost standard" for services rendered by system service companies such as SCS and Southern Nuclear. The FERC is also authorized to establish regional reliability organizations which enforce reliability standards, address impediments to the construction of transmission, and prohibit manipulative energy trading practices.
 Alabama Power and Georgia Power are also subject to the provisions of the Federal Power Act or the earlier Federal Water Power Act applicable to licensees with respect to their hydroelectric developments. As of December 31, 2023, among the hydroelectric projects subject to licensing by the FERC are 14 existing Alabama Power generating stations having an aggregate installed capacity of 1.7 million KWs and 17 existing Georgia Power generating stations and one generating station partially owned by Georgia Power, with a combined aggregate installed capacity of 1.1 million KWs.
 In 2013, the FERC issued a new 30-year license to Alabama Power for Alabama Power's seven hydroelectric developments on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan, and Bouldin). Alabama Power filed a petition requesting rehearing of the FERC order granting the relicense seeking revisions to several conditions of the license. In 2016, the FERC issued an order granting in part and denying in part Alabama Power's rehearing request. American Rivers and Alabama Rivers Alliance also filed multiple appeals of the FERC's 2013 order for the new 30-year license and, in 2018, the U.S. Court of Appeals for the District of Columbia Circuit vacated the order and remanded the proceeding to the FERC. Alabama Power continues to operate the Coosa River developments under annual licenses issued by the FERC.
 In 2021, Alabama Power filed an application with the FERC to relicense the Harris Dam project on the Tallapoosa River. The original Harris Dam project license expired on November 30, 2023 and, on December 13, 2023, the FERC issued an annual license for the continued operation of the Harris Dam project. The Harris Dam project will operate under annual licenses until a new long-term license is issued, which is expected by the first half of 2025.
 In 2018, Georgia Power filed applications to surrender the Langdale and Riverview hydroelectric projects on the Chattahoochee River upon their license expirations on December 31, 2023. Although the projects are not operational, the closure of the projects is subject to the closure requirements to be enforced in accordance with future FERC surrender orders.
 In 2021, Georgia Power filed an application with the FERC to relicense the Lloyd Shoals project on the Ocmulgee River. The current Lloyd Shoals project license expired on December 31, 2023. Subsequent to December 31, 2023, the FERC authorized Georgia Power to continue operation of the Lloyd Shoals project under the terms and conditions of the prior license until the issuance of a subsequent license.
 Georgia Power and OPC also have a license, expiring in 2026, for the Rocky Mountain project, a pure pumped storage facility of 903,000 KW installed capacity. In 2021, OPC, as an agent for co-licensees of the project, filed a notice of intent with the FERC to relicense the project. An application to relicense the project is expected to be filed with the FERC by December 31, 2024. See PROPERTIES – "Electric – Jointly-Owned Facilities" in Item 2 herein for additional information.
 Licenses for all projects, excluding those discussed above, expire in the years 2034-2066 for Alabama Power's projects and in the years 2034-2060 for Georgia Power's projects.
 Upon or after the expiration of each license, the U.S. Government, by act of Congress, may take over the project or the FERC may relicense the project either to the original licensee or to a new licensee. In the event of takeover or relicensing to another, the original licensee is to be compensated in accordance with the provisions of the Federal Power Act, such compensation to reflect the net investment of the licensee in the project, not in excess of the fair value of the property, plus reasonable damages to other property of the licensee resulting from the severance therefrom of the property. The FERC may grant relicenses subject to certain requirements that could result in additional costs.
 Nuclear Regulation
 Alabama Power, Georgia Power, and Southern Nuclear are subject to regulation by the NRC. The NRC is responsible for licensing and regulating nuclear facilities and materials and for conducting research in support of the licensing and regulatory process, as mandated by the Atomic Energy Act of 1954, as amended; the Energy Reorganization Act of 1974, as amended; and the Nuclear Nonproliferation Act of 1978, as amended; and in accordance with the National Environmental Policy Act of 1969, as amended, and other applicable statutes. These responsibilities also include protecting public health and safety, protecting the environment, protecting and safeguarding nuclear materials and nuclear power plants in the interest of national security, and assuring conformity with antitrust laws.
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 The NRC licenses for Georgia Power's Plant Hatch Units 1 and 2 expire in 2034 and 2038, respectively. Southern Nuclear has notified the NRC of its intent in the third quarter 2025 to seek to renew the plant's licenses for an additional 20 years (through 2054 and 2058 for Units 1 and 2, respectively). The NRC licenses for Alabama Power's Plant Farley Units 1 and 2 expire in 2037 and 2041, respectively. The NRC licenses for Plant Vogtle Units 1, 2, 3, and 4 expire in 2047, 2049, 2062, and 2063, respectively. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 herein for additional information on Plant Vogtle Units 3 and 4, including the projected in-service date for Unit 4.
 See Notes 3 and 6 to the financial statements under "Nuclear Insurance" and "Nuclear Decommissioning," respectively, in Item 8 herein for additional information.
 Environmental Laws and Regulations
 See "Construction Programs" herein, MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" in Item 7 herein, and Note 3 to the financial statements under "Environmental Remediation" and Note 6 to the financial statements in Item 8 herein for information concerning environmental laws and regulations impacting the Registrants.

 Rate Matters
 Rate Structure and Cost Recovery Plans
 The rates and service regulations of the traditional electric operating companies are uniform for each class of service throughout their respective retail service territories. Rates for residential electric service are generally of the block type based upon KWHs used and include minimum charges. Residential and other rates contain separate customer charges. Rates for commercial service are also of the block type and, for large customers, the billing demand is generally used to determine capacity and minimum bill charges. These large customers' rates are generally based upon usage by the customer and include rates with special features to encourage off-peak usage. Additionally, Alabama Power and Mississippi Power are generally allowed by their respective state PSCs to negotiate the terms and cost of service to large customers, subject to final state PSC approval.
 The traditional electric operating companies recover certain costs through a variety of forward-looking, cost-based rate mechanisms. Fuel and net purchased energy costs are recovered through specific fuel cost recovery provisions. These fuel cost recovery provisions are adjusted to reflect increases or decreases in such costs as needed or on schedules as required by the respective PSCs. Approved compliance, storm damage, and certain other costs are recovered at Alabama Power and Mississippi Power through specific cost recovery mechanisms approved by their respective PSCs. Certain similar costs at Georgia Power are recovered through various base rate tariffs as approved by the Georgia PSC. Costs not recovered through specific cost recovery mechanisms are recovered at Alabama Power and Mississippi Power through annual, formulaic cost recovery proceedings and at Georgia Power through periodic base rate proceedings.
 See Note 2 to the financial statements in Item 8 herein for a discussion of rate matters and certain cost recovery mechanisms. Also see "Integrated Resource Planning" herein for additional information.
 The traditional electric operating companies and Southern Power Company and certain of its generation subsidiaries are authorized by the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.
 Mississippi Power provides service under long-term contracts with rural electric cooperative associations and a municipality located in southeastern Mississippi under requirements cost-based electric tariffs, which are subject to regulation by the FERC. The contracts with these wholesale customers represented 14.0% of Mississippi Power's total operating revenues in 2023.

 Southern Company Gas' natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies. Rates charged to customers vary according to customer class (residential, commercial, or industrial) and rate jurisdiction. These agencies approve rates designed to provide the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable ROE.
 With the exception of Atlanta Gas Light, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are largely a function of weather conditions and price levels for natural gas. The natural gas distribution utilities have weather or revenue normalization mechanisms that mitigate revenue fluctuations from customer consumption changes. Atlanta Gas Light operates in a deregulated environment in which Marketers rather than a traditional utility sell natural gas to end-use customers and earns revenue by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC.
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 In addition to natural gas cost recovery mechanisms, other cost recovery mechanisms and regulatory riders, which vary by utility, allow recovery of certain costs, such as those related to infrastructure replacement programs as well as environmental remediation, energy efficiency plans, and bad debts.
 See Note 2 to the financial statements under "Southern Company Gas" in Item 8 herein for a discussion of rate matters and certain cost recovery mechanisms.

 Integrated Resource Planning
 Each of the traditional electric operating companies continually evaluates its electric generating resources in order to ensure that it maintains a cost-effective and reliable mix of resources to meet the existing and future demand requirements of its customers. In addition, each year the Southern Company system engages in a scenario planning process, developing scenarios which look out over a 30-year horizon. In 2023, scenarios included a wide range of fuel prices, load growth, and CO2 prices starting between $0 and $50 per metric ton of CO2 emitted and escalating over the 30-year horizon. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" in Item 7 herein for a discussion of existing and potential environmental regulations that may impact the future generating resource needs of the traditional electric operating companies, as well as a discussion of the Southern Company system's continued generating fleet transition.
 Triennially, Alabama Power provides an IRP report to the Alabama PSC. This report overviews Alabama Power's resource planning process and contains information that serves as the foundation for certain decisions affecting Alabama Power's portfolio of supply-side and demand-side resources. The IRP report facilitates Alabama Power's ability to provide reliable and cost-effective electric service to customers, while accounting for the risks and uncertainties inherent in planning for resources sufficient to meet expected customer demand. Under State of Alabama law, a CCN must be obtained from the Alabama PSC before Alabama Power constructs any new generating facility, unless such construction is an ordinary extension of an existing system in the usual course of business. Alabama Power provided its most recent IRP to the Alabama PSC during 2022. See Note 2 to the financial statements under "Alabama Power – Rate CNP New Plant" in Item 8 herein for additional information.

 Triennially, Georgia Power must file an IRP with the Georgia PSC that specifies how it intends to meet the future electric service needs of its customers through a combination of demand-side and supply-side resources. The Georgia PSC, under state law, must certify any new demand-side or supply-side resources for Georgia Power to receive cost recovery. Once certified, the lesser of actual or certified construction costs and purchased power costs is recoverable through rates. Certified costs may be excluded from recovery only on the basis of fraud, concealment, failure to disclose a material fact, imprudence, or criminal misconduct. In July 2022, the Georgia PSC approved Georgia Power's 2022 IRP, as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and as further modified by the Georgia PSC. 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. Georgia Power expects the Georgia PSC to render a final decision on the 2023 IRP Update on April 16, 2024. The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" and " – Rate Plans" in Item 8 herein for additional information. Also see Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 herein for additional information on the Georgia Nuclear Energy Financing Act and the Georgia PSC certification of Plant Vogtle Units 3 and 4, which have allowed Georgia Power to recover certain financing costs for construction of Plant Vogtle Units 3 and 4.

 Triennially, Mississippi Power must file an IRP with the Mississippi PSC, as well as an update at approximately the mid-point of the three-year cycle. The IRP must include long-term plans to best meet the needs of electric utility customers through a combination of demand-side and supply-side resources and considering transmission needs. The IRP filing is not intended to supplant or replace the Mississippi PSC's existing regulatory processes for petition and approval of CPCNs for new generating resources. Mississippi Power's most recent IRP was filed in 2021 and the next IRP is expected to be filed in April 2024. Mississippi Power must also file an annual report on energy delivery improvements, the latest of which was filed in November 2023. See Note 2 to the financial statements under "Mississippi Power – Integrated Resource Plan" in Item 8 herein for additional information.
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 Human Capital
 Southern Company system management is committed to attracting, developing, and retaining a sustainable workforce and aims to foster a diverse, equitable, inclusive, and innovative culture. The Southern Company system's values – safety first, intentional inclusion, act with integrity, and superior performance – guide behavior. The Southern Company system had approximately 28,100 employees on its payroll at December 31, 2023 comprised of the following:

 At December 31, 2023(*)

 6,200

 6,600

 1,000

 4,800

 SCS
 4,200

 Southern Nuclear
 3,800

 PowerSecure and other
 1,000

 Total Southern Company system
 28,100

 (*)Numbers are rounded to 100s.
 All Southern Company system employees are located within the United States. Part-time employees represent less than 1% of total employees.
 Southern Company system management values a diverse, equitable, and inclusive workforce. Southern Company's subsidiaries have policies, programs, and processes to help ensure that all groups are represented, included, and fairly treated across all job levels. The Southern Company Board of Directors and management believe that diversity is important to provide different perspectives on risk, business strategy, and innovation. Southern Company management leads the Southern Company system's diversity, equity, and inclusion initiatives and employee recruitment, retention, and development efforts. The Board, principally through its Compensation and Talent Development Committee, oversees these efforts. Southern Company system management utilizes its "Moving to Equity" initiative that focuses on five key areas: talent, work environment, supplier inclusion, civic engagement, and community investment and social justice. This initiative demonstrates the Southern Company system's commitments, highlights key results, and tracks progress on long-term goals.
 Southern Company system management supports employee resource groups, diversity councils, mentoring programs, and inclusion teams to provide formal networks of colleagues that can help promote belonging, improve employee retention, and support development. At December 31, 2023, people of color and women represented 30% and 25%, respectively, of the Southern Company system's workforce.
 Southern Company system management recognizes the importance of attracting and retaining an appropriately qualified workforce. Southern Company system management uses a variety of strategies to attract and retain talent, including working with high schools, technical schools, universities, and military installations to fill many entry-level positions. The recruiting strategy also includes partnerships with professional associations and local communities to recruit mid-career talent. The addition of external hires augments the existing workforce to meet changing business needs, address any critical skill gaps, and supplement and diversify the Southern Company system's talent pipeline.
 The Southern Company system supports the well-being of its employees through a comprehensive total rewards strategy with three measurable categories: physical, financial, and emotional well-being. The Southern Company system provides competitive salaries, annual incentive awards for nearly all employees, and health, welfare, and retirement benefits. The Southern Company system has a qualified defined benefit, trusteed pension plan and a qualified defined contribution, trusteed 401(k) plan which provides a competitive company matching contribution. Substantially all Southern Company system employees are eligible to participate in these plans. There are differences between the pension plan benefit formulas based on when and by which subsidiary an employee is hired. See Note 11 to the financial statements for additional information. At December 31, 2023, the average age of the Southern Company system employees was 44 and the average tenure with the Southern Company system was 14 years. Turnover rate, calculated as the percent of employees that terminated employment with the Southern Company system, including voluntary and involuntary terminations and retirements, divided by total employees, was 8.3%.
 Southern Company system management is committed to developing talent and helping employees succeed by providing development opportunities along with purposeful people moves as part of individual development plans and succession planning processes. The Southern Company system has multiple development programs, including programs targeted toward all
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 employees, high potential employees, first-level managers, managers of managers, and executives. Additionally, Southern Company system management strives to deliver consistent needs-based training and solutions as workplace needs evolve.
 Southern Company system management believes the safety of employees and customers is paramount. The Southern Company system seeks to meet or exceed applicable laws and regulations while continually improving its safety technologies and processes. The Southern Company System Safety and Health Council, which includes leaders from each Registrant, works collectively across the Southern Company system to provide safety leadership, share learning, work collaboratively to address safety-related issues, and govern the consistency of safety programs. The safety programs are focused on the prevention and elimination of life-altering events, serious injuries, and fatalities. These programs include continuous process improvements to put critical controls in place to prevent serious injuries, promote learning, and implement appropriate corrective actions. In 2023, the Southern Company system had zero fatalities and a serious injury rate of 0.06, which represents the number of incidents per 100 employees (calculated by taking the number of serious injuries multiplied by 200,000 workhours and divided by the total employee workhours during the year). A serious injury is one that is life-threatening or life-changing (temporary or permanent) for the employee. Serious injury examples, as defined by applicable safety regulators, include fatalities, amputations, trauma to organs, certain bone fractures, certain soft tissue injuries, severe burns, and eye injuries.
 The Southern Company system also has longstanding relationships with labor unions. The traditional electric operating companies, Southern Nuclear, and the natural gas distribution utilities have separate agreements with local unions of the IBEW, which generally apply to operating, maintenance, and construction employees. These agreements cover wages, benefits, terms of the pension plans, working conditions, and procedures for handling grievances and arbitration. The Southern Company system also partners with the IBEW to provide training programs to develop technical skills and career opportunities.
 At December 31, 2023, approximately 32% of Southern Company system employees were covered by agreements with unions, with agreements expiring between 2024 and 2029.
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 Item 1A. RISK FACTORS
 In addition to the other information in this Form 10-K, including MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL in Item 7, and other documents filed by Southern Company and/or its subsidiaries with the SEC, the following factors should be carefully considered in evaluating Southern Company and its subsidiaries. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by, or on behalf of, Southern Company and/or its subsidiaries. The risk factors discussed below could adversely affect a Registrant's results of operations, financial condition, liquidity, and cash flow, as well as cause reputational damage.
 UTILITY REGULATORY, LEGISLATIVE, AND LITIGATION RISKS
 Southern Company and its subsidiaries are subject to substantial federal, state, and local governmental regulation, including with respect to rates. Compliance with current and future regulatory requirements and procurement of necessary approvals, permits, and certificates may result in substantial costs to Southern Company and its subsidiaries.
 Laws and regulations govern the terms and conditions of the services the Southern Company system offers, protection of critical electric infrastructure assets, transmission planning, reliability, pipeline safety, interaction with wholesale markets and retail customers, and relationships with affiliates, among other matters. The Registrants' businesses are subject to regulatory regimes which could result in substantial monetary penalties if a Registrant is found to be noncompliant.
 The profitability of the traditional electric operating companies' and the natural gas distribution utilities' businesses is largely dependent on their ability, through the rates that they are permitted to charge, to recover their costs and earn a reasonable rate of return on invested capital. The traditional electric operating companies and the natural gas distribution utilities seek to recover their costs, including a reasonable return on invested capital, through their retail rates, which must be approved by the applicable state PSC or other applicable state regulatory agency. Such regulators, in a future rate proceeding, may alter the timing or amount of certain costs for which recovery is allowed or modify the current authorized rate of return; rate refunds may also be required. The outcome of any such proceeding could be impacted by a variety of factors, including the level of opposition from intervenors, potential impacts to customers, and past or future changes in the political, regulatory, economic, or legislative environment. Additionally, the rates charged to wholesale customers by the traditional electric operating companies and Southern Power and the rates charged to natural gas transportation customers by Southern Company Gas' pipeline investments must be approved by the FERC. Changes to Southern Power's and the traditional electric operating companies' ability to conduct business pursuant to FERC market-based rate authority could affect wholesale rates. Also, while a small percentage of transmission costs are recovered through wholesale electric tariffs, the majority are recovered through retail rates. Transmission planning and the resulting grid improvements could be impacted by FERC policy changes as well as North American Electric Reliability Corporation planning standard changes.
 The IRA, among other items, imposes a 15% corporate minimum tax on book income and is subject to the issuance of additional guidance by the U.S. Treasury Department and the IRS. Any rate recovery by the traditional electric operating companies or the natural gas distribution utilities will be determined pursuant to the regulatory processes of the FERC, state PSCs, or other applicable state regulatory agencies. There is no assurance, however, that such tax expense will be recoverable through the applicable regulatory process.
 The impact of any future revision or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to Southern Company or any of its subsidiaries is uncertain. Changes in regulation, the imposition of additional regulations, changes in application of existing regulations and in enforcement practices of regulators, or penalties imposed for noncompliance with existing laws or regulations could influence the operating environment of the Southern Company system and may result in substantial costs.
 The Southern Company system's costs of compliance with environmental laws and satisfying related AROs are significant.
 The Southern Company system's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, GHGs, water, land, avian and other wildlife and habitat protection, and other natural resources. Compliance with existing environmental requirements involves significant capital and operating costs including the settlement of AROs, a major portion of which is expected to be recovered through retail and wholesale rates. There is no assurance, however, that all such costs will be recovered. The Registrants expect future compliance expenditures will continue to be significant.
 The EPA has adopted and is implementing regulations governing air and GHG emissions under the Clean Air Act and water quality under the Clean Water Act. The EPA and certain states have also adopted and continue to propose regulations governing the disposal and management of CCR at power plant sites under the Resource Conservation and Recovery Act and applicable state laws. The cost estimates for AROs related to the disposal of CCR are based on information using various assumptions
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 related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential compliance methods. The traditional electric operating companies will continue to periodically update their ARO cost estimates and those updates could be material.
 Additionally, environmental laws and regulations covering the handling and disposal of waste and release of hazardous substances could require the Southern Company system to incur substantial costs to clean up affected sites, including certain current and former operating sites, and locations subject to contractual obligations.
 Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements has occurred throughout the United States. This litigation has included, but is not limited to, claims for damages alleged to have been caused by CO2 and other emissions, CCR, releases of regulated substances, alleged exposure to regulated substances, and/or requests for injunctive relief in connection with such matters.
 Compliance with any new or revised environmental laws or regulations could affect many areas of operations for the Southern Company system. The Southern Company system's ultimate environmental compliance strategy and future environmental expenditures will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, fuel prices, and the outcome of pending and/or future legal challenges. Compliance costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, operational changes, or changing fuel sources for certain existing units, as well as related upgrades to the Southern Company system's transmission and distribution (electric and natural gas) systems. Environmental compliance spending over the next several years may differ materially from the amounts estimated and could adversely affect the Registrants if such costs cannot continue to be recovered on a timely basis. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity and natural gas. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to reduce their demand for electricity or natural gas.
 The Southern Company system may be exposed to regulatory and financial risks related to the impact of GHG legislation, regulation, and emission reduction goals.
 Concern and activism about climate change continue to increase and, as a result, demand for energy conservation and sustainable assets could further increase. Additionally, costs associated with GHG legislation, regulation, and emission reduction goals could be significant and there is no assurance such costs would be fully recovered through regulated rates or PPAs.
 The Southern Company system has processes for identifying, assessing, and responding to climate-related risks, including a scenario planning process that is used to inform resource planning decisions in the states in which the traditional electric operating companies operate. This process relies on information and assumptions from internal and external sources, which may or may not be accurate in predicting future outcomes.
 Additional GHG policies, including legislation, may emerge requiring the United States to accelerate its transition to a lower GHG emitting economy. The ultimate impact will depend on various factors, such as state adoption and implementation of requirements, natural gas prices, the development, deployment, and advancement of relevant energy technologies, the ability to recover costs through existing ratemaking provisions, and the outcome of pending and/or future legal challenges.
 The SEC has proposed new rules relating to the disclosure of climate-related matters. If the proposed rules, or similar rules, are enacted, the Registrants could incur increased costs to comply with these new rules and could face increased risk of litigation related to disclosures made pursuant to the rules.
 Because natural gas is a fossil fuel with lower carbon content relative to other fossil fuels, future carbon constraints, including, but not limited to, the imposition of a carbon tax, may create additional demand for natural gas, both for production of electricity and direct use in homes and businesses. However, such demand may be tempered by legislation limiting the use of natural gas in certain circumstances, including use in new construction and certain household appliances. Additionally, efforts to electrify the transportation, building, and other sectors may result in higher electric demand and negatively impact natural gas demand. For example, Nicor Gas' regulator, the Illinois Commission, has ordered a "future of natural gas" proceeding to explore the recommendations involved with decarbonization of the gas distribution system in Illinois. In addition, future GHG constraints, including those related to methane emissions, designed to minimize emissions from natural gas could likewise result in increased costs to the Southern Company system and affect the demand for natural gas as well as the prices charged to customers and the competitive position of natural gas.
 Southern Company has established an intermediate goal of a 50% reduction in GHG emissions from 2007 levels by 2030 and a long-term goal of net zero GHG emissions by 2050. Achievement of these goals is dependent on many factors, including natural gas prices and the pace and extent of development and deployment of low- to no-GHG energy technologies and negative carbon concepts. The strategy to achieve these goals also relies on continuing to pursue a diverse portfolio including
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 low-carbon and carbon-free resources and energy efficiency resources; customer demand for carbon-free energy; continuing to transition the Southern Company system's generating fleet and making the necessary related investments in transmission and distribution systems; continuing research and development with a particular focus on technologies that lower GHG emissions, including methods of removing carbon from the atmosphere; and constructively engaging with policymakers, regulators, investors, customers, and other stakeholders to support outcomes leading to a net zero future. There can be no guarantee that the Southern Company system will achieve these goals.
 See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Greenhouse Gases" in Item 7 herein for additional information.
 OPERATIONAL RISKS
 The financial performance of Southern Company and its subsidiaries may be adversely affected if the subsidiaries are unable to successfully operate their facilities or perform certain corporate functions.
 The financial performance of Southern Company and its subsidiaries depends on the successful operation of the electric generation, transmission, and distribution facilities, natural gas distribution facilities, and distributed generation storage technologies and the successful performance of necessary corporate functions. There are many risks that could affect these matters, including operator error or failure of equipment or processes, accidents, operating limitations that may be imposed by environmental or other regulatory requirements or in connection with joint owner arrangements, labor disputes, physical attacks, fuel or material supply interruptions and/or shortages, transmission disruption or capacity constraints, including with respect to the Southern Company system's and third parties' transmission, storage, and transportation facilities, inability to maintain reliability consistent with customer expectations as the traditional electric operating companies and Southern Power transition their generating fleets in support of the Southern Company system's net zero goal, compliance with mandatory reliability standards, including mandatory cyber security standards, implementation of new technologies, technology system failures, cyber intrusions, environmental events, such as spills or releases, supply chain disruptions, inflation, and catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events, wars, political unrest, or other similar occurrences.
 Operation of nuclear facilities involves inherent risks, including environmental, safety, health, regulatory, natural disasters, cyber intrusions, physical attacks, and financial risks, that could result in fines or the closure of the nuclear units owned by Alabama Power or Georgia Power and which may present potential exposures in excess of insurance coverage.
 Alabama Power owns, and contracts for the operation of, two nuclear units and Georgia Power holds undivided interests in, and contracts for the operation of, five existing nuclear units. The seven existing units are operated by Southern Nuclear and represented approximately 27% and 29% of the total KWHs generated by Alabama Power and Georgia Power, respectively, in the year ended December 31, 2023. In addition, Southern Nuclear, on behalf of Georgia Power and the other Vogtle Owners, is managing the construction and start-up of Plant Vogtle Unit 4. Nuclear facilities are subject to environmental, safety, health, operational, and financial risks such as: the potential harmful effects on the environment and human health and safety resulting from a release of radioactive materials; uncertainties with respect to the ability to dispose of spent nuclear fuel and the need for longer term on-site storage; uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of licensed lives and the ability to maintain and anticipate adequate capital reserves for decommissioning; limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; and significant capital expenditures relating to maintenance, operation, security, and repair of these facilities.
 Damages, decommissioning, or other costs could exceed the amount of decommissioning trusts or external insurance coverage, including statutorily required nuclear incident insurance.
 The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear facilities. In the event of non-compliance, the NRC has the authority to impose fines and/or shut down any unit, depending upon its assessment of the severity of the situation, until compliance is achieved. NRC orders or regulations related to increased security measures and any future NRC safety requirements could require Alabama Power and Georgia Power to make substantial operating and capital expenditures at their nuclear plants. In addition, if a major nuclear incident were to occur, it could result in substantial costs to Alabama Power or Georgia Power and Southern Company. A major incident at a nuclear facility anywhere in the world could cause the NRC to require additional safety measures. Moreover, a major incident at any nuclear facility in the United States, including facilities owned and operated by third parties, could require Alabama Power and Georgia Power to make material contributory payments.
 In addition, actual or potential threats of cyber intrusions or physical attacks could result in increased nuclear licensing or compliance costs.
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 Generation, transmission, and distribution of electricity and transportation and storage of natural gas involve risks that may result in accidents and other operating risks and costs.
 The Southern Company system's electric generation, transmission, and distribution and natural gas distribution and storage activities involve a variety of inherent hazards and operating risks, such as accidents, explosions, fires, mechanical problems, discharges or releases of toxic or hazardous substances or gases, and other environmental risks. These incidents could result in serious injury, loss of life, significant damage to property, environmental pollution, and disruption of the Southern Company system's operations. The location of electric generation, transmission, and distribution infrastructure and natural gas pipelines and underground natural gas storage facilities near populated areas could increase the level of damage and liability resulting from any incidents. Additionally, electric generation, transmission, and distribution infrastructure and natural gas pipelines and underground natural gas storage facilities are subject to various state and other regulatory requirements. Failure to comply with these requirements could result in substantial monetary penalties.
 Physical attacks, both threatened and actual, could impact the ability of the Subsidiary Registrants to operate.
 The Subsidiary Registrants face the risk of physical attacks, both threatened and actual, against their respective generation and storage facilities and the transmission and distribution infrastructure used to transport energy, which could negatively impact their ability to generate, transport, and deliver power, or otherwise operate their respective facilities, or, with respect to Southern Company Gas, its ability to distribute or store natural gas, or otherwise operate its facilities, in the most efficient manner or at all. Transmission and distribution infrastructure can be vulnerable to physical attack because it is often unmanned, widely dispersed, and located in isolated areas. The risk of physical attack may escalate during periods of heightened geopolitical tensions. In addition, physical attacks against third-party providers could have a similar effect on the Southern Company system.
 Despite the implementation of robust security measures, all assets are potentially vulnerable to disability, failures, or unauthorized access due to human error, natural disasters, technological failure, or internal or external physical attacks. If assets were to fail, be physically damaged, or be breached and were not restored in a timely manner, the affected Subsidiary Registrant may be unable to fulfill critical business functions. Insurance may not be adequate to cover any associated losses.
 An information security incident, including a cybersecurity breach, or the failure of, or inability to remotely access, one or more key technology systems, networks, or processes could impact the ability of the Registrants to operate.
 The Subsidiary Registrants operate in highly regulated industries that require the continued operation of sophisticated technology systems and network infrastructure, which are part of interconnected systems. Because of the critical nature of the infrastructure and the technology systems' inherent vulnerability to disability or failures due to hacking, viruses, denial of service, ransomware, acts of war or terrorism, or other types of data security breaches, the Registrants face a heightened risk of cyberattack. Remote working arrangements also increase the Registrants' data security risks. Additionally, the Registrants' field workforces use mobile technology, which have fewer security measures than the Registrants' wired networks. Portions of the Registrants' system data, architecture, and other materials may also be disclosed, either intentionally or unintentionally, to third parties and the public by regulators, employees, contractors, and vendors. This system information may be used by malicious actors to understand the Registrants' systems to prepare for a cyberattack. In addition, unpatched software or network vulnerabilities, including those resulting from the use of end-of-life operating systems, could be leveraged by an attacker.
 Cyber actors, including those associated with foreign governments, have attacked and threatened to attack energy infrastructure. Various regulators have increasingly stressed that these attacks, including ransomware attacks, and attacks targeting utility systems and other critical infrastructure, are increasing in sophistication, magnitude, and frequency. In particular, certain actors, such as nation-state and state-sponsored actors, can deploy significant resources and employ sophisticated methods to plan and carry out attacks. Risk of these attacks may escalate during periods of heightened geopolitical tensions, such as those caused by the war in Ukraine and conflicts in the Middle East.
 The Registrants and their third-party vendors have been subject, and will likely continue to be subject, to attempts to gain unauthorized access to their technology systems and confidential data or to attempts to disrupt utility and related business operations. While there have been immaterial incidents of phishing, unauthorized access to technology systems, financial fraud, and disruption of remote access across the Southern Company system, there has been no material impact on business or operations from these attacks. However, the Registrants cannot guarantee that security efforts will have the maturity to detect or prevent breaches, operational incidents, or other breakdowns of technology systems and network infrastructure. This is especially true in the event the Registrants are targeted by a sophisticated attacker with significant resources, such as a nation-state or state-sponsored actor. Further, the Registrants do not have security visibility into all operational technology communications and processes, do not maintain completely exhaustive inventories of assets and applications, and do not centrally manage or monitor all technologies, applications, and environments, which could negatively affect preparation for, investigation of, or response to an information security incident. Accordingly, the Registrants cannot provide any assurance that information security incidents will not have a material adverse effect in the future.
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 In addition, in the ordinary course of business, Southern Company and its subsidiaries collect and retain sensitive information, including personally identifiable information about customers, employees, and stockholders, and other confidential information. In some cases, administration of certain functions may be outsourced to third-party service providers. Malicious actors may target these providers to disrupt the services they provide to the Registrants, or to use those third parties to attack the Registrants. The Registrants do not fully assess the security maturity of all third-party service providers and such third-party service providers could fail to establish adequate risk management and information security measures with respect to their systems and/or could fail to timely notify the Registrants of an information security incident.
 Internal or external cyberattacks may have wide-reaching impacts due to incomplete segmentation among network assets and/or reliance of segmented networks on a disrupted network, inhibit the affected Registrant's ability to fulfill critical business functions, including energy delivery service failures, compromise sensitive and other data, violate privacy laws, and lead to customer dissatisfaction. Any cyber breach or theft, damage, or improper disclosure of sensitive electronic data may also subject the affected Registrant to penalties and claims from regulators or other third parties. Insurance may not be adequate to cover any associated losses. Additionally, the cost and operational consequences of implementing, maintaining, and enhancing system protection measures are significant, and they could materially increase to address ever changing intense, complex, and sophisticated cyber risks.
 The Southern Company system may not be able to obtain adequate natural gas, fuel supplies, and other resources required to operate the traditional electric operating companies' and Southern Power's electric generating plants or serve Southern Company Gas' natural gas customers.
 SCS, on behalf of the traditional electric operating companies and Southern Power, purchases fuel for the Southern Company system's generation fleet from a diverse set of suppliers. Southern Company Gas' primary business is the distribution of natural gas through the natural gas distribution utilities. Natural gas is delivered daily from different regions of the country. This daily supply is complemented by natural gas supplies stored in both company-owned and third party storage locations. To deliver this daily supply and stored natural gas, the Southern Company system has firm transportation capacity contracted with third party interstate pipelines. Disruption in the supply and/or delivery of fuel as a result of matters such as transportation delays, weather, labor relations, natural disasters, cyber or physical attacks, other force majeure events, or environmental regulations affecting fuel suppliers could limit the ability of the traditional electric operating companies and Southern Power to operate certain facilities, which could result in higher fuel and operating costs, and the ability of Southern Company Gas to serve its natural gas customers.
 The traditional electric operating companies are also dependent on coal, and related coal supply contracts, for a portion of their electric generating capacity. The counterparties to coal supply contracts may not fulfill their obligations to supply coal because of financial or technical problems. In addition, the suppliers and/or railroads may be delayed in supplying or delivering or may not be required to supply or deliver coal under certain circumstances, such as in the event of a natural disaster. If the traditional electric operating companies are unable to obtain their contracted coal requirements, they may be required to purchase additional coal at higher prices or limit coal generation, and these increased costs may not be recoverable through rates if deemed to be imprudently incurred. Coal deliveries continued to be delayed early in 2023, which has largely been attributed to labor shortages in the railroad industry. Service levels improved over the course of 2023 and deliveries returned to normal levels by the end of 2023. As coal-fired generating facilities are retired, the demand for coal is expected to continue to decline. As a result, railroads may commit fewer resources to coal transportation, which could increase these risks.
 Whereas fuel oil directly provides only a small portion of the Southern Company system's annual generation, its importance to the reliability of the Southern Company system's generation portfolio continues to grow. Over the last few years, related cost increases and supply chain challenges have become more common and may increase the risk of reliability challenges.
 In addition to fuel supply, the traditional electric operating companies and Southern Power also need adequate access to water, which is drawn from nearby sources, to aid in the production of electricity. Any impact to their water resources could also limit the ability of the traditional electric operating companies and Southern Power to operate certain facilities, which could result in higher fuel and operating costs.
 The revenues of Southern Company, the traditional electric operating companies, and Southern Power depend in part on sales under PPAs, the success of which depend on PPA counterparties performing their obligations, Southern Company subsidiaries satisfying minimum requirements under the PPAs, and renewal or replacement of the PPAs for the related generating capacity.
 Most of Southern Power's generating capacity has been sold to purchasers under PPAs with Southern Power's top three customers comprising approximately 19% of Southern Power's total revenues for the year ended December 31, 2023. The traditional electric operating companies have entered into PPAs with non-affiliated parties for the sale of generating capacity.
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 The revenues related to PPAs are dependent on the continued performance by the purchasers of their obligations. Although the credit evaluations undertaken and contractual protections implemented by Southern Power and the traditional electric operating companies take into account the possibility of default by a purchaser, actual exposure to a default by a purchaser may be greater than predicted or specified in the applicable contract.
 Additionally, neither Southern Power nor any traditional electric operating company can predict whether the PPAs will be renewed at the end of their respective terms or on what terms any renewals may be made. If a Registrant is unable to replace expiring PPAs with an acceptable new revenue contract, it may be required to sell the power produced by the facility at wholesale prices and be exposed to market fluctuations and risks, or the affected site may temporarily or permanently cease operations. The failure to satisfy minimum operational or availability requirements under these PPAs, including PPAs related to projects under construction, could result in payment of damages or termination of the PPAs.
 Increased competition from other companies that supply energy or generation and storage technologies and changes in customer demand for energy could negatively impact Southern Company and its subsidiaries.
 The traditional electric operating companies operate under a business model that invests capital to serve customers and recovers those investments and earns a return for investors through state regulation. Southern Power's business model is primarily focused on investing capital or building energy assets to serve creditworthy counterparties using a bilateral contract model. A key premise of these business models is that generating power at power plants achieves economies of scale and produces power at a competitive cost.
 Customers and stakeholders are increasingly focused on the Registrants' ability to meet rapidly changing demands for new and varied products, services, and offerings. Additionally, the risk of global climate change continues to shape customers' and stakeholders' sustainability goals and energy needs.
 New technologies such as distributed energy resources and microgrids and increased customer and stakeholder demand for sustainable assets could change the type of assets constructed and/or the methods for cost recovery. Advances in these technologies or changes in laws or regulations could reduce the cost of distributed generation storage technologies or other alternative methods of producing power to a level that is competitive with that of most power generation production or result in smaller-scale, more fuel efficient, and/or more cost effective distributed generation that allows for increased self-generation by customers. Broader use of distributed generation by retail energy customers may also result from customers' changing perceptions of the merits of utilizing existing generation technology or tax or other economic incentives. Additionally, a state PSC or legislature may modify certain aspects of the traditional electric operating companies' business as a result of these advances in technology, which may provide for further competition from these alternative sources of generation.
 It is also possible that rapid advances in power generation technology could reduce the value of the current electric generating facilities owned by the traditional electric operating companies and Southern Power. Changes in technology could also alter the channels through which electric customers buy or utilize power.
 Southern Company Gas' business is dependent on natural gas prices remaining competitive as compared to other forms of energy. Southern Company Gas' gas marketing services segment also is affected by competition from other energy marketers providing similar services in Southern Company Gas' unregulated service territories, most notably in Illinois and Georgia.
 If new technologies become cost competitive and achieve sufficient scale, the market share of the Subsidiary Registrants could be eroded, and the value of their respective electric generating facilities or natural gas distribution facilities could be reduced. Additionally, these technology and customer-induced changes to the Subsidiary Registrants' business models could change the risk profile of the Southern Company system's historical capital investments. Southern Company Gas' market share could be reduced if Southern Company Gas cannot remain price competitive in its unregulated markets.
 The Subsidiary Registrants are subject to workforce factors that could affect operations.
 The Southern Company system must attract, train, and retain a workforce to meet current and future needs. Events such as an aging workforce without appropriate replacements, increased cost or reduced supply of labor, mismatch of skill sets to future needs, or unavailability of contract resources may lead to operating challenges such as lack of resources, loss of knowledge, and a lengthy time period associated with skill development, including workforce needs associated with construction projects and ongoing operations. The Southern Company system may be subject to continuing workforce trends occurring in the United States triggered by decisions of employees to leave the workforce and/or their employer in higher rates during recent years as compared to prior years and challenges competing with other employers offering more flexible or fully-remote work options. The Southern Company system's costs, including costs for contractors to replace employees, productivity costs, and safety costs, may rise. The Southern Company system is also subject to risks associated with the failure to adequately manage contract resources. In addition, the failure to hire and adequately obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect Southern Company and its subsidiaries' ability to manage and operate their businesses.
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 Supply chain disruptions and inflation could negatively impact operations.
 The Southern Company system's operations and business plans depend on the global supply chain to procure equipment, materials, and other resources. The delivery of components, materials, equipment, and other resources that are critical to the Southern Company system's operations has been impacted by domestic and global supply chain disruptions. Future pandemic health events or continued international tensions, including the ramifications of regional conflicts, such as those in Ukraine and the Middle East, could further exacerbate global supply chain disruptions. These disruptions and shortages could adversely impact business operations. The constraints in the supply chain also could restrict availability and delay construction, maintenance, or repair of items needed to support normal operations or to continue planned capital investments.
 Supply chain disruptions have contributed to higher prices of components, materials, equipment, and other needed commodities, and these inflationary increases may continue. Further inflation, a continued elevated interest rate environment, or other economic factors may negatively affect operations and the timely recovery of costs.
 CONSTRUCTION RISKS
 The Registrants have incurred and may incur additional costs or delays in the construction of new plants or other facilities and may not be able to recover their investments. Also, existing facilities of the Subsidiary Registrants require ongoing expenditures, including those to meet AROs and other environmental standards and goals.
 The businesses of the Registrants require substantial expenditures for investments in new facilities as well as capital improvements, including transmission, distribution, and generation facilities for the traditional electric operating companies, generation facilities for Southern Power, and capital improvements to natural gas distribution facilities for Southern Company Gas. These expenditures also include those to settle AROs and meet environmental standards and goals. The traditional electric operating companies and Southern Power are in the process of constructing new generating facilities and/or adding environmental and other modifications to certain existing generating facilities and Southern Company Gas is replacing certain pipe in its natural gas distribution system. The traditional electric operating companies also are in the process of closing ash ponds to comply with the CCR Rule and, where applicable, state CCR rules. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, expanding and improving the electric transmission and electric and natural gas distribution systems, and undertaking projects to comply with environmental laws and regulations. These projects are long-term in nature and in some cases may include the development and construction of facilities with designs that have not been finalized or previously constructed.
 Completion of these types of projects without delays or significant cost overruns is subject to substantial risks that have occurred or may occur, including 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; challenges related to 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 interest rates or as a result of project delays.
 If a Subsidiary Registrant is unable to complete the development or construction of a project or decides to delay or cancel construction of a project, it may not be able to recover its investment in that project and may incur substantial cancellation payments under equipment purchase orders or construction contracts, as well as other costs associated with the closure and/or abandonment of the construction project.
 In addition, partnership and joint ownership agreements may provide partners or co-owners with certain decision-making authority in connection with projects under construction, including the right to cause the cancellation of a construction project under certain circumstances. Any failure by a partner or co-owner to perform its obligations under the applicable agreements could have a material negative impact on the applicable project under construction. Southern Power participates in partnership agreements with respect to a majority of its renewable energy projects and Georgia Power jointly owns Plant Vogtle Unit 4 with other co-owners. See Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information regarding other jointly-owned facilities.
 If construction projects are not completed according to specification, a Registrant may incur liabilities and suffer reduced plant efficiency, higher operating costs, and reduced net income. Furthermore, construction delays associated with renewable projects could result in the loss of otherwise available tax credits and incentives.
 Even if a construction project (including a joint venture construction project) is completed, the total costs may be higher than estimated or deemed imprudent and may be disallowed or otherwise not recoverable through regulated rates, if applicable. In
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 addition, construction delays and contractor performance shortfalls can result in the loss of revenues. The largest construction project currently underway in the Southern Company system is Plant Vogtle Unit 4. Southern Company and Georgia Power recorded cumulative pre-tax charges to income of $3.2 billion ($2.4 billion after tax) through December 31, 2023 to reflect Georgia Power's revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 herein for information regarding Plant Vogtle Units 3 and 4.
 Once facilities become operational, ongoing capital expenditures are required to maintain safe and reliable levels of operation. Significant portions of the traditional electric operating companies' existing facilities were constructed many years ago. Older equipment, even if maintained in accordance with good engineering practices, may require significant expenditures to maintain efficiency, to comply with environmental requirements, to provide safe and reliable operations, and/or to meet related retirement obligations.
 FINANCIAL, ECONOMIC, AND MARKET RISKS
 The electric generation and energy marketing operations of the traditional electric operating companies and Southern Power and the natural gas operations of Southern Company Gas are subject to changes in energy prices and fuel costs.
 The generation, energy marketing, and natural gas operations of the Southern Company system are subject to changes in energy prices and fuel costs, which could increase the cost of producing power, decrease the amount received from the sale of energy, and/or make electric generating facilities and natural gas distribution systems less competitive. The market prices for these commodities may fluctuate significantly over relatively short periods of time as a result of changes in supply and/or demand, which could increase the expenses and/or reduce the revenues of the Registrants. For the traditional electric operating companies and Southern Company Gas' regulated gas distribution operations, such impacts may not be fully recoverable through rates.
 Southern Power and the traditional electric operating companies purchase natural gas as a fuel source for their power generation needs and the natural gas distribution utilities purchase natural gas for sale to their customers. Accordingly, the price of natural gas affects, among other things, Southern Power's and the traditional electric operating companies' costs of generation and the natural gas distribution utilities' cost of natural gas. Natural gas remains a volatile commodity. Slight supply and demand imbalances can quickly result in significant price moves both up and down. These price movements may be short-lived, but the impacts can be pronounced. Natural gas supplies, primarily from the Permian and Haynesville regions, have continued to grow; however, this growth has been accompanied by LNG export growth. Forward curves project prices will remain in the range of mid-to high- $3 per mmBtu, approaching $4 per mmBtu, through 2030; however, short-term price volatility is expected and future prices could be materially impacted by various factors, including unexpected geopolitical events as well as government policies related to natural gas infrastructure development, production, and exports.
 The traditional electric operating companies and Southern Company Gas from time to time have experienced and may continue to experience underrecovered fuel and purchased power and/or purchased gas cost balances. While the traditional electric operating companies and Southern Company Gas are generally authorized to recover fuel and purchased power and/or purchased gas costs through cost recovery clauses, recovery may be delayed or may be denied if costs are deemed to be imprudently incurred.
 The Registrants are subject to risks associated with a changing economic environment, customer behaviors, including increased energy conservation, and adoption patterns of technologies by the customers of the Subsidiary Registrants.
 The consumption and use of energy are linked to economic activity. This relationship is affected over time by changes in the economy, customer behaviors, and technologies. An economic downturn could be caused by a variety of factors, including wars, geopolitical instability, acts of terrorism, political or financial crises, pandemic health events, or cyclical economic factors. Any economic downturn could negatively impact customer growth and usage per customer. Additionally, any economic downturn or disruption of financial markets, both nationally and internationally, could negatively affect the financial stability of customers and counterparties of the Subsidiary Registrants.
 Outside of economic disruptions, changes in customer behaviors in response to energy efficiency programs, changing conditions and preferences, legislation, or changes in the adoption of technologies could affect the relationship of economic activity to the consumption of energy. For example, some jurisdictions in the United States have banned the use of natural gas in new construction.
 Both federal and state programs exist to influence how customers use energy, and several of the traditional electric operating companies and natural gas distribution utilities have state PSC or other applicable state regulatory agency mandates to promote energy efficiency.
 Customers could also voluntarily reduce their consumption of energy in response to decreases in their disposable income, increases in energy prices, or individual conservation efforts.
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 In addition, the adoption of technology by customers can have both positive and negative impacts on sales. Many new technologies utilize less energy than in the past. However, electric and natural gas technologies such as electric and natural gas vehicles can create additional demand. The Southern Company system seeks to incorporate the effects of changes in customer behavior, state and federal programs, state PSC or other applicable state regulatory agency mandates, and technology, but the Southern Company system's planning processes may not accurately estimate and incorporate these effects.
 The operating results of the Registrants are affected by weather conditions and may fluctuate on a seasonal basis. In addition, catastrophic events could result in substantial damage to or limit the operation of the properties of a Subsidiary Registrant.
 Electric power and natural gas supply are generally seasonal businesses. The Subsidiary Registrants have historically sold less power and natural gas when weather conditions are milder.
 Volatile or significant weather events could result in substantial damage to the transmission and distribution lines of the traditional electric operating companies, the generating facilities of the traditional electric operating companies and Southern Power, and the natural gas distribution and underground storage facilities of Southern Company Gas, which is likely to negatively impact revenue. The Subsidiary Registrants have significant investments in the Atlantic and Gulf Coast regions and Southern Power and Southern Company Gas have investments in various states that could be subject to severe weather and natural disasters, including hurricanes and wildfires. Further, severe drought conditions can reduce the availability of water and restrict or prevent the operation of certain generating facilities. These volatile weather events may result in unexpected increases in customer load, requiring procurement of additional power at wholesale prices, or create other grid reliability issues.
 In the event a traditional electric operating company or Southern Company Gas experiences any of these weather events or any natural disaster or other catastrophic event, recovery of costs in excess of reserves and insurance coverage is subject to the approval of its state PSC or other applicable state regulatory agency. The traditional electric operating companies from time to time have experienced and may continue to experience deficits in their storm cost recovery reserve balances. Additionally, the applicable state PSC or other applicable state regulatory agency may deny or delay recovery of any portion of such costs.
 In addition, damages resulting from significant weather events occurring within a Subsidiary Registrant's service territory or otherwise affecting its customers may result in the loss of customers and reduced demand for energy for extended periods and may impact customers' ability to perform under existing PPAs.
 Acquisitions, dispositions, or other strategic ventures or investments may not result in anticipated benefits and may present risks, including risks not originally contemplated.
 Southern Company and its subsidiaries have made significant acquisitions, dispositions, and investments in the past and may continue to do so. Such actions cannot be assured to be completed or beneficial to Southern Company or its subsidiaries. Southern Company and its subsidiaries continually seek opportunities to create value through various transactions, including acquisitions or sales of assets. Specifically, Southern Power continually seeks opportunities to execute its strategy to create value through various transactions, including acquisitions, dispositions, and sales of partnership interests, development and construction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, IPPs, municipalities, and other load-serving entities, as well as commercial and industrial customers. Additionally, Southern Company Gas has made significant investments in existing pipelines, most of which are operated by third parties. If one of these agents fails to perform in a proper manner, the value of the investment could decline and Southern Company Gas could lose part or all of its investment. In addition, Southern Company Gas is required to fulfill capital obligations to pipeline joint ventures.
 Southern Company and its subsidiaries may face significant competition for transactional opportunities and anticipated transactions may not be completed on acceptable terms or at all. In addition, these transactions are intended to, but may not, result in the generation of cash or income, the realization of savings, the creation of efficiencies, or the reduction of risk.
 These transactions also involve risks, including that they may not result in an increase in income or provide adequate or expected cash flows or return on capital or other anticipated benefits; they may result in Southern Company or its subsidiaries entering into new or additional lines of business, which may have new or different business or operational risks; they may not be successfully integrated into the acquiring company's operations, internal control processes, and/or accounting systems; the due diligence conducted prior to a transaction may not uncover situations that could result in financial or legal exposure or may not appropriately evaluate the likelihood or quantify the exposure from identified risks; they may result in impairment or decreased earnings, revenues, or cash flow; they may result in credit rating downgrades for Southern Company or its subsidiaries; they may involve retained obligations in connection with transitional agreements or deferred payments related to dispositions that subject Southern Company or its subsidiaries to additional risk; Southern Company or the applicable subsidiary may not be able to achieve the expected financial benefits from the use of funds generated by any dispositions; expected benefits of a transaction may be dependent on the cooperation, performance, or credit risk of a counterparty; minority investments in growth companies may not result in a positive return on investment; or, for the traditional electric operating
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 companies and Southern Company Gas, costs associated with such investments that were expected to be recovered through regulated rates may not be recoverable.
 Southern Company and Southern Company Gas are holding companies and Southern Power owns many of its assets indirectly through subsidiaries. Each of these companies is dependent on cash flows from their respective subsidiaries to meet their ongoing and future financial obligations.
 Southern Company and Southern Company Gas are holding companies and, as such, they have no operations of their own. Substantially all of Southern Company's and Southern Company Gas' and many of Southern Power's respective consolidated assets are held by subsidiaries. Southern Company's, Southern Company Gas' and, to a certain extent, Southern Power's ability to meet their respective financial obligations, including making interest and principal payments on outstanding indebtedness, and, for Southern Company, to pay dividends on its common stock, is dependent on the net income and cash flows of their respective subsidiaries and the ability of those subsidiaries to pay upstream dividends or to repay borrowed funds. Prior to funding Southern Company, Southern Company Gas, or Southern Power, the respective subsidiaries have financial obligations and, with respect to Southern Company and Southern Company Gas, regulatory restrictions that must be satisfied, including among others, debt service. In addition, Southern Company, Southern Company Gas, and Southern Power may provide capital contributions or debt financing to subsidiaries under certain circumstances, which would reduce the funds available to meet their respective financial obligations, including making interest and principal payments on outstanding indebtedness, and to pay dividends on Southern Company's common stock.
 A downgrade in the credit ratings of any of the Registrants, Southern Company Gas Capital, or Nicor Gas could negatively affect their ability to access capital at reasonable costs and/or could require posting of collateral or replacing certain indebtedness.
 There are numerous factors that rating agencies evaluate to determine credit ratings for the Registrants, Southern Company Gas Capital, and Nicor Gas, including capital structure, regulatory environment, the ability to cover liquidity requirements, other commitments for capital, and certain other controllable and uncontrollable events. The Registrants, Southern Company Gas Capital, and Nicor Gas could experience a downgrade in their ratings if any rating agency concludes that the level of business or financial risk of the industry or the applicable company has deteriorated. Changes in ratings methodologies by the agencies could also have a negative impact on credit ratings. If one or more rating agencies downgrade any Registrant, Southern Company Gas Capital, or Nicor Gas, borrowing costs likely would increase, including potential automatic increases in interest rates or fees under applicable term loans and credit facilities, the pool of investors and funding sources would likely decrease, and, particularly for any downgrade to below investment grade, significant collateral requirements may be triggered in a number of contracts. Any credit rating downgrades could require altering the mix of debt financing currently used and could require the issuance of secured indebtedness and/or indebtedness with additional restrictive covenants binding the applicable company.
 Uncertainty in demand for energy can result in lower earnings or higher costs.
 The traditional electric operating companies and Southern Power each engage in a long-term planning process to estimate the optimal mix and timing of new generation assets required to serve future load obligations. Southern Company Gas engages in a long-term planning process to estimate the optimal mix and timing of building new pipelines, replacing existing pipelines, and entering new markets and/or expanding in existing markets. These planning processes must project many years into the future to accommodate the long lead times associated with the permitting and construction of new generation and associated transmission facilities and natural gas distribution facilities. Inherent risk exists in predicting demand as future loads are dependent on many uncertain factors, including economic conditions, customer usage patterns, efficiency programs, and customer technology adoption. Because regulators may not permit the traditional electric operating companies or the natural gas distribution utilities to adjust rates to recover the costs of new generation and associated transmission assets and/or new pipelines and related infrastructure in a timely manner or at all, these subsidiaries may not be able to fully recover these costs or may have exposure to regulatory lag associated with the time between the incurrence of costs and the recovery in customers' rates. In addition, under Southern Power's model of selling capacity and energy at negotiated market-based rates under long-term PPAs, Southern Power might not be able to fully execute its business plan if market prices drop below original forecasts. Southern Power and/or the traditional electric operating companies may not be able to extend or replace existing PPAs upon expiration, or they may be forced to market these assets at prices lower than originally intended.
 The traditional electric operating companies are currently obligated to supply power to retail customers, as well as wholesale customers under long-term PPAs. Southern Power is currently obligated to supply power to wholesale customers under long-term PPAs. At peak times, the demand for power required to meet this obligation could exceed the Southern Company system's available generation capacity. Market or competitive forces may require that the traditional electric operating companies purchase capacity in the open market or build additional generation and transmission facilities and that Southern Power purchase energy or capacity in the open market. Because regulators may not permit the traditional electric operating companies
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 to pass all of these purchase or construction costs on to their customers, the traditional electric operating companies may not be able to recover some or all of these costs or may have exposure to regulatory lag associated with the time between the incurrence of costs of purchased or constructed capacity and the traditional electric operating companies' recovery in customers' rates. Under Southern Power's long-term fixed price PPAs, Southern Power may not be able to recover all of these costs.
 The businesses of the Registrants and Nicor Gas are dependent on their ability to successfully access capital through capital markets and financial institutions.
 The Registrants and Nicor Gas rely on access to both short-term and longer-term capital markets as a significant source of liquidity to meet capital requirements not satisfied by the cash flow from their respective operations. If any of the Registrants or Nicor Gas is not able to access capital at competitive rates or on favorable terms, its ability to implement its business plan will be limited due to weakened capacity to fund capital investments or acquisitions that it may otherwise rely on to achieve future earnings and cash flows. In addition, the Registrants and Nicor Gas rely on committed credit facilities as back-up liquidity for access to low cost money markets. Certain market disruptions, whether in the United States or globally, including an economic downturn or uncertainty, continued increases in interest rates, bankruptcy or financial distress at an unrelated utility company, financial institution, or sovereign entity, capital markets volatility and disruption, either nationally or internationally, changes in tax policy, volatility in market prices for electricity and natural gas, actual or threatened cyber or physical attacks on facilities within the Southern Company system or owned by unrelated utility companies, future impacts of pandemic health events, geopolitical instability, war or threat of war, or the overall health of the utility and financial institution industries, may increase the cost of borrowing or adversely affect the ability to raise capital through the issuance of securities or other borrowing arrangements or the ability to secure committed bank lending agreements used as back-up sources of capital. Furthermore, some financial institutions may be limited in their ability to provide capital to the Registrants as a result of such financial institution's investment criteria, including criteria related to GHG.
 If sources of capital for the Registrants or Nicor Gas are reduced, capital costs could increase materially.
 Failure to comply with debt covenants or conditions could adversely affect the ability of the Registrants, SEGCO, Southern Company Gas Capital, or Nicor Gas to execute future borrowings.
 The debt and credit agreements of the Registrants, SEGCO, Southern Company Gas Capital, and Nicor Gas contain various financial and other covenants. Georgia Power's loan guarantee agreement with the DOE contains additional covenants, events of default, and mandatory prepayment events relating to the ongoing operation and/or construction of Plant Vogtle Units 3 and 4. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements.
 Volatility in the securities markets, interest rates, and other factors could substantially increase defined benefit pension and other postretirement plan costs and affect the funding available for nuclear decommissioning.
 The costs of providing pension and other postretirement benefit plans are dependent on a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plan, changes in actuarial assumptions, government regulations, and/or life expectancy, and the frequency and amount of the Southern Company system's required or voluntary contributions made to the plans. Changes in actuarial assumptions and differences between the assumptions and actual values, as well as a significant decline in the value of investments that fund the pension and other postretirement plans, if not offset or mitigated by a decline in plan liabilities, could increase pension and other postretirement expense, and the Southern Company system could be required from time to time to fund the pension plans with significant amounts of cash. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Pension and Other Postretirement Benefits" in Item 7 herein and Note 11 to the financial statements in Item 8 herein for additional information regarding the defined benefit pension and other postretirement plans. Additionally, Alabama Power and Georgia Power each hold significant assets in their nuclear decommissioning trusts to satisfy obligations to decommission their nuclear plants. The rate of return on assets held in those trusts can significantly impact both the funding available for decommissioning and the funding requirements for the trusts. See Note 6 to the financial statements under "Nuclear Decommissioning" in Item 8 herein for additional information.
 Shareholder activism could cause Southern Company to incur significant expense, hinder execution of Southern Company's business strategy, and impact Southern Company's stock price.
 Shareholder activism, which can take many forms and arise in a variety of situations, could result in substantial costs and divert management's and Southern Company's board's attention and resources. Additionally, such shareholder activism could give rise to perceived uncertainties as to Southern Company's future, adversely affect the Southern Company system's relationships with its employees, customers, regulators, or service providers, and make it more difficult to attract and retain qualified personnel. Also, Southern Company may be required to incur significant fees and other expenses related to activist shareholder matters,
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 including for third-party advisors. Southern Company's stock price could be subject to significant fluctuation or otherwise be adversely affected by the events, risks, and uncertainties of any shareholder activism.
 The Registrants are subject to risks associated with their ability to obtain adequate insurance at acceptable costs.
 The financial condition of some insurance companies, actual or threatened physical or cyber attacks, natural disasters, and an increased focus on climate issues, among other things, could have disruptive effects on insurance markets. The availability of insurance may decrease, and the insurance that the Registrants are able to obtain may have higher deductibles, higher premiums, and more restrictive policy terms. Further, the insurance policies may not cover all of the potential exposures or the actual amount of loss incurred.
 The use of derivative contracts by Southern Company and its subsidiaries in the normal course of business could result in financial losses that negatively impact the net income of the Registrants or in reported net income volatility.
 Southern Company and its subsidiaries use derivative instruments, such as swaps, options, futures, and forwards, to manage their commodity and interest rate exposures and, to a lesser extent, manage weather and foreign currency exchange rate exposure and engage in limited trading activities. The Registrants could recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform. These risks are managed through risk management policies, limits, and procedures, which might not work as planned and cannot entirely eliminate the risks associated with these activities. In addition, derivative contracts entered into for hedging purposes might not offset the underlying exposure being hedged as expected, resulting in financial losses. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management's judgment or use of estimates. The factors used in the valuation of these instruments become more difficult to predict and the calculations become less reliable further into the future. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
 See Notes 13 and 14 to the financial statements in Item 8 herein for additional information.
 Future impairments of goodwill or long-lived assets could have a material adverse effect on the Registrants' results of operations.
 Goodwill is not amortized, but is evaluated for impairment at least annually or more frequently if impairment indicators are present that would more likely than not reduce the fair value of a reporting unit below its carrying amount and long-lived assets are tested for impairment whenever events or circumstances indicate that an asset group's carrying amount may not be recoverable. At December 31, 2023, goodwill was $5.2 billion and $5.0 billion for Southern Company and Southern Company Gas, respectively.
 In addition, Southern Company and its subsidiaries have long-lived assets recorded on their balance sheets. To the extent the carrying amount of goodwill or long-lived assets become impaired, the affected Registrant may be required to incur impairment charges that could have a material impact on their results of operations. See Notes 1, 7, 9, and 15 to the financial statements in Item 8 herein for information regarding certain impairment charges at Southern Company and Southern Company Gas.

 Item 1B.UNRESOLVED STAFF COMMENTS.
 None.

 Item 1C.CYBERSECURITY.
 Cybersecurity is a critical component of Southern Company's risk management program. The Southern Company system has implemented a cybersecurity program to assess, identify, and manage risks from cybersecurity threats that may result in material adverse effects on the Southern Company system's ability to fulfill critical business functions, including energy delivery service failures, and on the confidentiality, integrity, and availability of the Southern Company system's information systems.
 Governance and Oversight of Cybersecurity Risk
 Board of Directors
 The Southern Company Board of Directors (Board), along with certain committees (primarily the Audit Committee of the Board) oversees the Southern Company system's enterprise risk management process. The Board devotes significant time and attention to overseeing cybersecurity risk, and the Southern Company system's approach to cybersecurity governance establishes oversight throughout the enterprise. The Board has delegated the primary responsibility to oversee cybersecurity matters to the Business Security and Resiliency Committee (BSRC) of the Board. Having a committee like the BSRC, focused on and dedicated to security, is a strong governance practice. Comprised solely of independent members of the Board, the BSRC is charged with oversight of risks related to cybersecurity, physical security, and operational resiliency. The BSRC
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 includes directors with an understanding of cyber issues. The BSRC meets at every regular Board meeting and when needed in the event of a specific threat or emerging issue. The Chair of the BSRC regularly reports to the Board in connection with key matters the BSRC considered. The BSRC routinely receives presentations on a range of topics, including the threat environment and vulnerabilities and risks, policies, practices, technology trends, and regulatory developments, from the Chief Information Security Officer (CISO) and the legal organization and, as needed, the Chief Information Officer (CIO). The CISO reports to the BSRC at each regular committee meeting. Protocols have been established by which certain cybersecurity incidents are escalated internally and, where appropriate, reported to the BSRC, and ongoing updates regarding any such incident are provided until it has been resolved. See "Incident Response" herein.
 Management
 The Southern Company system has implemented a cross-functional, risk-based, "defense-in-depth" approach to preventing, detecting, identifying, mitigating, responding to, and recovering from cybersecurity threats and incidents, while also implementing controls and procedures that provide for the prompt escalation of certain cybersecurity incidents so that decisions regarding the public disclosure and reporting of such incidents can be made by management in a timely manner. Overall network efforts are led by the CISO and the Technology Security Organization (TSO), the organization responsible for implementing, monitoring, and maintaining cybersecurity practices across the Southern Company system, and aided by the Executive Vice President of Operations and the Energy Management System and Generation organization. The CISO meets regularly with the CIO and the Chief Executive Officer and reports regularly to committees of the Board to discuss risk management measures implemented to identify and mitigate data protection and cybersecurity risks. Security and resiliency are emphasized through business assurance, enterprise risk management, and incident response plans designed to identify, evaluate, and remediate incidents when they occur. Among other things, the Cybersecurity Incident Response Plan (CIRP) establishes a team comprised of the CISO, the Deputy CISO, the Director of the Digital Defense Center, and members of the legal and compliance organizations to evaluate emerging cyber threats and escalate to executive management and business units as appropriate. Plans, policies, and technologies are regularly updated and training exercises and crisis management preparedness activities are conducted to test effectiveness.
 The CISO works closely with the legal and compliance organizations, as well as the relevant business units, to help ensure broad oversight of and compliance with legal, regulatory, and contractual cybersecurity requirements. The CISO has extensive cybersecurity knowledge and skills gained from over 30 years of work experience within the Southern Company system. The CISO receives reports on cybersecurity threats from a variety of sources both internally and externally on an ongoing basis and regularly reviews risk management measures implemented to identify and mitigate cybersecurity risks. Briefings to the Board on cybersecurity matters include annual briefings to the Audit Committee and the Operations, Environmental, and Safety Committee in addition to briefings to the BSRC at each of its regular meetings (at least five times annually).
 Internal Cybersecurity Team
 The TSO, led by the CISO, is responsible for the implementation, monitoring, and maintenance of the cybersecurity and data protection practices across the Southern Company system. The Southern Company system also relies on a Data Privacy and Protection team in the compliance organization, as well as the internal audit organization, to work with the TSO on data protection policies and practices. Multiple experienced information security leaders with internal and external security experience responsible for various parts of the business report to the CISO, each of whom is supported by a team of trained cybersecurity professionals. In addition to these internal cybersecurity capabilities, external auditors and security companies are regularly engaged to assist with assessing, testing, identifying, and managing cybersecurity, including through penetration testing, vulnerability testing, and other technical evaluations.
 Risk Management and Strategy
 Although many of the networks are segmented, overall network security is a centralized shared service across the Southern Company system, led by the TSO and the CISO. Recognizing that no single technology, process, or business control can effectively prevent or mitigate all risks related to cyber threats, multiple technologies, processes, and controls, all working independently but as part of a cohesive strategy, are employed to reduce risk. Southern Company system exposure and defenses are regularly tested through auditing, penetration testing, vulnerability testing, and other exercises designed to assess effectiveness.
 The Southern Company system emphasizes both security and resiliency through business assurance and incident response plans designed to identify, evaluate, and remediate incidents when they occur. A 24/7 security operations center is also utilized, which facilitates real-time situational awareness across the cyber-threat environment, and a robust insider threat protection program that leverages cross-function information sharing to assess insider threat activity is employed. The Southern Company system regularly reviews and updates its plans, policies, and technologies and conducts regular training exercises and crisis management preparedness activities to test their effectiveness. In addition, a security awareness program for the Southern
 I-27

 Company system's employees has also been implemented, which is designed to educate and train employees at least annually, or more often as needed, about risks inherent to human interaction with information and operational technology.
 The Southern Company system's cybersecurity program is increasingly leveraging intelligence-sharing capabilities about emerging threats within the energy industry, across other industries, with specialized vendors, and through public-private partnerships with U.S. government intelligence agencies. By engaging with both the Electricity Information Sharing and Analysis Center and the Downstream Natural Gas Information Sharing and Analysis Center, the Southern Company system benefits from quality analysis and rapid sharing of security information across the energy sector. Such intelligence helps to allow for better detection and prevention of emerging cyber threats before they materialize. Just as it tests its policies and plans internally, the Southern Company system also engages in external exercises such as the bi-annual GridEx Security Exercise to evaluate and address the preparedness of the industry as a whole.
 Many cybersecurity policies and standards across the Southern Company system are governed by multiple regulatory requirements. Portions of these policies and standards are audited by the FERC, the Transportation Security Administration, and the NRC, as appropriate, and are periodically evaluated by third parties such as cybersecurity insurance carriers. Certain members of senior management have high-level security clearances to facilitate access to critical information, and the Southern Company system participates in pilot programs with industry and the U.S. government to share additional information and strengthen cybersecurity and business resiliency.
 The Southern Company system also employs systems and processes designed to oversee, identify, and reduce the potential impact of a security incident at a third-party vendor, service provider, or customer or otherwise implicating the third-party technology and systems used. Among other things, the Southern Company system has established a Vendor Security Incident Working Group to address such third-party security incidents, including following up with the third party as appropriate and taking steps to mitigate any impact to systems. The Vendor Security Incident Working Group includes members of the internal cybersecurity teams to address any incidents that may invoke the CIRP. Additionally, the Southern Company system typically imposes contractual obligations on vendors and other third-party business partners related to privacy, confidentiality, and data security based on their access to the Southern Company system's data and systems. The Southern Company system also maintains insurance coverage for cyber incidents; the scope of coverage and fitness of coverage is evaluated each year.
 Incident Response
 The Southern Company system has adopted a CIRP that applies in the event of certain cybersecurity threats or incidents to provide a standardized guide for responding to security incidents. The CIRP sets out a coordinated approach to investigating, containing, documenting, and mitigating incidents, including reporting findings and keeping senior management and other key stakeholders informed and involved as appropriate. In general, the incident response process follows the National Institute of Standards and Technology guidance and focuses on four phases: preparation; detection and analysis; containment, eradication, and recovery; and post-incident remediation. The CIRP is reviewed periodically to help ensure its applicability to any changing needs or circumstances and to provide users a tactical tool to effectively respond to incidents. The CIRP applies to all Southern Company system personnel (including third-party contractors, vendors, and partners) that perform functions or services requiring access to secure Southern Company system information and to all devices and network services that are owned or managed by the Southern Company system. A full tabletop exercise is performed at least annually, including stakeholders from business units beyond technology security, such as power delivery, legal, compliance, risk management, and corporate communications. In addition, the Southern Company system participates in sector-level and cross-sector exercises led by industry or the U.S. government. In the event of an incident, the technology security organization, the legal organization, and other stakeholders frequently review lessons learned after an incident has been remediated.
 Material Cybersecurity Risks, Threats, and Incidents
 Due to evolving cybersecurity threats, it has and will continue to be difficult to prevent, detect, mitigate, and remediate cybersecurity incidents. Risks from cybersecurity threats, including as a result of any previous cybersecurity incidents, have not materially affected the Southern Company system, including its business strategy, results of operations, or financial condition. While the Southern Company system has not experienced any material cybersecurity incidents, there can be no guarantee that it will not be the subject of future successful attacks, threats, or incidents. Additional information on cybersecurity risks can be found in Item 1A "Risk Factors" of this Form 10-K which should be read in conjunction with the foregoing information.
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 Item 2. PROPERTIES
 At December 31, 2023, the traditional electric operating companies, Southern Power, and SEGCO owned and/or operated the generating facilities listed in the table below. The traditional electric operating companies have certain jointly-owned generating stations. For these facilities, the nameplate capacity shown represents the Registrant's portion of total plant capacity, with ownership percentages provided if less than 100%. See "Jointly-Owned Facilities" and "Titles to Property" herein and Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information.

 Coal

 Barry Unit 5
 Mobile, AL
 700,000

 Gaston Unit 5
 Wilsonville, AL
 880,000

 Miller (95.92%)
 Birmingham, AL
 2,532,288

 Total Coal
 4,112,288

 Combined Cycle:

 Barry Units 6 through 8

 Mobile, AL
 1,706,424

 Central Alabama Generating Station
 Autauga County, AL
 885,000

 Combustion Turbine:

 Calhoun Generating Station
 Calhoun County, AL
 748,000

 Greene County
 Demopolis, AL
 720,000

 Steam:

 Barry Units 1, 2, and 4
 Mobile, AL
 600,000

 Greene County Units 1 and 2 (60%)
 Demopolis, AL
 300,000

 Total Natural Gas
 4,959,424

 Farley
 Dothan, AL
 1,720,000

 Hydro

 Bankhead
 Holt, AL
 53,985

 Bouldin
 Wetumpka, AL
 225,000

 Harris
 Wedowee, AL
 132,000

 Henry
 Ohatchee, AL
 72,900

 Holt
 Holt, AL
 46,944

 Jordan
 Wetumpka, AL
 100,000

 Lay
 Clanton, AL
 177,000

 Lewis Smith
 Jasper, AL
 157,500

 Logan Martin
 Vincent, AL
 135,000

 Martin
 Dadeville, AL
 182,000

 Mitchell
 Verbena, AL
 170,000

 Thurlow
 Tallassee, AL
 81,000

 Weiss
 Leesburg, AL
 87,750

 Yates
 Tallassee, AL
 47,000

 Total Hydro
 1,668,079

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 Cogeneration

 Lowndes County
 Burkeville, AL
 104,800

 Theodore
 Theodore, AL
 236,418

 Washington County
 Washington County, AL
 123,428

 Total Cogeneration
 464,646

 Solar

 Anniston Army Depot
 Dale County, AL
 7,380

 Fort Rucker
 Calhoun County, AL
 10,560

 Total Solar
 17,940

 Total Alabama Power Generating Capacity
 12,942,377

 Combined Cycle:

 McDonough-Atkinson Units 4 through 6
 Atlanta, GA
 2,520,000

 McIntosh Units 10 and 11
 Effingham County, GA
 1,318,920

 Combustion Turbine:

 McDonough Unit 3
 Atlanta, GA
 78,800

 McIntosh Units 1 through 8
 Effingham County, GA
 640,000

 McManus
 Brunswick, GA
 481,700

 Robins
 Warner Robins, GA
 158,400

 Wilson
 Augusta, GA
 354,100

 Steam:

 Yates
 Newnan, GA
 700,000

 Total Natural Gas
 6,251,920

 Coal

 Bowen
 Cartersville, GA
 3,160,000

 Scherer (8.4% of Units 1 and 2 and 75% of Unit 3)
 Macon, GA
 750,924

 Total Coal
 3,910,924

 Hatch (50.1%)
 Baxley, GA
 899,612

 Vogtle Units 1 through 3 (45.7%)

 Augusta, GA
 1,613,667

 Total Nuclear
 2,513,279

 Hydro

 Bartletts Ferry
 173,000

 Burton
 Clayton, GA
 8,100

 Flint River
 Albany, GA
 5,400

 Goat Rock
 40,500

 Lloyd Shoals
 Jackson, GA
 18,000

 Morgan Falls
 Atlanta, GA
 16,800

 Nacoochee
 Lakemont, GA
 4,800

 North Highlands
 29,600

 Oliver Dam
 60,000

 Rocky Mountain (25.4%)
 Rome, GA
 229,362
 (b)

 Sinclair Dam
 Milledgeville, GA
 45,000

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 Tallulah Falls
 Clayton, GA
 72,000

 Terrora
 Clayton, GA
 20,800

 Tugalo
 Clayton, GA
 45,000

 Wallace Dam
 Eatonton, GA
 321,300

 Yonah
 Toccoa, GA
 22,500

 Total Hydro
 1,112,162

 Solar

 Fort Benning
 30,005

 Fort Gordon
 Augusta, GA
 30,000

 Fort Stewart
 Fort Stewart, GA
 30,000

 Fort Valley
 Fort Valley, GA
 10,800

 Kings Bay
 Camden County, GA
 30,161

 Marine Corps Logistics Base
 Albany, GA
 31,161

 Moody Air Force Base
 Valdosta, GA
 49,500

 Robins Air Force Base
 Warner Robins, GA
 128,000

 8 Other Plants
 Various Georgia locations
 18,479

 Total Solar
 358,106

 Total Georgia Power Generating Capacity
 14,146,391

 Combined Cycle:

 Daniel
 Pascagoula, MS
 1,070,424

 Ratcliffe
 Kemper County, MS
 769,898

 Combustion Turbine:

 Sweatt
 Meridian, MS
 39,400

 Watson
 Gulfport, MS
 39,360

 Steam:

 Greene County Units 1 and 2 (40%)
 Demopolis, AL
 200,000

 Watson
 Gulfport, MS
 750,000

 Total Natural Gas
 2,869,082

 Coal

 Daniel (50%)
 Pascagoula, MS
 500,000

 Cogeneration

 Chevron Cogenerating Station
 Pascagoula, MS
 147,292
 (c)

 Solar

 Walnut Grove

 Walnut Grove, MS

 1,500

 Total Mississippi Power Generating Capacity
 3,517,874

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 Combined Cycle:

 Franklin
 Smiths, AL
 1,857,820

 Harris
 Autaugaville, AL
 1,318,920

 Rowan Unit 4
 Salisbury, NC
 530,550

 Wansley Units 6 and 7
 Carrollton, GA
 1,073,000

 Combustion Turbine:

 Addison
 Thomaston, GA
 668,800

 Cleveland
 Cleveland County, NC
 720,000

 Dahlberg
 Jackson County, GA
 756,000

 Rowan Units 1 through 3
 Salisbury, NC
 455,250

 Total Natural Gas
 7,380,340

 Wind

 Beech Ridge II
 Greenbrier County, WV
 56,200

 Bethel
 Castro County, TX
 276,000

 Cactus Flats
 Concho County, TX
 148,350

 Deuel Harvest
 Deuel County, SD
 301,100

 Glass Sands
 Murray County, OK
 118,300

 Grant Plains
 Grant County, OK
 147,200

 Grant Wind
 Grant County, OK
 151,800

 Kay Wind
 Kay County, OK
 299,000

 Passadumkeag
 Penobscot County, ME
 42,900

 Reading
 Osage & Lyon Counties, KS
 200,100

 Salt Fork
 Donley & Gray Counties, TX
 174,000

 Skookumchuck
 Lewis & Thurston Counties, WA
 136,800

 Tyler Bluff
 Cooke County, TX
 125,580

 Wake Wind
 Crosby & Floyd Counties, TX
 257,250

 Wildhorse Mountain
 Pushmataha County, OK
 100,000

 Total Wind
 2,534,580
 (d)

 Solar

 Adobe

 Apex
 North Las Vegas, NV

 Boulder I
 Clark County, NV
 100,000

 Butler
 Taylor County, GA
 104,000

 Butler Solar Farm
 Taylor County, GA
 22,000

 Calipatria
 Imperial County, CA

 Campo Verde
 Imperial County, CA
 147,420

 Cimarron
 Colfax County, NM
 30,640

 Decatur County
 Decatur County, GA

 Decatur Parkway
 Decatur County, GA
 84,000

 Desert Stateline
 San Bernadino County, CA
 299,990

 East Pecos
 Pecos County, TX
 120,000

 Garland
 205,290

 Gaskell West I

 Granville
 Granville County, NC
 2,500

 Henrietta
 Kings County, CA
 102,000

 Imperial Valley
 Imperial County, CA
 163,200

 Lamesa
 Dawson County, TX
 102,000

 Lost Hills-Blackwell
 32,000

 I-32

 Macho Springs
 Luna County, NM
 55,000

 Morelos del Sol
 15,000

 North Star
 Fresno County, CA
 61,600

 Pawpaw
 Taylor County, GA
 30,480

 Roserock
 Pecos County, TX
 160,000

 Rutherford
 Rutherford County, NC
 74,800

 Sandhills
 Taylor County, GA
 148,000

 Spectrum
 Clark County, NV
 30,240

 Tranquillity
 Fresno County, CA
 205,300

 Total Solar
 2,395,460
 (e)

 Battery Storage

 Garland
 88,000
 (f)

 Tranquillity
 Fresno County, CA
 72,000
 (f)

 Total Battery Storage
 160,000

 Fuel Cell

 Red Lion and Brookside
 New Castle and Newark, DE
 27,500
 (g)

 Total Southern Power Generating Capacity
 12,497,880

 SEGCO

 Gaston Units 1 through 4 (Natural Gas-Steam)
 Wilsonville, AL
 1,000,000

 Gaston (Natural Gas-Combustion Turbine)
 Wilsonville, AL
 19,680

 Total SEGCO Generating Capacity
 1,019,680
 (h)

 Southern Company System

 22,480,446

 Coal
 8,523,212

 4,233,279

 Hydro
 2,780,241

 Solar
 2,773,006

 Wind
 2,534,580

 Cogeneration
 611,938

 Battery Storage
 160,000

 Fuel Cell
 27,500

 Total Southern Company System Generating Capacity
 44,124,202

 (a)Represents the primary fuel source.
 (b)Operated by OPC.
 (c)Generation is dedicated to a single industrial customer. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" in Item 7 herein.
 (d)Southern Power is the controlling partner in a non-tax equity partnership for Beech Ridge II and also owns 100% of Glass Sands. Southern Power is the controlling partner in tax equity partnerships owning Cactus Flats, Deuel Harvest, Reading, Skookumchuck, and Wildhorse Mountain (additionally for Deuel Harvest and Skookumchuck, a noncontrolling interest in Southern Power's remaining equity is owned by another partner). Southern Power is the controlling partner in SP Wind (a tax equity partnership owning the remaining eight Southern Power wind facilities). SP Wind is the 90.1% majority owner of Wake Wind and owns 100% of the other SP Wind facilities. All of these entities are consolidated subsidiaries of Southern Power and the capacity shown in the table is 100% of the nameplate capacity for the respective facility.
 (e)Southern Power owns a 67% equity interest in SP Solar (a limited partnership indirectly owning all of Southern Power's solar facilities, except the Gaskell West I and Roserock solar facilities). SP Solar is the 51% majority owner of Boulder I, Garland, Henrietta, Imperial Valley, Lost Hills Blackwell, North Star, and Tranquillity solar facilities; the 66% majority owner of Desert Stateline solar facility; and the sole owner of the remaining SP Solar solar facilities. Southern Power is the controlling partner in a tax equity partnership owning Gaskell West I and also owns 100% of Roserock. All of these entities are consolidated subsidiaries of Southern Power and the capacity shown in the table is 100% of the nameplate capacity for the respective facility.
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 (f)Southern Power is the controlling partner in a tax equity partnership owning the Garland and Tranquillity battery energy storage facilities. Additionally, the noncontrolling interests in Southern Power's remaining equity are owned by two other partners and the facilities are indirect subsidiaries of SP Solar. These entities are consolidated subsidiaries of Southern Power and the capacity shown in the table is 100% of the nameplate capacity for the respective facility.
 (g)Southern Power has two noncontrolling interest partners that own approximately 10 MWs of the facility. These entities are consolidated subsidiaries of Southern Power and the capacity shown in the table is 100% of the nameplate capacity for the respective facility.
 (h)Alabama Power and Georgia Power each own 50% of the outstanding common stock of SEGCO, an operating public utility company. Alabama Power and Georgia Power are each entitled to one-half of SEGCO's capacity and energy. Alabama Power acts as SEGCO's agent in the operation of SEGCO's units and furnishes fuel to SEGCO for its units. See Note 7 to the financial statements under "SEGCO" in Item 8 herein for additional information.
 See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" in Item 7 herein and Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order," "Georgia Power – Integrated Resource Plans," and "Mississippi Power – Integrated Resource Plan" in Item 8 herein for information regarding plans to retire or convert to natural gas certain coal-fired generating capacity included in the table above.
 Except as discussed below under "Titles to Property," the principal plants and other important units of the traditional electric operating companies, Southern Power, and SEGCO are owned in fee by the respective companies. It is the opinion of management of each such company that its operating properties are adequately maintained and are substantially in good operating condition, and suitable for their intended purpose.
 Mississippi Power owns a 79-mile length of 500-kilovolt transmission line which is leased to Entergy Gulf States Louisiana, LLC. The line extends from Plant Daniel to the Louisiana state line. Entergy Gulf States Louisiana, LLC is paying a use fee covering all expenses and the amortization of the capitalized costs through the expiration of the agreement between the parties on May 31, 2024. At December 31, 2023, the unamortized portion was approximately $1 million.
 Mississippi Power owns a lignite mine that was intended to provide fuel for the Kemper IGCC. Liberty Fuels Company, LLC, the operator of the mine, has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. As a result of the abandonment of the Kemper IGCC, final mine reclamation began in 2018 and was substantially completed in 2020, with monitoring expected to continue through 2028. See Note 3 to the financial statements under "Other Matters – Mississippi Power – Kemper County Energy Facility" in Item 8 herein for additional information.
 In conjunction with Southern Company's 2019 sale of Gulf Power, Mississippi Power and NextEra Energy agreed to negotiate a mutually acceptable revised operating agreement for Plant Daniel. In July 2022, the co-owners executed a revised operating agreement. The dispatch procedures in the revised operating agreement for the two jointly-owned coal units at Plant Daniel resulted in Mississippi Power designating one of the two units as primary and the other as secondary in lieu of each company separately owning 100% of a single generating unit. Mississippi Power did not exercise an option to purchase its co-owner's ownership interest for $1 on January 15, 2024. See Notes 2 and 3 under "Mississippi Power – Integrated Resource Plan" and "Other Matters – Mississippi Power – Plant Daniel," respectively, in Item 8 herein for additional information on Plant Daniel.
 In 2023, the maximum demand on the traditional electric operating companies, Southern Power Company, and SEGCO was 36,919,000 KWs and occurred on August 14, 2023. The all-time maximum demand of 37,035,000 KWs occurred on June 15, 2022. These amounts exclude demand served by capacity retained by MEAG Power, OPC, and SEPA. The reserve margin for the traditional electric operating companies, Southern Power Company, and SEGCO in 2023 was 19%.
 Jointly-Owned Facilities
 Alabama Power, Georgia Power, and Mississippi Power at December 31, 2023 had undivided interests in certain generating plants and other related facilities with non-affiliated parties. The percentages of ownership of the total plant or facility are as follows:

 Percentage Ownership

 Total
Capacity
Power
 Power
South
Power
Power
 OPC
 MEAG
Power
 Dalton
 FP&L

 (MWs)

 Plant Miller Units 1 and 2
 1,320
 91.8
 %
 8.2
 %
 —
 %
 —
 %
 —
 %
 —
 %
 —
 %
 —
 %

 Plant Hatch
 1,796
 —
 —
 50.1
 —
 30.0
 17.7
 2.2
 —

 Plant Vogtle Units 1 through 3

 3,531
 —
 —
 45.7
 —
 30.0
 22.7
 1.6
 —

 Plant Scherer Units 1 and 2
 1,636
 —
 —
 8.4
 —
 60.0
 30.2
 1.4
 —

 Plant Scherer Unit 3
 —
 —
 75.0
 —
 —
 —
 —
 25.0

 Rocky Mountain
 —
 —
 25.4
 —
 74.6
 —
 —
 —

 Plant Daniel Units 1 and 2
 1,000
 —
 —
 —
 50.0
 —
 —
 —
 50.0

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 Alabama Power, Georgia Power, and Mississippi Power have contracted to operate and maintain the respective units in which each has an interest (other than Rocky Mountain) as agent for the joint owners. Southern Nuclear operates and provides services to Alabama Power's and Georgia Power's nuclear plants.
 In addition, Georgia Power has commitments, in the form of capacity purchases totaling $39 million, regarding a portion of a 5% interest in the original cost of Plant Vogtle Units 1 and 2 owned by MEAG Power that are in effect until the later of the retirement of the plant or the latest stated maturity date of MEAG Power's bonds issued to finance such ownership interest. See Note 3 to the financial statements under "Commitments" in Item 8 herein for additional information.
 Construction continues on Plant Vogtle Units 3 and 4, which are jointly owned by the Vogtle Owners (with each owner currently holding the same undivided ownership interest as shown in the table above with respect to Plant Vogtle Units 1 and 2). See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 herein.
 Titles to Property
 The traditional electric operating companies', Southern Power's, and SEGCO's interests in the principal plants and other important units of the respective companies are owned in fee by such companies, subject to the following major encumbrances: (1) a leasehold interest granted by Mississippi Power's largest retail customer, Chevron Products Company (Chevron), at the Chevron refinery, where five combustion turbines owned by Mississippi Power are located and used for co-generation, as well as liens on these assets pursuant to the related co-generation agreements and (2) liens associated with Georgia Power's reimbursement obligations to the DOE under its loan guarantee, which are secured by a first priority lien on (a) Georgia Power's undivided ownership interest in Plant Vogtle Units 3 and 4 and (b) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. See Note 5 to the financial statements under "Assets Subject to Lien" and Note 8 to the financial statements under "Long-term Debt" in Item 8 herein for additional information. The traditional electric operating companies own the fee interests in certain of their principal plants as tenants in common. See "Jointly-Owned Facilities" herein and Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information. Properties such as electric transmission and distribution lines, steam heating mains, and gas pipelines are constructed principally on rights-of-way, which are maintained under franchise or are held by easement only. A substantial portion of lands submerged by reservoirs is held under flood right easements. In addition, certain of the renewable generating facilities occupy or use real property that is not owned, primarily through various leases, easements, rights-of-way, permits, or licenses from private landowners or governmental entities.

 Southern Company Gas considers its properties to be adequately maintained, substantially in good operating condition, and suitable for their intended purpose. The following sections provide the location and general character of the materially important properties that are used by the segments of Southern Company Gas. Substantially all of Nicor Gas' properties are subject to the lien of the indenture securing its first mortgage bonds. See Note 8 to the financial statements in Item 8 herein for additional information.
 Distribution and Transmission Mains
 Southern Company Gas' distribution systems transport natural gas from its pipeline suppliers to customers in its service areas. These systems consist primarily of distribution and transmission mains, compressor stations, peak shaving/storage plants, service lines, meters, and regulators. At December 31, 2023, Southern Company Gas' gas distribution operations segment owned approximately 77,900 miles of underground distribution and transmission mains, which are located on easements or rights-of-way that generally provide for perpetual use.
 Storage Assets
 Southern Company Gas owns and operates eight underground natural gas storage fields in Illinois with a total working capacity of approximately 150 Bcf, approximately 135 Bcf of which is usually cycled on an annual basis. This system is designed to meet about 50% of the estimated peak-day deliveries and approximately 40% of the normal winter deliveries in Illinois. This level of storage capability provides Nicor Gas with supply flexibility, improves the reliability of deliveries, and helps mitigate the risk associated with seasonal price movements.
 Southern Company Gas also has four LNG plants located in Georgia and Tennessee with total LNG storage capacity of approximately 7.0 Bcf. In addition, Southern Company Gas owns two propane storage facilities in Virginia, each with storage capacity of approximately 0.3 Bcf. The LNG plants and propane storage facility are used by Southern Company Gas' gas distribution operations segment to supplement natural gas supply during peak usage periods.
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 All Other
 In September 2022, certain affiliates of Southern Company Gas entered into agreements to sell two natural gas storage facilities located in California and Texas. The sale of the Texas facility was completed in November 2022 and the sale of the California facility was completed on September 22, 2023. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 herein for additional information.
 Jointly-Owned Properties
 Southern Company Gas' gas pipeline investments segment has a 50% undivided ownership interest in a 115-mile pipeline facility in northwest Georgia. Southern Company Gas also has an agreement to lease its 50% undivided ownership in the pipeline facility. See Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information.

 Item 3.LEGAL PROCEEDINGS
 See Note 3 to the financial statements in Item 8 herein for descriptions of legal and administrative proceedings discussed therein. The Registrants' threshold for disclosing material environmental legal proceedings involving a governmental authority where potential monetary sanctions are involved is $1 million.

 Item 4.MINE SAFETY DISCLOSURES
 Not applicable.
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 INFORMATION ABOUT OUR EXECUTIVE OFFICERS – SOUTHERN COMPANY
 (Identification of executive officers of Southern Company is inserted in Part I in accordance with Regulation S-K, Item 401) The ages of the officers set forth below are as of December 31, 2023.
 Age 65
 First elected in 2008. President since March 2023, Chief Executive Officer since May 2023, and Chairman since December 2023. Previously served as Chairman and Chief Executive Officer of Georgia Power from June 2021 to March 2023, President of Georgia Power from November 2020 to March 2023, and Executive Vice President and President of External Affairs of Southern Company from January 2009 to October 2020.
 Daniel S. Tucker
 Executive Vice President and Chief Financial Officer
 Age 53
 First elected in 2021. Executive Vice President and Chief Financial Officer since September 2021. Previously served as Executive Vice President, Chief Financial Officer, and Treasurer of Georgia Power from January 2021 to September 2021, and Executive Vice President and Chief Financial Officer of Southern Company Gas from January 2019 to January 2021.
 Bryan D. Anderson
 Executive Vice President
 Age 57
 First elected in 2020. Executive Vice President and President of External Affairs since January 2021. Executive Vice President of SCS since November 2020. Previously served as Senior Vice President of SCS with responsibility for governmental affairs from January 2015 to November 2020.
 Stanley W. Connally, Jr.
 Executive Vice President
 Age 54
 First elected in 2012. Executive Vice President since April 2021. Chairman, President, and Chief Executive Officer of SCS since April 2021. Previously served as Executive Vice President for Operations of SCS from June 2018 to April 2021.
 Christopher Cummiskey
 Executive Vice President
 Age 49
 First elected in 2021. Executive Vice President since January 2021. Chairman of Southern Power since February 2021 and Executive Vice President of SCS, Chief Executive Officer of Southern Power, and President and Chief Executive Officer of Southern PowerSecure Holdings, Inc. and Southern Holdings since July 2020. Previously served as Executive Vice President, External Affairs of Georgia Power from May 2015 to June 2020.
 Martin B. Davis
 Executive Vice President and Chief Information Officer
 Age 60
 First elected in 2021. Executive Vice President since April 2021. Chief Information Officer and Executive Vice President of SCS since July 2015. Previously served as Vice President from July 2015 through April 2021.
 Kimberly S. Greene
 Chairman, President, and Chief Executive Officer of Georgia Power
 Age 57
 First elected in 2013. Chairman, President, and Chief Executive Officer of Georgia Power since April 2023. Previously served as Chairman, President, and Chief Executive Officer of Southern Company Gas from June 2018 to March 2023.
 James Y. Kerr II
 Chairman, President, and Chief Executive Officer of Southern Company Gas
 Age 59
 First elected in 2014. Chairman, President, and Chief Executive Officer of Southern Company Gas since April 2023. Previously served as Executive Vice President, Chief Legal Officer, and Chief Compliance Officer of Southern Company from March 2014 to March 2023.
 I-37

 Stephen E. Kuczynski
 Chairman and Chief Executive Officer of Southern Nuclear
 Age 61
 First elected in 2011. Chairman and Chief Executive Officer of Southern Nuclear since July 2011. Previously served as President of Southern Nuclear from July 2011 through March 2023.
 J. Jeffrey Peoples
 Chairman, President, and Chief Executive Officer of Alabama Power
 Age 64
 First elected in 2023. Chairman, President, and Chief Executive Officer of Alabama Power since January 2023. Previously served as Executive Vice President of Customer and Employee Services of Alabama Power from June 2020 to January 2023, Senior Vice President of Employee Services and Labor Relations of Alabama Power from June 2018 to June 2020, and Executive Vice President and Chief Administrative Officer of Southern Company Gas and President of AGL Services Company from September 2018 to June 2020.
 Sterling A. Spainhour
 Executive Vice President and Chief Legal Officer
 Age 55
 First elected in 2023. Executive Vice President and Chief Legal Officer since April 2023. Previously served as Chief Compliance Officer of Southern Company from April 2023 to January 2024, Senior Vice President, General Counsel, Corporate Secretary, and Chief Compliance Officer of Georgia Power from June 2020 to March 2023, Senior Vice President and General Counsel – East of SCS from July 2020 to March 2023, and Senior Vice President and General Counsel of SCS from December 2016 to July 2020.
 Anthony L. Wilson
 Chairman, President, and Chief Executive Officer of Mississippi Power
 Age 59
 First elected in 2015. President of Mississippi Power since October 2015 and Chief Executive Officer and Director since January 2016. Chairman of Mississippi Power's Board of Directors since August 2016.

 Each officer listed above was elected at the annual meeting (or by written consent in lieu of the annual meeting) of the board of directors of the applicable company, to serve until the next such annual meeting or until his or her successor is elected and qualified, except for Mr. Womack who was elected as Chairman on December 11, 2023.
 I-38

 Item 5.MARKET FOR REGISTRANTS' COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
 (a)(1) The common stock of Southern Company is listed and traded on the NYSE under the ticker symbol SO. The common stock is also traded on regional exchanges across the U.S.
 There is no market for the other Registrants' common stock, all of which is owned by Southern Company.
 (a)(2) Number of Southern Company's common stockholders of record at January 31, 2024: 95,412
 Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of common stock were $2.78 in 2023 and $2.70 in 2022. In January 2024, Southern Company declared a quarterly dividend of 70 cents per share. Dividends on Southern Company's common stock are payable at the discretion of Southern Company's Board of Directors and depend upon earnings, financial condition, and other factors. See Note 8 to the financial statements under "Dividend Restrictions" in Item 8 herein for additional information.
 Each of the other Registrants have one common stockholder, Southern Company.
 (a)(3) Securities authorized for issuance under equity compensation plans.
 See Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
 (b) Use of Proceeds
 Not applicable.
 (c) Issuer Purchases of Equity Securities
 None.

 Item 6.RESERVED
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 Item 7.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

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 Results of Operations

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 Future Earnings Potential

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 Accounting Policies

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 Financial Condition and Liquidity

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 This section generally discusses 2023 and 2022 items and year-to-year comparisons between 2023 and 2022. Discussions of 2021 items and year-to-year comparisons between 2022 and 2021 that are not included in this Annual Report on Form 10-K can be found in Item 7 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2022, which was filed with the SEC on February 15, 2023. 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.
 Item 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" in Item 7 herein and Note 1 to the financial statements under "Financial Instruments" in Item 8 herein. Also see Notes 13 and 14 to the financial statements in Item 8 herein.
 II-2

 OVERVIEW
 Business Activities
 Southern Company is a holding company that owns all of the common stock of three traditional electric operating companies, 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. See Note 16 to the financial statements for additional information.
 • The traditional electric operating companies – Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service to retail customers in three Southeastern states in addition to wholesale customers in the Southeast.
 • Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions, dispositions, and sales of partnership interests, development and construction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, IPPs, municipalities, electric cooperatives, and other load-serving entities, as well as commercial and industrial customers. In general, Southern Power commits to the construction or acquisition of new generating capacity only after entering into or assuming long-term PPAs for the new facilities.
 • Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas. Southern Company Gas owns natural gas distribution utilities in four states – Illinois, Georgia, Virginia, and Tennessee – and is also involved in several other complementary businesses. Southern Company Gas manages its business through three reportable segments – gas distribution operations, gas pipeline investments, and gas marketing services, which includes SouthStar, a Marketer and provider of energy-related products and services to natural gas markets – and one non-reportable segment, all other. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' reportable segments also included wholesale gas services. See Notes 7, 15, and 16 to the financial statements for additional information.

 Southern Company's other business activities include providing distributed energy and resilience solutions and deploying microgrids for commercial, industrial, governmental, and utility customers, as well as investments in telecommunications. Management continues to evaluate the contribution of each of these activities to total shareholder return and may pursue acquisitions, dispositions, and other strategic ventures or investments accordingly.
 See FUTURE EARNINGS POTENTIAL herein for a discussion of many factors that could impact the Registrants' future results of operations, financial condition, and liquidity.

 Recent Developments

 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, or 1.1%, 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 November 1, 2023, Alabama Power placed Plant Barry Unit 8 in service. On December 1, 2023, Alabama Power filed Rate CNP New Plant with the Alabama PSC to recover costs associated with Plant Barry Unit 8. The filing reflected an annual increase in retail revenues of $91 million, or 1.4%, effective with January 2024 billings.
 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 between scheduled generating unit maintenance outages.
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 On August 18, 2023, Alabama Power notified the Alabama PSC of its intent to use a portion of its reliability reserve balance in 2023. During the fourth quarter 2023, Alabama Power used $75 million of the reliability reserve for reliability-related transmission, distribution, and generation expenses and nuclear production-related expenses. At December 31, 2023, Alabama Power accrued $52 million to its reliability reserve.
 On October 3, 2023, the Alabama PSC issued an order modifying its December 2022 order related to excess federal accumulated deferred income taxes 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. At December 31, 2023, the remaining balance was $81 million, of which approximately $67 million and $14 million will flow back in 2024 and 2025, respectively, for the benefit of customers.
 On November 9, 2023, the Alabama PSC approved a decrease to Rate ECR of approximately $126 million annually, effective with December 2023 billings.
 On December 1, 2023, Alabama Power submitted calculations to the Alabama PSC for Rate CNP Compliance for 2024, which resulted in an annual revenue decrease of approximately $23 million, or 0.3%, effective with January 2024 billings.
 For the year ended December 31, 2023, Alabama Power's weighted common equity return exceeded 6.15%, resulting in Alabama Power establishing a current regulatory liability of $15 million for Rate RSE refunds, which will be refunded to customers through bill credits in April 2024.
 See Note 2 to the financial statements under "Alabama Power" for additional information.

 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 the second quarter 2024 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 start-up and pre-operational testing for Unit 4, Southern Nuclear identified a motor fault in one of four reactor coolant pumps (RCPs). This RCP was replaced with an on-site spare RCP from inventory.
 On February 1, 2024, Georgia Power announced that during start-up and pre-operational testing for Unit 4, Southern Nuclear identified, and has remediated, vibrations associated with certain piping within the cooling system. Considering the remaining pre-operational testing, Unit 4 is projected to be placed in service during the second quarter 2024. On February 14, 2024, Unit 4 achieved self-sustaining nuclear fission, commonly referred to as initial criticality. The projected schedule for Unit 4 significantly depends on the progression of start-up and pre-operational testing, which may be impacted by equipment or other operational failures. 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.
 As of December 31, 2023, based on completion of construction work and the assessment of start-up and pre-operational testing remaining, Southern Nuclear has an estimated $36 million for construction contingency remaining in the estimate to complete. This contingency is projected to be allocated in the future to address any further Unit 4 schedule extensions or remediation of other issues discovered during start-up testing.
 In September 2022, Georgia Power and MEAG Power reached an agreement to resolve a dispute regarding the cost-sharing and tender provisions of the Global Amendments (as defined in Note 2 to the financial statements under "Georgia Power – Nuclear Construction – Joint Owner Contracts"). 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.
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 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 cost-sharing and tender provisions of 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.
 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 for Plant Vogtle Unit 4 and project capital cost forecast for Plant Vogtle Units 3 and 4 cannot be determined at this time. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information.
 Plant Vogtle Units 3 and 4 Rate and Prudency Proceedings
 In compliance with a Georgia PSC order approved in 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 Unit 3.
 On December 19, 2023, the Georgia PSC voted to approve the application to adjust rates to include reasonable and prudent Plant Vogtle Units 3 and 4 costs (Application) as modified by the related stipulated agreement (Prudency Stipulation) among Georgia Power, the staff of the Georgia PSC, and certain intervenors.
 Under the terms of the approved Prudency Stipulation, 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 will also recover projected operations and maintenance expenses, depreciation expense, nuclear decommissioning accruals, and property taxes, net of projected PTCs. 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 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 Prudency Stipulation, 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 will result in an estimated negative impact to earnings of approximately $30 million per month until the month following the date commercial operation for Unit 4 is achieved. The ultimate outcome of this matter cannot be determined at this time.
 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.
 The approval of the Application and the Prudency Stipulation resolves all issues for determination by the Georgia PSC regarding the reasonableness, prudence, and cost recovery for the remaining Plant Vogtle Units 3 and 4 construction and capital costs not already in retail base rates.
 As a result of the Georgia PSC's approval of the Prudency Stipulation, Georgia Power recorded a pre-tax credit to income of approximately $228 million ($170 million after tax) in the fourth quarter 2023 to recognize CWIP costs previously charged to income, which are now recoverable through retail rates. Associated AFUDC on these costs was also recognized.
 See Note 2 to the financial statements under "Georgia Power – Nuclear Construction – Regulatory Matters" for additional information.
 Rate Plans
 On November 16, 2023, in accordance with the terms of the 2022 ARP, the Georgia PSC approved tariff adjustments effective January 1, 2024 that resulted in a net increase in rates of $191 million.
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 Georgia Power expects to submit a compliance filing in the fourth quarter 2024 to request tariff adjustments approved pursuant to the 2022 ARP effective January 1, 2025. The ultimate outcome of this matter cannot be determined at this time.
 See Note 2 to the financial statements under "Georgia Power – Rate Plans – 2022 ARP" 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 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" for additional information.
 Integrated Resource Plans
 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. Georgia Power expects the Georgia PSC to render a final decision on the 2023 IRP Update on April 16, 2024. The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" for additional information.

 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.
 In October 2023, Mississippi Power signed an affiliate PPA with Georgia Power for 750 MWs of capacity, which began January 1, 2024 and will continue through December 2028. In order to fulfill this PPA and serve the interests of customers, Mississippi Power now expects electric generating units identified in its 2021 IRP to remain in service beyond the previously indicated dates. Mississippi Power is expected to file its next IRP in April 2024 in accordance with the rules and orders of the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time.
 On February 6, 2024, the Mississippi PSC approved Mississippi Power's request to increase retail fuel revenues by $18 million annually effective with the first billing cycle of March 2024.
 On February 12, 2024, Mississippi Power submitted its annual ECO Plan filing to the Mississippi PSC, which requested a $9 million annual increase in revenues. The ultimate outcome of this matter cannot be determined at this time.
 See Note 2 to the financial statements under "Mississippi Power" for additional information.
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 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 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. Subsequent to December 31, 2023, Southern Power committed to expand the construction of the facility through a second phase adding up to 205 MWs, with commercial operation expected to occur in the second quarter 2026.
 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 second quarter 2024.
 Southern Power calculates an 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. With the inclusion of investments associated with facilities under construction, as well as other capacity and energy contracts, Southern Power's average investment coverage ratio at December 31, 2023 was 97% through 2028 and 89% through 2033, with an average remaining contract duration of approximately 12 years.
 See Note 15 to the financial statements under "Southern Power" for additional information.

 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 placed in service in 2019. The disallowance is reflected on the statement of income as an $8 million reduction to revenues and $30 million in estimated loss on regulatory disallowance. 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.
 On November 16, 2023, the Illinois Commission approved a $223 million annual base rate increase for Nicor Gas, which became effective December 1, 2023. The base rate increase was based on a return on equity of 9.51% and an equity ratio of 50.00%.
 In connection with Nicor Gas' general base rate case proceeding, the Illinois Commission disallowed $126.8 million of capital investments that have been completed or planned to be completed through December 31, 2024. This includes $31 million for capital investments placed in service in 2022 and 2023 under the Investing in Illinois program and $95.9 million for other transmission and distribution capital investments. Nicor Gas recorded a pre-tax charge to income in the fourth quarter 2023 of $58 million ($44 million after tax) associated with the disallowances, with the remaining $69 million related to prospective projects that will be postponed and/or reevaluated. The disallowance is reflected on the statement of income in estimated loss on regulatory disallowance. On January 3, 2024, the Illinois Commission denied a request by Nicor Gas for rehearing on the base rate case disallowances associated with capital investment, as well as on other issues determined in the Illinois Commission's November 16, 2023 base rate case decision. On February 6, 2024, Nicor Gas filed a notice of appeal with the Illinois Appellate Court related to the Illinois Commission's rate case ruling.
 Any further cost disallowances by the Illinois Commission in the pending cases could be material to the financial statements of Southern Company Gas. The ultimate outcome of these matters cannot be determined at this time. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects – Nicor Gas" for additional information.
 On December 19, 2023, the Georgia PSC approved Atlanta Gas Light's annual GRAM filing, which resulted in an annual base rate increase of $53 million effective January 1, 2024.
 On February 1, 2024, Atlanta Gas Light filed its triennial Integrated Capacity and Delivery Plan (i-CDP) with the Georgia PSC, which included a series of ongoing and proposed pipeline safety, reliability, and growth programs for the next 10 years (2025 through 2034), as well as the required capital investments and related costs to implement the programs. The i-CDP reflected
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 capital investments totaling approximately $0.7 billion to $1.0 billion annually. Atlanta Gas Light expects the Georgia PSC to issue a final order on this matter in the third quarter 2024. The ultimate outcome of this matter cannot be determined at this time.
 On August 28, 2023, the Virginia Commission approved a stipulation agreement related to Virginia Natural Gas' August 2022 general base rate case filing, which allowed for a $48 million increase in annual base rate revenues based on a ROE of 9.70% and an equity ratio of 49.06%. Interim rates became effective as of 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 were completed during the fourth quarter 2023.
 On February 9, 2024, Virginia Natural Gas filed with the Virginia Commission a request to extend the existing SAVE program through 2029. The request includes investments of $70 million in each year from 2025 through 2029, with a potential variance of up to $5 million allowed for the program, for a maximum total investment over the five-year extension (2025 through 2029) of $355 million. Virginia Natural Gas expects the Virginia Commission to issue a final order on this matter in the second quarter 2024. The ultimate outcome of this matter cannot be determined at this time.

 Key Performance Indicators
 In striving to achieve attractive risk-adjusted returns while providing cost-effective energy to approximately 8.9 million electric and gas utility customers collectively, the traditional electric operating companies and Southern Company Gas continue to focus on several key performance indicators. These indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, and execution of major construction projects. In addition, Southern Company and the Subsidiary Registrants focus on earnings per share (EPS) and net income, respectively, as a key performance indicator. See RESULTS OF OPERATIONS herein for information on the Registrants' financial performance.
 The financial success of the traditional electric operating companies and Southern Company Gas is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. The traditional electric operating companies use customer satisfaction surveys to evaluate their results and generally target the top quartile of these surveys in measuring performance. Reliability indicators are also used to evaluate results. See Note 2 to the financial statements under "Alabama Power – Rate RSE" and "Mississippi Power – Performance Evaluation Plan" for additional information on Alabama Power's Rate RSE and Mississippi Power's PEP rate plan, respectively, both of which contain mechanisms that directly tie customer service indicators to the allowed equity return.
 Southern Company Gas also 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. See RESULTS OF OPERATIONS – "Southern Company Gas" for additional information on Southern Company Gas' operating metrics.
 Southern Power continues to focus on several key performance indicators, including, but 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.
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 RESULTS OF OPERATIONS

 Consolidated net income attributable to Southern Company was $4.0 billion in 2023, an increase of $452 million, or 12.8%, from 2022. The increase was primarily due to lower non-fuel operations and maintenance costs, an increase in retail electric revenues associated with rates and pricing, a decrease in income tax expense, a decrease in after-tax charges related to the construction of Plant Vogtle Units 3 and 4, an increase in other revenues, an increase in natural gas revenues from rate increases and continued infrastructure replacement, and a goodwill impairment charge in 2022 at PowerSecure, partially offset by higher depreciation and amortization, higher interest expense, and a decrease in retail electric revenues associated with milder weather in 2023 compared to 2022. See Notes 1 and 2 to the financial statements under "Goodwill and Other Intangible Assets" and "Georgia Power – Nuclear Construction," respectively, for additional information.
 Basic EPS was $3.64 in 2023 and $3.28 in 2022. Diluted EPS, which factors in additional shares related to stock-based compensation, was $3.62 in 2023 and $3.26 in 2022. EPS for 2023 and 2022 was negatively impacted by $0.06 and $0.04 per share, respectively, as a result of increases in the average shares outstanding. See Note 8 to the financial statements under "Outstanding Classes of Capital Stock – Southern Company" for additional information.

 Dividends paid per share of common stock were $2.78 in 2023 and $2.70 in 2022. In January 2024, Southern Company declared a quarterly dividend of 70 cents per share. For 2023, the dividend payout ratio was 76% compared to 82% for 2022.

 Discussion of Southern Company's results of operations is divided into three parts – the Southern Company system's primary business of electricity sales, its gas business, and its other business activities.

 2023
 2022

 Electricity business
 $
 3,994
 $
 3,672

 Gas business

 Other business activities
 (633)
 (720)

 $
 3,976
 $
 3,524

 II-9

 Electricity Business
 Southern Company's electric utilities generate and sell electricity to retail and wholesale customers. A condensed statement of income for the electricity business follows:

 2023
 Increase (Decrease) from 2022

 Electric operating revenues
 $
 19,998
 $
 (2,875)

 Fuel
 4,365
 (2,470)

 (710)

 Cost of other sales

 4,679
 (550)

 3,865

 1,159

 (68)
 (251)

 Total electric operating expenses
 15,054
 (3,054)

 4,944

 1,274

 (265)

 3,867

 Less:

 Dividends on preferred stock of subsidiaries
 —
 (11)

 Net loss attributable to noncontrolling interests
 (127)
 (20)

 Net Income Attributable to Southern Company
 $
 3,994
 $

 Electric Operating Revenues
 Electric operating revenues for 2023 were $20.0 billion, reflecting a $2.9 billion, or 12.6%, decrease from 2022. Details of electric operating revenues were as follows:

 2023
 2022

 Retail electric — prior year
 $
 18,197

 Estimated change resulting from —

 Rates and pricing

 Sales decline

 (33)

 Weather
 (229)

 Fuel and other cost recovery
 (2,029)

 Retail electric — current year
 $
 16,343
 $
 18,197

 2,467
 3,641

 Other electric revenues

 Electric operating revenues
 $
 19,998
 $
 22,873

 Retail electric revenues decreased $1.9 billion, or 10.2%, in 2023 as compared to 2022. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing in 2023 was primarily due to base tariff increases in accordance with Georgia Power's 2022 ARP, revenue reductions in 2022 resulting from Georgia Power's retail ROE exceeding the allowed
 II-10

 retail ROE range, an increase in Rate CNP Compliance revenues at Alabama Power, and a lower Rate RSE customer refund accrual in 2023 compared to 2022 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.
 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 under "Alabama Power" and "Georgia Power" for additional information. Also see "Energy Sales" herein for a discussion of changes in the volume of energy sold, including estimated changes related to sales and weather.
 Wholesale electric revenues from power sales were as follows:

 2023
 2022

 Capacity and other
 $
 $

 Energy
 1,837
 3,016

 Total
 $
 2,467
 $
 3,641

 In 2023, wholesale electric revenues decreased $1.2 billion, or 32.2%, as compared to 2022 primarily due to a decrease in energy revenues. Energy revenues decreased $884 million at Southern Power and $295 million at the traditional electric operating companies primarily due to fuel and purchased power price decreases compared to 2022. Also contributing to the Southern Power decrease was a net decrease in the volume of KWHs sold primarily associated with natural gas PPAs.
 Wholesale electric revenues consist of revenues from PPAs and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, the ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated MRA 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
 Other electric revenues increased $45 million, or 6.0%, in 2023 as compared to 2022. The increase was primarily due to increases of $23 million in outdoor lighting sales at Georgia Power, $18 million resulting from receipts of liquidated damages associated with generation facility production guarantees and an arbitration award at Southern Power, $17 million in realized gains associated with price stability products for retail customers on variable demand-driven pricing tariffs at Georgia Power, and $17 million in retail solar program fees at Georgia Power, partially offset by decreases of $25 million in cogeneration steam revenues associated with lower natural gas prices at Alabama Power and $14 million in rent revenues primarily at Alabama Power.
 II-11

 Energy Sales
 Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2023 and the percent change from 2022 were as follows:

 2023

 Total
KWHs
 Total KWH
Percent Change
 Weather-Adjusted
Percent Change(*)

 47.1
 (5.1)
 %
 (0.5)
 %

 48.3
 0.1
 1.3

 48.6
 (1.9)
 (1.9)

 Other
 0.5
 (7.2)
 (6.8)

 Total retail
 144.5
 (2.3)
 (0.4)
 %

 51.0
 (9.4)

 Total energy sales
 195.5
 (4.3)
 %

 (*)Weather-adjusted KWH sales are estimated using statistical models of the historical relationship between temperatures and energy sales, and then removing the estimated effect of deviations from normal temperature conditions. Normal temperature conditions are defined as those experienced in the applicable service territory over a specified historical period. This metric is useful because it allows trends in historical operations to be evaluated apart from the influence of weather conditions. Management also considers this metric in developing long-term capital and financial plans.
 Changes in retail energy sales are generally the result of changes in electricity usage by customers, weather, and the number of customers. Weather-adjusted retail energy sales decreased 587 million KWHs in 2023 as compared to 2022. Weather-adjusted residential KWH sales decreased 0.5% primarily due to decreased customer usage, partially offset by customer growth. Weather-adjusted commercial KWH sales increased 1.3% primarily due to increased customer usage and customer growth. Industrial KWH sales decreased 1.9% primarily due to decreases in the chemicals, forest products, and textiles sectors.
 See "Electric Operating Revenues" above for a discussion of significant changes in wholesale revenues related to changes in price and KWH sales.
 Other Revenues
 Other revenues increased $108 million, or 37.5%, in 2023 as compared to 2022. The increase was primarily due to increases of $54 million in power delivery construction and maintenance projects at Georgia Power, $34 million in unregulated sales of products and services at Alabama Power, and $25 million associated with energy conservation projects at Georgia Power.
 The mix of fuel sources for the generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the electric utilities purchase a portion of their electricity needs from the wholesale market.
 II-12

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

 2023
 2022

 Total generation (in billions of KWHs)(a)(b)

 Total purchased power (in billions of KWHs)

 Sources of generation (percent)(a) —

 Gas

 Nuclear(b)

 Coal

 Hydro

 Wind, Solar, and Other

 Cost of fuel, generated (in cents per net KWH) —

 Gas(a)

 2.77
 5.29

 Nuclear(b)

 0.76
 0.72

 Coal
 4.33
 3.67

 Average cost of fuel, generated (in cents per net KWH)(a)(b)

 2.68
 4.05

 Average cost of purchased power (in cents per net KWH)(c)

 5.17
 7.66

 (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" 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 2 to the financial statements under "Georgia Power – Nuclear Construction" 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.
 In 2023, total fuel and purchased power expenses were $5.2 billion, a decrease of $3.2 billion, or 37.7%, as compared to 2022. The decrease was primarily the result of a $2.7 billion decrease in the average cost of fuel generated and purchased and a $513 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 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.
 Fuel
 In 2023, fuel expense was $4.4 billion, a decrease of $2.5 billion, or 36.1%, as compared to 2022. The decrease was primarily due to a 47.6% decrease in the average cost of natural gas per KWH generated and a 22.5% decrease in the volume of KWHs generated by coal, partially offset by an 18.2% decrease in the volume of KWHs generated by hydro, an 18.0% increase in the average cost of coal per KWH generated, a 10.8% increase in the volume of KWHs generated by nuclear, and a 6.9% increase in the volume of KWHs generated by natural gas.
 Purchased Power
 In 2023, purchased power expense was $883 million, a decrease of $710 million, or 44.6%, as compared to 2022. The decrease was primarily due to a 32.5% decrease in the average cost per KWH purchased primarily due to lower natural gas prices and a 27.5% decrease in the volume of KWHs purchased.
 Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.
 Cost of Other Sales
 Cost of other sales increased $57 million, or 50.0%, in 2023 as compared to 2022. The increase was primarily due to increases of $40 million from unregulated power delivery construction and maintenance projects at Georgia Power and $20 million in expenses related to unregulated products and services at Alabama Power.
 II-13

 Other operations and maintenance expenses decreased $550 million, or 10.5%, in 2023 as compared to 2022. The decrease reflects a decrease of $189 million associated with the reliability reserve accruals and reliability-related expenditures incurred at Alabama Power. Excluding this decrease, there were decreases of $223 million in transmission and distribution expenses primarily related to line maintenance, $182 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 $50 million in employee compensation and benefit expenses, partially offset by an $86 million increase in technology infrastructure and application production costs and a $73 million increase in generation environmental projects primarily at Georgia Power. See Note 1 to the financial statements under "Storm Damage and Reliability Reserves" for additional information.
 Depreciation and amortization increased $836 million, or 27.6%, in 2023 as compared to 2022. The increase was primarily due to increases of $541 million and $190 million resulting from higher depreciation rates at Alabama Power and Georgia Power, respectively, and $79 million from additional plant in service. See Note 2 to the financial statements under "Alabama Power – Rate CNP Depreciation" for additional information.
 Taxes Other Than Income Taxes
 Taxes other than income taxes increased $34 million, or 3.0%, in 2023 as compared to 2022. The increase was primarily due to increases of $62 million in property taxes primarily at Georgia Power resulting from an increase in the assessed value of property and $14 million in utility license taxes at Alabama Power, partially offset by a decrease of $40 million in municipal franchise fees resulting from lower retail revenues at Georgia Power.
 Estimated Loss on Plant Vogtle Units 3 and 4
 Georgia Power recorded pre-tax charges (credits) to income for the estimated probable loss on Plant Vogtle Units 3 and 4 totaling $(68) million and $183 million in 2023 and 2022, respectively. The charges (credits) to income in each year were recorded to reflect Georgia Power's revisions to the total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4 and the related cost recovery. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information.
 Allowance for Equity Funds Used During Construction
 Allowance for equity funds used during construction increased $37 million, or 17.6%, in 2023 as compared to 2022. The increase was primarily associated with an increase in capital expenditures subject to AFUDC at Georgia Power and an increase in capital expenditures related to hydro production and Plant Barry Unit 8 construction at Alabama Power. See Note 2 to the financial statements under "Alabama Power – Rate CNP New Plant" for additional information.
 Interest expense, net of amounts capitalized increased $207 million, or 19.4%, in 2023 as compared to 2022. The increase reflects approximately $120 million related to higher interest rates and $96 million related to higher average outstanding borrowings. See Note 8 to the financial statements for additional information.
 Other Income (Expense), Net
 Other income (expense), net increased $17 million, or 3.3%, in 2023 as compared to 2022 primarily due to a $48 million decrease in charitable donations primarily at Georgia Power, a $15 million increase in interest income, and a $14 million decrease in non-operating benefit-related expenses at Alabama Power, partially offset by a $42 million decrease in non-service cost-related retirement benefits income and a $13 million decrease in customer charges related to contributions in aid of construction at Georgia Power. See Note 11 to the financial statements for additional information.
 Income taxes decreased $265 million, or 31.3%, in 2023 as compared to 2022. The decrease was primarily due to a $252 million increase in the flowback of certain excess deferred income taxes at Alabama Power, an $85 million decrease in charges to a valuation allowance on certain state tax credit carryforwards at Georgia Power, generation of $35 million of advanced nuclear PTCs at Georgia Power, and a $32 million adjustment in 2022 related to a prior year state tax credit carryforward at Georgia Power, partially offset by a $145 million decrease in the flowback of certain excess deferred income taxes at Georgia Power that ended in 2022. See Note 10 to the financial statements for additional information.
 II-14

 Net Loss Attributable to Noncontrolling Interests
 Substantially all noncontrolling interests relate to renewable projects at Southern Power. Net loss attributable to noncontrolling interests increased $20 million, or 18.7%, in 2023 as compared to 2022. The increased loss was primarily due to $25 million in higher HLBV loss allocations to Southern Power's wind tax equity partners and $5 million in lower income allocations to Southern Power's equity partners, partially offset by $10 million in lower HLBV loss allocations to Southern Power's battery energy storage partners.
 Gas Business
 Southern Company Gas distributes natural gas through utilities in four states and is involved in several other complementary businesses including gas pipeline investments and gas marketing services.
 A condensed statement of income for the gas business follows:

 2023
 Increase (Decrease) from 2022

 $
 4,702
 $
 (1,260)

 1,644
 (1,360)

 1,194

 (20)

 —
 (131)

 (7)
 (3)

 3,763
 (1,385)

 (8)

 $
 $

 During the period from November through March when natural gas usage and operating revenues are generally higher (Heating Season), more customers are connected to Southern Company Gas' distribution systems and natural gas usage is higher in periods of colder weather. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively equally over any given year. Thus, operating results can vary significantly from quarter to quarter as a result of seasonality. For 2023, the percentage of operating revenues and net income generated during
 II-15

 the Heating Season (January through March and November through December) were 67% and 73%, respectively. For 2022, the percentage of operating revenues and net income generated during the Heating Season were 67% and 66%, respectively.
 Operating revenues in 2023 were $4.7 billion, reflecting a $1.3 billion, or 21.1%, decrease compared to 2022. Details of operating revenues were as follows:

 2023

 Operating revenues – prior year
 $
 5,962

 Estimated change resulting from –

 Infrastructure replacement programs and base rate changes

 Gas costs and other cost recovery
 (1,323)

 (93)

 Other
 (38)

 Operating revenues – current year
 $
 4,702

 Revenues from infrastructure replacement programs and base rate changes increased in 2023 primarily due to rate increases at the natural gas distribution utilities and continued investment in infrastructure replacement, partially offset by lower volumes sold and regulatory disallowances at Nicor Gas. See Note 2 to the financial statements under "Southern Company Gas" for additional information.
 Revenues associated with gas costs and other cost recovery decreased in 2023 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. The natural gas distribution utilities have weather or revenue normalization mechanisms that mitigate revenue fluctuations from customer consumption changes. 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. See "Cost of Natural Gas" herein for additional information.
 Revenues from gas marketing services decreased in 2023 primarily due to lower natural gas prices and the timing of unrealized hedge losses.
 Southern Company Gas hedged its exposure to warmer-than-normal weather in Illinois for gas distribution operations and in Illinois and Georgia for gas marketing services. The remaining impacts of weather on earnings were immaterial.
 Cost of Natural Gas
 Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, the natural gas distribution utilities 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. See Note 2 to the financial statements under "Southern Company Gas – Natural Gas Cost Recovery" for additional information. Cost of natural gas at the natural gas distribution utilities represented 83.5% of the total cost of natural gas for 2023.
 Gas marketing services customers are charged for actual and estimated natural gas consumed. Cost of natural gas includes the cost of fuel and associated transportation costs, lost and unaccounted for gas, and gains and losses associated with certain derivatives.
 Cost of natural gas was $1.6 billion, a decrease of $1.4 billion, or 45.3%, in 2023 compared to 2022, which reflects lower gas cost recovery in 2023 as a result of a 58.8% decrease in natural gas prices compared to 2022.
 Other operations and maintenance expenses increased $18 million, or 1.5%, in 2023 compared to 2022. The increase was primarily due to increases of $70 million in compensation and benefits and $20 million related to energy service contracts, partially offset by a decrease of $60 million in expenses passed through to customers primarily related to bad debt and energy efficiency programs at the natural gas distribution utilities. See Note 2 to the financial statements under "Southern Company Gas" for additional information.
 II-16

 Depreciation and amortization increased $23 million, or 4.1%, in 2023 compared to 2022. The increase was primarily due to continued infrastructure investments at the natural gas distribution utilities. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" for additional information.
 Taxes Other Than Income Taxes
 Taxes other than income taxes decreased $20 million, or 7.1%, in 2023 compared to 2022. The decrease was primarily due to a $29 million decrease in revenue taxes, partially offset by increases in payroll and property taxes.
 Impairment Charges
 In 2022, Southern Company Gas recorded pre-tax impairment charges totaling approximately $131 million ($99 million after tax) as a result of an agreement to sell two natural gas storage facilities. See Note 15 to the financial statements under "Southern Company Gas" for additional information.
 Estimated Loss on Regulatory Disallowance
 In 2023, Southern Company Gas recorded pre-tax charges related to the disallowance of certain capital investments at Nicor Gas, $88 million of which was recorded in estimated loss on regulatory disallowance. See Note 2 under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects – Nicor Gas" for additional information.
 Interest expense, net of amounts capitalized increased $47 million, or 17.9%, in 2023 compared to 2022. The increase reflects approximately $43 million related to higher interest rates and $8 million related to higher average outstanding borrowings. See Note 8 to the financial statements for additional information.
 Income taxes increased $31 million, or 17.2%, in 2023 compared to 2022. The increase was primarily due to $33 million of tax benefit in 2022 related to the impairment charges associated with the sale of two natural gas storage facilities and higher taxes related to increased earnings, partially offset by approximately $24 million related to the regulatory disallowances at Nicor Gas. See Notes 2 and 15 to the financial statements under "Southern Company Gas" and Note 10 to the financial statements for additional information.
 Other Business Activities
 Southern Company's other business activities primarily include the parent company (which does not allocate operating expenses to business units); PowerSecure, which provides distributed energy and resilience solutions and deploys microgrids for commercial, industrial, governmental, and utility customers; Southern Holdings, which invests in various projects; and Southern Linc, which provides digital wireless communications for use by the Southern Company system and also markets these services to the public and provides fiber optics services within the Southeast.
 II-17

 A condensed statement of operations for Southern Company's other business activities follows:

 2023
 Increase (Decrease) from 2022

 $
 $

 Cost of other sales

 (26)

 —

 —
 (119)

 —

 (42)

 Operating income (loss)
 (57)

 (16)

 (298)
 (65)

 $
 (633)
 $

 Operating revenues for these other business activities increased $110 million, or 24.8%, in 2023 as compared to 2022 primarily due to increases of $92 million related to distributed infrastructure projects at PowerSecure and $24 million primarily related to sales associated with commercial customers at Southern Linc.
 Cost of Other Sales
 Cost of other sales for these other business activities increased $87 million, or 32.5%, in 2023 as compared to 2022 primarily due to increases of $58 million related to distributed infrastructure projects at PowerSecure and $23 million primarily related to sales associated with commercial customers at Southern Linc.
 Other Operations and Maintenance
 Other operations and maintenance expenses for these other business activities decreased $26 million, or 12.9%, in 2023 as compared to 2022 primarily due to a decrease at the parent company related to cost containment efforts and lower director compensation expenses.
 Impairment Charges
 In 2022, a goodwill impairment charge of $119 million was recorded at PowerSecure. See Note 1 to the financial statements under "Goodwill and Other Intangible Assets" for additional information.
 Gain on Dispositions, Net
 In 2022, a $14 million gain was recorded at the parent company as a result of the early termination of the transition services agreement related to the 2019 sale of Gulf Power.
 Interest Expense
 Interest expense for these other business activities increased $171 million, or 24.7%, in 2023 as compared to 2022. The increase primarily results from parent company financing activities and includes approximately $112 million related to higher interest rates and $73 million related to higher average outstanding borrowings. See Note 8 to the financial statements for additional information.
 II-18

 Other Income (Expense), Net
 Other income (expense), net for these other business activities increased $39 million, or 70.9%, in 2023 as compared to 2022 primarily due to a $29 million decrease in charitable donations and a $12 million increase in interest income, both primarily at the parent company. See Note 15 to the financial statements under "Southern Company" for additional information.
 Income Taxes (Benefit)
 The income tax benefit for these other business activities increased $65 million, or 27.9%, in 2023 as compared to 2022. The increase was primarily due to a $35 million tax benefit in 2023 related to a reversal of an uncertain tax position associated with the 2019 sale of Gulf Power and higher pre-tax losses, both at the parent company.

 Alabama Power's 2023 net income after dividends on preferred stock was $1.37 billion, representing a $30 million, or 2.2%, increase from 2022. The increase was primarily due to a decrease in income tax expense, an increase in Rate CNP Compliance revenues, a decrease in operations and maintenance expenses primarily related to the reliability reserve, and a lower Rate RSE customer refund accrual in 2023 compared to 2022. These increases to net income were offset by 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 increases in capacity-related expenses and interest expense. See Note 2 to the financial statements under "Alabama Power" for additional information.
 A condensed income statement for Alabama Power follows:

 2023
 Increase
 (Decrease)
 from 2022

 $
 7,050
 $
 (767)

 Fuel
 1,299
 (541)

 (297)

 1,769
 (166)

 1,401

 5,415
 (460)

 1,635
 (307)

 (342)

 1,370

 Dividends on preferred stock
 —
 (11)

 Net income after dividends on preferred stock
 $
 1,370
 $

 II-19

 Operating revenues for 2023 were $7.1 billion, reflecting a $767 million, or 9.8%, decrease from 2022. Details of operating revenues were as follows:

 2023
 2022

 Retail — prior year
 $
 6,470

 Estimated change resulting from —

 Rates and pricing

 Sales decline

 (33)

 Weather
 (84)

 Fuel and other cost recovery
 (470)

 Retail — current year
 $
 6,159
 $
 6,470

 Wholesale revenues —

 Non-affiliates

 Affiliates

 Total wholesale revenues

 Other operating revenues

 $
 7,050
 $
 7,817

 Retail revenues decreased $311 million, or 4.8%, in 2023 as compared to 2022. The significant factors driving this change are shown in the preceding table. The decrease was primarily due to a decrease in fuel and other cost recovery, partially offset by an increase in revenues associated with rates and pricing primarily due to an increase in Rate CNP Compliance revenues and a lower Rate RSE customer refund accrual in 2023 compared to 2022.
 See Note 2 to the financial statements under "Alabama Power – Rate ECR," " – Rate RSE," and " – Rate CNP Compliance" for additional information. See "Energy Sales" herein for a discussion of changes in the volume of energy sold, including estimated changes related to sales and weather.
 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" for additional information.
 Wholesale revenues from sales to non-affiliated utilities were as follows:

 2023
 2022

 Capacity and other
 $
 $

 Energy

 Total non-affiliated
 $
 $

 In 2023, wholesale revenues from sales to non-affiliates decreased $302 million, or 41.6%, as compared to 2022. The decrease reflects a 26.0% decrease in the volume of KWHs sold as a result of power sales agreements that ended in May 2023 and a 20.8% decrease in the price of energy primarily as a result of lower natural gas prices.
 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.
 II-20

 In 2023, wholesale revenues from sales to affiliates decreased $142 million, or 70.3%, as compared to 2022. The revenue decrease reflects a 47.7% decrease in the price of energy due to lower natural gas prices and a 42.9% decrease in KWH sales due to lower customer demand as a result of milder weather in 2023.
 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 and purchases are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.
 In 2023, other operating revenues decreased $12 million, or 2.9%, as compared to 2022 primarily due to decreases of $25 million in cogeneration steam revenue associated with lower natural gas prices and $17 million in rent revenues, partially offset by a $34 million increase in unregulated sales of products and services.
 Energy Sales
 Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2023 and the percent change from 2022 were as follows:

 2023

 Total
KWHs
 Total KWH
Percent Change
 Weather-Adjusted
Percent Change(*)

 17.4
 (5.7)
 %
 (0.9)
 %

 12.9
 (1.2)
 0.4

 20.4
 (2.8)
 (2.8)

 Other
 0.1
 (15.5)
 (15.5)

 Total retail
 50.8
 (3.4)
 (1.3)
 %

 Non-affiliates
 9.3
 (26.0)

 Affiliates
 2.1
 (42.9)

 Total wholesale
 11.4
 (29.9)

 Total energy sales
 62.2
 (9.7)
 %

 (*)Weather-adjusted KWH sales are estimated using statistical models of the historical relationship between temperatures and energy sales, and then removing the estimated effect of deviations from the normal temperature conditions. Normal temperature conditions are defined as those experienced in Alabama Power's service territory over a specified historical period. This metric is useful because it allows trends in historical operations to be evaluated apart from the influence of weather conditions. Management also considers this metric in developing long-term capital and financial plans.
 Changes in retail energy sales are generally the result of changes in electricity usage by customers, weather, and the number of customers. Revenues attributable to changes in sales decreased in 2023 when compared to 2022. In 2023, weather-adjusted residential KWH sales decreased 0.9% primarily due to decreased customer usage. Weather-adjusted commercial KWH sales increased 0.4% primarily due to increased customer usage and customer growth. Industrial KWH sales decreased 2.8% as a result of a decrease in demand resulting from changes in production levels primarily in the chemicals and forest products sectors.
 See "Operating Revenues" above for a discussion of significant changes in wholesale revenues from sales to non-affiliates and wholesale revenues from sales to affiliated companies related to changes in price and KWH sales.
 The mix of fuel sources for generation of electricity is determined primarily by the unit cost of fuel consumed, demand, and the availability of generating units. Additionally, Alabama Power purchases a portion of its electricity needs from the wholesale market.
 II-21

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

 2023
 2022

 Total generation (in billions of KWHs)(a)

 54.5
 58.3

 Total purchased power (in billions of KWHs)

 10.8
 11.6

 Sources of generation (percent)(a) —

 Coal

 Gas

 Hydro

 Cost of fuel, generated (in cents per net KWH) —

 Coal
 3.46
 3.39

 Gas(a)

 2.99
 5.12

 0.69
 0.67

 Average cost of fuel, generated (in cents per net KWH)(a)

 2.50
 3.19

 Average cost of purchased power (in cents per net KWH)(b)

 4.98
 8.00

 (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" 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 and purchased power expenses were $1.8 billion in 2023, a decrease of $838 million, or 31.7%, compared to 2022. The decrease was primarily due to a $674 million decrease in the average cost of fuel and purchased power and a $164 million decrease 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. Alabama Power, along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. See Note 2 to the financial statements under "Alabama Power – Rate ECR" for additional information.
 Fuel
 Fuel expense was $1.3 billion in 2023, a decrease of $541 million, or 29.4%, compared to 2022. The decrease was primarily due to a 41.6% decrease in the average cost of natural gas per KWH generated, which excludes tolling agreements, and a 29.1% decrease in the volume of KWHs generated by coal, partially offset by a 21.2% increase in the volume of KWHs generated by natural gas, an 18.9% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall in 2023, and a 13.6% increase in the volume of KWHs generated by nuclear.
 Purchased Power – Non-Affiliates
 Purchased power expense from non-affiliates was $253 million in 2023, a decrease of $188 million, or 42.6%, compared to 2022. The decrease was primarily due to a 32.9% decrease in the average cost per KWH purchased primarily due to lower natural gas prices and a 25.5% decrease in the volume of KWHs purchased primarily due to the availability of lower cost generation in the Southern Company system.
 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
 Purchased power expense from affiliates was $251 million in 2023, a decrease of $109 million, or 30.3%, compared to 2022. The decrease was primarily due to a 51.4% decrease in the average cost per KWH purchased primarily due to lower natural gas prices, partially offset by a 43.4% increase in the volume of KWHs purchased due to the availability of lower cost gas generation in the Southern Company system.
 II-22

 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 decreased $166 million, or 8.6%, in 2023 as compared to 2022. The change was primarily due to a decrease of $189 million associated with the reliability reserve accruals and reliability-related expenditures incurred, as well as decreases of $33 million in transmission and distribution expenses and $21 million in certain employee compensation and benefit expenses. These decreases were partially offset by increases of $30 million in technology infrastructure and application production costs and $25 million in expenses related to unregulated products and services, as well as a $14 million decrease in nuclear property insurance refunds. See Note 2 to the financial statements under "Alabama Power – Reliability Reserve Accounting Order" for additional information.
 Depreciation and amortization increased $526 million, or 60.1%, in 2023 as compared to 2022 primarily due to an increase in depreciation rates effective in 2023. See Note 2 to the financial statements under "Alabama Power – Rate CNP Depreciation" for additional information.
 Allowance for Equity Funds Used During Construction
 Allowance for equity funds used during construction increased $12 million, or 17.1%, in 2023 as compared to 2022 primarily due to increases in capital expenditures related to hydro production and Plant Barry Unit 8 construction. See Note 2 to the financial statements under "Alabama Power – Rate CNP New Plant" for additional information.
 Interest expense, net of amounts capitalized increased $43 million, or 11.3%, in 2023 as compared to 2022. The increase reflects approximately $30 million related to higher average outstanding borrowings and $20 million related to higher interest rates. See Note 8 to the financial statements for additional information.
 Other Income (Expense), Net
 Other income (expense), net increased $15 million, or 10.4%, in 2023 as compared to 2022 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 11 to the financial statements for additional information.
 Income taxes decreased $342 million, or 80.9%, in 2023 as compared to 2022 primarily due to a $252 million increase in the flowback of certain excess deferred income taxes and an $84 million decrease due to lower pre-tax earnings. See Note 2 to the financial statements under "Alabama Power – Excess Accumulated Deferred Income Tax Accounting Order" and Note 10 to the financial statements for additional information.

 Georgia Power's 2023 net income was $2.1 billion, representing a $0.3 billion, or 14.7%, increase from the previous year. The increase was primarily due to lower non-fuel operations and maintenance costs, revenue reductions in 2022 as a result of Georgia Power exceeding its allowed retail return range, a $187 million decrease in after-tax charges related to the construction of Plant Vogtle Units 3 and 4, and an increase in other revenues, partially offset by a decrease in retail revenues associated with lower contributions from customers with variable demand-driven pricing and milder weather in 2023, as well as higher interest expense. Also contributing to the net income growth 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 under "Georgia Power" for additional information.
 II-23

 A condensed income statement for Georgia Power follows:

 2023
 Increase
 (Decrease)
 from 2022

 $
 10,118
 $
 (1,466)

 Fuel
 1,781
 (705)

 1,281
 (976)

 2,083
 (266)

 1,681

 (68)
 (251)

 7,299
 (1,933)

 2,819

 (6)

 $
 2,080
 $

 Operating revenues for 2023 were $10.1 billion, reflecting a $1.5 billion, or 12.7%, decrease from 2022. Details of operating revenues were as follows:

 2023
 2022

 Retail — prior year
 $
 10,792

 Estimated change resulting from —

 Rates and pricing

 Sales decline
 (10)

 Weather
 (141)

 Fuel cost recovery
 (1,591)

 Retail — current year
 $
 9,222
 $
 10,792

 Wholesale revenues

 Other operating revenues

 $
 10,118
 $
 11,584

 Retail revenues decreased $1.6 billion, or 14.5%, in 2023 as compared to 2022. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing was primarily due to base tariff increases in accordance with the 2022 ARP and revenue reductions in 2022 resulting from Georgia Power's retail ROE exceeding the allowed retail ROE range, 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. See Note 2 to the financial statements under "Georgia Power – Rate Plans" and " – Nuclear Construction" for additional information.
 See "Energy Sales" below for a discussion of changes in the volume of energy sold, including estimated changes related to sales and weather in 2023.
 Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See Note 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" for additional information.
 II-24

 Wholesale revenues from power sales were as follows:

 2023
 2022

 Capacity and other
 $
 $

 Energy

 Total
 $
 $

 In 2023, wholesale revenues decreased $47 million, or 20.0%, as compared to 2022 largely due to an $81 million decrease related to the average cost per KWH sold due to lower Southern Company system fuel and purchased power costs, partially offset by a $21 million increase related to new capacity contracts and a $13 million increase related to the volume of KWH sales associated with higher market demand.
 Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Wholesale capacity revenues from PPAs are recognized in amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.
 Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
 In 2023, other operating revenues increased $151 million, or 27.1%, as compared to 2022 primarily due to an increase of $105 million in unregulated sales associated with power delivery construction and maintenance, outdoor lighting, and energy conservation projects, a net increase of $17 million in realized gains associated with price stability products for retail customers on variable demand-driven pricing tariffs, an increase of $17 million in retail solar program fees, and a $9 million increase in open access transmission tariff sales.
 Energy Sales
 Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2023 and the percent change from 2022 were as follows:

 2023

 Total
KWHs
 Total KWH
Percent Change
 Weather-Adjusted
Percent Change(*)

 27.6
 (5.0)
 %
 (0.4)
 %

 32.6
 0.1
 1.2

 23.5
 (1.6)
 (1.4)

 Other
 0.4
 (4.7)
 (4.2)

 Total retail
 84.1
 (2.1)
 (0.1)
 %

 2.6
 7.8

 Total energy sales
 86.7
 (1.9)
 %

 (*)Weather-adjusted KWH sales are estimated using statistical models of the historical relationship between temperatures and energy sales, and then removing the estimated effect of deviations from normal temperature conditions. Normal temperature conditions are defined as those experienced in Georgia Power's service territory over a specified historical period. This metric is useful because it allows trends in historical operations to be evaluated apart from the influence of weather conditions. Management also considers this metric in developing long-term capital and financial plans.
 Changes in retail energy sales are generally the result of changes in electricity usage by customers, weather, and the number of customers. Revenues attributable to changes in sales decreased in 2023 when compared to 2022. Weather-adjusted residential sales decreased 0.4% primarily due to decreased customer usage, largely offset by customer growth. Weather-adjusted commercial KWH sales increased 1.2% primarily due to customer growth. Weather-adjusted industrial KWH sales decreased
 II-25

 1.4% primarily due to decreases in the textile, mining, and stone, clay, and glass sectors, partially offset by an increase in the paper sector.
 See "Operating Revenues" above for a discussion of significant changes in wholesale sales to non-affiliates and affiliated companies.

 Fuel costs constitute one of the largest expenses for Georgia Power. The mix of fuel sources for the generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, Georgia Power purchases a portion of its electricity needs from the wholesale market.
 Details of Georgia Power's generation and purchased power were as follows:

 2023
 2022

 Total generation (in billions of KWHs)(a)

 60.3
 59.7

 Total purchased power (in billions of KWHs)

 29.6
 33.6

 Sources of generation (percent) —

 Gas

 Nuclear(a)

 Coal

 Hydro and other

 Cost of fuel, generated (in cents per net KWH) —

 Gas
 3.07
 5.06

 Nuclear(a)

 0.82
 0.75

 Coal
 5.59
 4.12

 Average cost of fuel, generated (in cents per net KWH)(a)

 2.90
 3.64

 Average cost of purchased power (in cents per net KWH)(b)

 4.63
 7.88

 (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 2 to the financial statements under "Georgia Power – Nuclear Construction" 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 and purchased power expenses were $3.1 billion in 2023, a decrease of $1.7 billion, or 35.4%, compared to 2022. The decrease was due to decreases of $1.4 billion related to the average cost of fuel and purchased power and $321 million related to the volume of KWHs generated and purchased.
 Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through Georgia Power's fuel cost recovery mechanism. See Note 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" for additional information.
 Fuel
 Fuel expense was $1.8 billion in 2023, a decrease of $0.7 billion, or 28.4%, compared to 2022. The decrease was primarily due to decreases of 39.3% in the average cost per KWH generated by natural gas and 8.9% in the volume of KWHs generated by coal, partially offset by increases of 35.7% in the average cost per KWH generated by coal, 9.3% in the average cost per KWH generated by nuclear, 8.5% in the volume of KWHs generated by nuclear, and 2.1% in the volume of KWHs generated by natural gas.
 Purchased Power – Non-Affiliates
 Purchased power expense from non-affiliates was $517 million in 2023, a decrease of $339 million, or 39.6%, compared to 2022. The decrease was primarily due to a decrease of 33.9% in the volume of KWHs purchased due to lower demand and the availability of lower cost generation in the Southern Company system and a decrease of 22.3% 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.
 II-26

 Purchased Power – Affiliates
 Purchased power expense from affiliates was $764 million in 2023, a decrease of $637 million, or 45.5%, compared to 2022. The decrease was primarily due to a decrease of 49.1% in the average cost per KWH purchased primarily due to lower natural gas prices.
 Energy purchases from affiliates will vary depending on the demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.

 Other operations and maintenance expenses decreased $266 million, or 11.3%, in 2023 as compared to 2022. The decrease was primarily due to decreases of $182 million in storm damage recovery as authorized in the 2022 ARP, $178 million in transmission and distribution expenses primarily associated with line maintenance, $74 million in generation non-outage maintenance expenses, and $28 million in certain employee compensation and benefit expenses. These decreases were partially offset by increases of $60 million from unregulated power delivery construction and maintenance and energy conservation projects, $59 million in generation environmental projects, $55 million in technology infrastructure and application production costs, and $28 million in planned generation outages. See Note 2 to the financial statements under "Georgia Power – Storm Damage Recovery" for additional information.

 Depreciation and amortization increased $251 million, or 17.6%, in 2023 as compared to 2022 primarily due to increases of $190 million resulting from higher depreciation rates as authorized in the 2022 ARP and $75 million associated with additional plant in service, partially offset by a decrease of $15 million in amortization of regulatory assets related to the retirement of certain generating units that ended in 2022.
 Taxes Other Than Income Taxes
 Taxes other than income taxes increased $14 million, or 2.7%, in 2023 as compared to 2022 primarily due to an increase of $56 million in property taxes primarily resulting from an increase in the assessed value of property, largely offset by a decrease of $40 million in municipal franchise fees resulting from lower retail revenues.
 Estimated Loss on Plant Vogtle Units 3 and 4
 Georgia Power recorded pre-tax charges (credits) to income for the estimated probable loss on Plant Vogtle Units 3 and 4 totaling $(68) million and $183 million in 2023 and 2022, respectively. The charges (credits) to income in each year were recorded to reflect revisions to the total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4 and the related cost recovery. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information.
 Allowance for Equity Funds Used During Construction
 Allowance for equity funds used during construction increased $25 million, or 17.9%, in 2023 as compared to 2022 primarily due to an increase in capital expenditures subject to AFUDC.
 Interest expense, net of amounts capitalized increased $141 million, or 29.1%, in 2023 as compared to 2022. The increase primarily reflects approximately $78 million related to higher interest rates and $76 million related to higher average outstanding borrowings, partially offset by the deferral of $14 million in financing costs related to Plant Vogtle Unit 3. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein and Note 8 to the financial statements for additional information. Also see Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.
 Other Income (Expense), Net
 Other income (expense), net decreased $6 million, or 3.4%, in 2023 as compared to 2022 primarily due to decreases in non-service cost-related retirement benefits income and customer charges related to contributions in aid of construction, partially offset by a decrease in charitable donations. See Note 11 to the financial statements for additional information on Georgia Power's net periodic pension and other postretirement benefit costs.
 II-27

 Income Taxes (Benefit)
 Income taxes increased $78 million, or 21.1%, in 2023 as compared to 2022 primarily due to the flowback of $145 million of certain excess deferred income taxes that ended in 2022 and higher pre-tax earnings largely resulting from lower charges associated with the construction of Plant Vogtle Units 3 and 4, partially offset by an $85 million decrease in charges to a valuation allowance on certain state tax credit carryforwards, generation of $35 million of advanced nuclear PTCs, and a $32 million adjustment in 2022 related to a prior year state tax credit carryforward. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" and Note 10 to the financial statements for additional information.

 Mississippi Power's net income was $188 million in 2023 compared to $164 million in 2022. The increase was primarily due to an increase in affiliate wholesale capacity revenues, changes in power supply agreements, and a decrease in non-fuel operations and maintenance expenses, partially offset by an increase in interest expense.
 A condensed income statement for Mississippi Power follows:

 2023
 Increase
 (Decrease)
 from 2022

 $
 1,474
 $
 (220)

 Fuel and purchased power
 (251)

 (14)

 —

 1,214
 (256)

 (1)

 $
 $

 Operating revenues for 2023 were $1.5 billion, reflecting a $220 million, or 13.0%, decrease from 2022. Details of operating revenues were as follows:

 2023
 2022

 Retail — prior year
 $

 Estimated change resulting from —

 Rates and pricing
 (11)

 Sales growth

 Weather
 (4)

 Fuel and other cost recovery

 Retail — current year
 $
 $

 Wholesale revenues —

 Non-affiliates

 Affiliates

 Total wholesale revenues

 Other operating revenues

 $
 1,474
 $
 1,694

 II-28

 Total retail revenues for 2023 increased $28 million, or 3.0%, compared to 2022 primarily due to higher recoverable fuel costs and an increase in customer usage, partially offset by lower contributions from commercial and industrial customers with variable demand-driven pricing and lower revenues associated with a tolling arrangement accounted for as a sales-type lease. See Notes 2 and 9 to the financial statements under "Mississippi Power" and "Lessor," respectively, for additional information.
 See "Energy Sales" below for a discussion of changes in the volume of energy sold, including estimated changes related to sales and weather.
 Electric rates for Mississippi Power 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. 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. See Note 2 to the financial statements under "Mississippi Power – Fuel Cost Recovery" for additional information.
 Wholesale revenues from power sales to non-affiliated utilities, including FERC-regulated MRA sales as well as market-based sales, were as follows:

 2023
 2022

 Capacity and other
 $
 $

 Energy

 Total non-affiliated
 $
 $

 Wholesale revenues from sales to non-affiliates increased $20 million, or 7.9%, compared to 2022. The increase was primarily due to capacity revenues associated with new capacity contracts in 2023.
 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 a municipality located in southeastern Mississippi under requirements cost-based electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 14.0% of Mississippi Power's total operating revenues in 2023. Short-term opportunity energy sales are also included in sales for resale to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above Mississippi Power's variable cost to produce the energy. See Note 2 under "Mississippi Power – Municipal and Rural Associations Tariff" for additional information.
 Wholesale revenues from sales to affiliates decreased $260 million, or 56.5%, in 2023 compared to 2022. The decrease was primarily due to a $293 million decrease associated with lower natural gas prices, partially offset by a $23 million increase in capacity revenues resulting from availability of generation reserves and an increase in pricing and a $10 million increase associated with higher KWH sales.
 Wholesale revenues from sales to affiliates 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. The energy portion of these transactions does not have a significant impact on earnings since this energy is generally sold at marginal cost.
 In 2023, other operating revenues decreased $8 million, or 17.0%, as compared to 2022 primarily due to decreases of $5 million in unregulated sales associated with power delivery construction and maintenance projects and $3 million in open access transmission tariff revenues.
 II-29

 Energy Sales
 Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2023 and the percent change from 2022 were as follows:

 2023

 Total
KWHs
 Total KWH
Percent Change
 Weather-Adjusted Percent Change(*)

 2,092
 (1.9)
 %
 0.7
 %

 2,815
 7.0
 7.1

 4,721
 0.7
 0.7

 Other
 (11.1)
 (11.1)

 Total retail
 9,656
 1.8
 %
 2.5
 %

 Non-affiliated
 3,836
 10.7

 5,612
 2.2

 Total wholesale
 9,448
 5.5

 Total energy sales
 19,104
 3.6
 %

 (*)Weather-adjusted KWH sales are estimated using statistical models of the historical relationship between temperatures and energy sales, and then removing the estimated effect of deviations from normal temperature conditions. Normal temperature conditions are defined as those experienced in Mississippi Power's service territory over a specified historical period. This metric is useful because it allows trends in historical operations to be evaluated apart from the influence of weather conditions. Management also considers this metric in developing long-term capital and financial plans.
 Changes in retail energy sales are generally the result of changes in electricity usage by customers, weather, and the number of customers. Revenues attributable to changes in sales increased in 2023 when compared to 2022. Weather-adjusted residential KWH sales increased 0.7% due to an increase in customer usage. Weather-adjusted commercial KWH sales increased 7.1% primarily due to customer growth. Industrial KWH sales increased 0.7% primarily due to an increase in the non-manufacturing sector, partially offset by a decrease in the chemicals sector.
 See "Operating Revenues" above for a discussion of significant changes in wholesale revenues to affiliated companies.
 The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, Mississippi Power purchases a portion of its electricity needs from the wholesale market.
 Details of Mississippi Power's generation and purchased power were as follows:

 2023
 2022

 Total generation (in millions of KWHs)

 18,789
 18,303

 Total purchased power (in millions of KWHs)

 Sources of generation (percent) –

 Gas

 Coal

 Cost of fuel, generated (in cents per net KWH) –

 Gas
 2.68
 4.34

 Coal
 5.46
 4.13

 Average cost of fuel, generated (in cents per net KWH)

 2.90
 4.31

 Average cost of purchased power (in cents per net KWH)

 4.27
 6.91

 Fuel and purchased power expenses were $538 million in 2023, a decrease of $251 million, or 31.8%, as compared to 2022. The decrease was primarily due to a $266 million decrease related to the average cost of fuel and purchased power, partially offset by a $15 million net increase related to the volume of KWHs generated and purchased.
 II-30

 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 clauses. See Note 2 to the financial statements under "Mississippi Power – Fuel Cost Recovery" and Note 1 to the financial statements under "Fuel Costs" for additional information.
 Fuel expense decreased $230 million, or 30.8%, in 2023 compared to 2022 primarily due to a 38.2% decrease in the average cost of natural gas per KWH generated and a 20.3% decrease in the volume of KWHs generated by coal, partially offset by a 32.2% increase in the average cost of coal per KWHs generated and a 5.4% increase in the volume of KWHs generated by natural gas.
 Purchased power expense decreased $21 million, or 49.9%, in 2023 compared to 2022 primarily due to a 38.2% decrease in the average cost per KWH purchased primarily due to lower natural gas prices and a 15.1% decrease in the volume of KWHs purchased primarily due to the availability of lower cost generation in the Southern Company system.
 Energy purchases will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
 Other operations and maintenance expenses decreased $14 million, or 3.7%, in 2023 compared to 2022. The decrease was primarily due to decreases of $14 million in reliability reserve accruals, $7 million in generation expenses, and $6 million in unregulated power delivery construction and maintenance projects, partially offset by increases of $5 million in storm reserve accruals and $2 million in certain employee compensation and benefit expenses. See Note 2 to the financial statements under "Mississippi Power – System Restoration Rider" and " – Reliability Reserve Accounting Order" for additional information.
 Depreciation and amortization increased $9 million, or 5.0%, in 2023 compared to 2022 primarily due to an increase in depreciation associated with additional plant in service.
 Interest expense, net of amounts capitalized increased $15 million, or 26.8%, in 2023 compared to 2022. The increase was primarily due to increases of approximately $10 million related to higher interest rates and $5 million related to higher average outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein and Note 8 to the financial statements for additional information.
 Income taxes decreased $1 million, or 2.7%, in 2023 compared to 2022 primarily due to a decrease of $7 million associated with the flowback of certain excess deferred income taxes associated with new PEP rates that became effective in April 2023, largely offset by an increase of $6 million associated with higher pre-tax earnings. See Note 2 to the financial statements under "Mississippi Power – Performance Evaluation Plan" and Note 10 to the financial statements for additional information.
 II-31

 Net income attributable to Southern Power for 2023 was $357 million, a $3 million increase from 2022. The increase was primarily due to higher HLBV income associated with tax equity partnerships, an arbitration award received for losses previously incurred, a gain on the sale of spare parts, 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.

 A condensed statement of income follows:

 2023
 Increase
 (Decrease)
 from 2022

 $
 2,189
 $
 (1,180)

 Fuel
 (908)

 (195)

 (9)

 (12)

 Loss on sales-type leases
 —
 (1)

 (20)
 (18)

 1,830
 (1,141)

 (39)

 (9)

 (8)

 (17)

 Net loss attributable to noncontrolling interests
 (127)
 (20)

 Net income attributable to Southern Power
 $
 $

 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 generally accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.
 Solar and Wind Energy Revenue
 Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have capacity revenue. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy generated from the respective facility and sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors.
 II-32

 See FUTURE EARNINGS POTENTIAL – "Southern Power's Power Sales Agreements" herein for additional information regarding Southern Power's PPAs.
 Operating Revenues Details
 Details of Southern Power's operating revenues were as follows:
 2023
 2022

 PPA capacity revenues
 $
 $

 PPA energy revenues
 1,227
 2,121

 Total PPA revenues
 1,698
 2,572

 Non-PPA revenues

 $
 2,189
 $
 3,369

 Operating revenues for 2023 were $2.2 billion, a $1.2 billion, or 35.0% decrease from 2022. The change in operating revenues was primarily due to the following:
 • PPA capacity revenues increased $20 million, or 4.4%, primarily due to an increase associated with a change in rates from new and existing natural gas PPAs.
 • PPA energy revenues decreased $894 million, or 42.1%, primarily due to a $904 million decrease in sales under natural gas PPAs resulting from a $726 million decrease in the price of fuel and purchased power and a $178 million decrease in the volume of KWHs sold.
 • Non-PPA revenues decreased $325 million, or 42.7%, primarily due to a $650 million decrease in the market price of energy, partially offset by a $321 million increase in the volume of KWHs sold through short-term sales.
 • Other revenues increased $19 million, or 52.8%, primarily due to receipts of liquidated damages associated with generation facility production guarantees, an arbitration award received for losses previously incurred, and business interruption insurance proceeds for damaged generation equipment. See Note 3 to the financial statements under "General Litigation Matters – Southern Power" for additional information.

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

 Total
KWHs
 Total KWH % Change
 Total
KWHs

 2023
 2022

 (in billions of KWHs)

 Generation

 Total generation and purchased power
 2.0%

 Total generation and purchased power (excluding solar, wind, fuel cells, and tolling agreements)

 6.5%

 Southern Power's PPAs for natural gas generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the Southern Company power pool for capacity owned directly by Southern Power.
 Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the Southern Company power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.
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 Details of Southern Power's fuel and purchased power expenses were as follows:
 2023
 2022

 Fuel
 $
 $
 1,614

 Total fuel and purchased power expenses
 $
 $
 1,925

 In 2023, total fuel and purchased power expenses decreased $1.1 billion, or 57.3%, compared to 2022. Fuel expense decreased $908 million, or 56.3%, primarily due to a $1.0 billion decrease associated with the average cost of fuel. Purchased power expense decreased $195 million, or 62.7%, primarily due to a $206 million decrease associated with the average cost of purchased power.

 Gain on Dispositions, Net
 In 2023, gain on dispositions, net increased $18 million compared to 2022 primarily due to a $16 million gain on the sale of spare parts in 2023.
 In 2023, interest expense, net of amounts capitalized decreased $9 million, or 6.5%, compared to 2022. The decrease was primarily due to lower average outstanding borrowings.
 Income Taxes (Benefit)
 In 2023, income taxes decreased $8 million, or 40.0%, compared to 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. See Notes 1 and 10 to the financial statements under "Income Taxes" and "Effective Tax Rate," respectively, for additional information.
 Net Loss Attributable to Noncontrolling Interests
 In 2023, net loss attributable to noncontrolling interests increased $20 million, or 18.7%, compared to 2022. The increased loss was primarily due to $25 million in higher HLBV loss allocations to wind tax equity partners and $5 million in lower income allocations to equity partners, partially offset by $10 million in lower HLBV loss allocations to battery energy storage partners.

 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 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.
 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 can vary significantly from quarter to quarter as a result of seasonality, which is illustrated in the table below.

 Percent Generated During
Heating Season

 Net
Income

 2023
 %
 %

 2022
 %
 %

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 Net income attributable to Southern Company Gas in 2023 was $615 million, an increase of $43 million, or 7.5%, compared to 2022. Net income increased primarily as a result of an impairment charge in 2022 related to the sale of natural gas storage facilities. The increase in net income was partially offset by a decrease of $29 million in net income at gas distribution operations primarily as a result of reduced revenue due to lower volumes sold, regulatory disallowances at Nicor Gas, and higher depreciation related to continued investment in infrastructure replacement programs, partially offset by lower cost of gas, and a $9 million decrease in net income at gas pipeline investments primarily as a result of higher expenses at SNG.
 A condensed income statement for Southern Company Gas follows:

 2023
 Increase (Decrease) from 2022

 $
 4,702
 $
 (1,260)

 1,644
 (1,360)

 1,194

 (20)

 —
 (131)

 (7)
 (3)

 3,763
 (1,385)

 (8)

 Earnings before income taxes

 $
 $

 Operating revenues in 2023 were $4.7 billion, reflecting a $1.3 billion, or 21.1%, decrease compared to 2022. Details of operating revenues were as follows:

 2023

 Operating revenues – prior year
 $
 5,962

 Estimated change resulting from –

 Infrastructure replacement programs and base rate changes

 Gas costs and other cost recovery
 (1,323)

 (93)

 Other
 (38)

 Operating revenues – current year
 $
 4,702

 Revenues from infrastructure replacement programs and base rate changes increased in 2023 primarily due to rate increases at the natural gas distribution utilities and continued investment in infrastructure replacement, partially offset by lower volumes sold and regulatory disallowances at Nicor Gas. See Note 2 to the financial statements under "Southern Company Gas" for additional information.
 Revenues associated with gas costs and other cost recovery decreased in 2023 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. The natural gas distribution utilities have weather or revenue normalization mechanisms that mitigate revenue fluctuations from
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 customer consumption changes. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. See "Cost of Natural Gas" herein for additional information.
 Revenues from gas marketing services decreased in 2023 primarily due to lower natural gas prices and the timing of unrealized hedge losses.
 Customer Count
 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.
 The following table provides the number of customers served by Southern Company Gas at December 31, 2023 and 2022:

 2023
 2022

 (in thousands, except market share %)

 Gas distribution operations
 4,374
 4,358

 Energy customers

 Market share of energy customers in Georgia
 30.0
 %
 29.3
 %

 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
 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. See Note 2 to the financial statements under "Southern Company Gas – Natural Gas Cost Recovery" for additional information. Cost of natural gas at gas distribution operations represented 83.5% of the total cost of natural gas for 2023.
 Gas marketing services customers are charged for actual and estimated natural gas consumed. Cost of natural gas includes the cost of fuel and associated transportation costs, lost and unaccounted for gas, and gains and losses associated with certain derivatives.
 In 2023, cost of natural gas was $1.6 billion, a decrease of $1.4 billion, or 45.3%, compared to 2022, which reflects lower gas cost recovery in 2023 as a result of a 58.8% decrease in natural gas prices compared to 2022.
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 Volumes of Natural Gas Sold
 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.
 The following table details the volumes of natural gas sold during all periods presented:

 2023 vs. 2022

 2023
 2022
 % Change

 Gas distribution operations (mmBtu in millions)

 Firm
 (11.6)
 %

 Interruptible
 —

 Total
 (10.3)
 %

 Gas marketing services (mmBtu in millions)

 Firm:

 (5.7)
 %

 Other
 5.6

 Interruptible large commercial and industrial
 —

 Total
 (1.5)
 %

 In 2023, other operations and maintenance expenses increased $18 million, or 1.5%, compared to 2022. The increase was primarily due to increases of $70 million in compensation and benefits and $20 million related to energy service contracts, partially offset by a decrease of $60 million in expenses passed through to customers primarily related to bad debt and energy efficiency programs at gas distribution operations. See Note 2 to the financial statements under "Southern Company Gas" for additional information.
 In 2023, depreciation and amortization increased $23 million, or 4.1%, compared to 2022. The increase was primarily due to continued infrastructure investments at the natural gas distribution utilities. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" for additional information.
 Taxes Other Than Income Taxes
 In 2023, taxes other than income taxes decreased $20 million, or 7.1%, compared to 2022. The decrease was primarily due to a $29 million decrease in revenue taxes, partially offset by increases in payroll and property taxes.
 Impairment Charges
 In 2022, Southern Company Gas recorded pre-tax impairment charges totaling approximately $131 million ($99 million after tax) as a result of an agreement to sell two natural gas storage facilities. See Note 15 to the financial statements under "Southern Company Gas" for additional information.
 Estimated Loss on Regulatory Disallowance
 In 2023, Southern Company Gas recorded pre-tax charges related to the disallowance of certain capital investments at Nicor Gas, $88 million of which was recorded in estimated loss on regulatory disallowance. See Note 2 under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects – Nicor Gas" for additional information.
 In 2023, interest expense, net of amounts capitalized increased $47 million, or 17.9%, compared to 2022. The increase reflects $43 million related to higher interest rates and $8 million related to higher average outstanding borrowings. See Note 8 to the financial statements for additional information.
 In 2023, income taxes increased $31 million, or 17.2%, compared to 2022. The increase was primarily due to $33 million of tax benefit in 2022 related to the impairment charges associated with the sale of two natural gas storage facilities and higher taxes
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 related to increased earnings, partially offset by approximately $24 million related to the regulatory disallowances at Nicor Gas. See Notes 2 and 15 to the financial statements under "Southern Company Gas" and Note 10 to the financial statements for additional information.
 Segment Information

 2023
 2022

 Operating Expenses
 Net Income (Loss)
 Operating Expenses
 Net Income (Loss)

 Gas distribution operations
 $
 4,105
 $
 3,301
 $
 $
 5,267
 $
 4,464
 $

 Gas pipeline investments

 All other
 (15)
 (99)

 Intercompany eliminations
 (19)
 (6)
 —
 (30)
 (22)
 —

 Consolidated
 $
 4,702
 $
 3,763
 $
 $
 5,962
 $
 5,148
 $

 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" for additional information.
 In 2023, net income decreased $29 million, or 6.2%, compared to 2022. Operating revenues decreased $1.2 billion primarily due to lower gas cost recovery and lower volumes sold, 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 $1.2 billion primarily due to a $1.3 billion decrease in the cost of natural gas as a result of lower gas prices compared to 2022 and lower taxes other than income taxes, partially offset by $88 million related to the regulatory disallowances at Nicor Gas, higher depreciation resulting from additional assets placed in service, higher compensation and benefits expenses, 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. The decrease in net income also includes an increase of $46 million in interest expense, net of amounts capitalized primarily due to higher interest rates and higher average outstanding debt, partially offset by a $19 million decrease in income taxes primarily as a result of the tax benefit resulting from the regulatory disallowances at Nicor Gas. See Note 2 to the financial statements under "Southern Company Gas" for additional information.
 Gas Pipeline Investments
 Gas pipeline investments consists primarily of joint ventures in natural gas pipeline investments including SNG and Dalton Pipeline. In 2023, net income decreased $9 million compared to 2022. The decrease was primarily due to lower earnings at SNG resulting from higher expenses. See Note 7 to the financial statements under "Southern Company Gas" 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
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 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 2023, net income decreased $3 million, or 3.2%, compared to 2022. The decrease was due to a $90 million decrease in operating revenues primarily due to lower gas prices and the timing of unrealized hedge losses, largely offset by an $87 million decrease in operating expenses primarily related to a $106 million decrease in cost of gas, partially offset by higher compensation and benefits.
 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 under "Southern Company Gas" for additional information.
 In 2023, net income increased $84 million compared to 2022. The increase was primarily due to a decrease in operating expenses primarily related to pre-tax impairment charges in 2022 totaling approximately $131 million ($99 million after tax) as a result of an agreement to sell two natural gas storage facilities, lower depreciation, lower cost of gas, and lower taxes other than income taxes, partially offset by a decrease in operating revenues of $19 million and an increase in income taxes. See Note 10 to the financial statements and Note 15 to the financial statements under "Southern Company Gas" for additional information.

 FUTURE EARNINGS POTENTIAL
 General
 Prices for electric service provided by the traditional electric operating companies and natural gas distribution service provided by the natural gas distribution utilities to retail customers are set by state PSCs or other applicable state regulatory agencies under cost-based regulatory principles. Retail rates and earnings are reviewed through various regulatory mechanisms and/or processes and may be adjusted periodically within certain limitations. Effectively operating pursuant to these regulatory mechanisms and/or processes and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the traditional electric operating companies and natural gas distribution utilities for the foreseeable future. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Southern Power continues to focus on long-term PPAs. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Utility Regulation" herein and Note 2 to the financial statements for additional information about regulatory matters.
 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 and meeting the related cost and schedule projections.
 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 affected by higher-than-expected inflation that arose from the COVID-19 pandemic and associated policy responses of governments and central banks. In response to elevated inflation levels, the U.S. Federal Reserve raised interest rates faster than any rate increase cycle in the last 40 years. The actions by the U.S. Federal Reserve have helped to slow the rate of inflation and curtail economic activity. Although target levels of inflation have yet to be achieved, the U.S. Federal Reserve has indicated its current intention to pause future rate increases and evaluate rate cuts in the near term. The shifting economic policy variables and weakening of historic relationships among economic activity, prices, and employment have increased the uncertainty of future levels of economic activity, which will directly impact future energy demand and operating costs. Weakening economic activity increases the risk of slowing or declining energy sales. See RESULTS OF OPERATIONS herein for information on energy sales in the Southern Company system's service territory during 2023.
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 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 "Income Tax Matters" herein for information regarding the IRA's expansion of the availability of federal ITCs and PTCs. Also see Notes 10 and 15 to the financial statements for additional information.
 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 in Illinois and across certain other 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.
 Mississippi Power provides service under long-term contracts with rural electric cooperative associations and a municipality located in southeastern Mississippi under requirements cost-based electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 14.0% of Mississippi Power's total operating revenues in 2023.
 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 for additional information.

 Environmental Matters
 The Southern Company system's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, avian and other wildlife and habitat protection, and other natural resources. The Southern Company system maintains comprehensive environmental compliance and GHG strategies to assess both current and upcoming requirements and compliance costs associated with these environmental laws and regulations. New or revised environmental laws and regulations could further affect many areas of operations for the Subsidiary Registrants. The costs required to comply with environmental laws and regulations and to achieve stated goals, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, may impact future electric generating unit retirement and replacement decisions (which are generally subject to approval from the traditional electric operating companies' respective state PSCs), results of operations, cash flows, and/or financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, or changing fuel sources for certain existing
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 units, as well as related upgrades to the Southern Company system's transmission and distribution (electric and natural gas) systems. A major portion of these costs is expected to be recovered through retail and wholesale rates, including existing ratemaking and billing provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed herein cannot be determined at this time and will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, the outcome of pending and/or future legal challenges and regulatory matters, and the ability to continue recovering the related costs, through rates for the traditional electric operating companies and the natural gas distribution utilities and/or through long-term wholesale agreements for the traditional electric operating companies and Southern Power.
 Alabama Power and Mississippi Power recover environmental compliance costs through separate mechanisms, Rate CNP Compliance and the ECO Plan, respectively. Georgia Power's base rates include an ECCR tariff that allows for the recovery of environmental compliance costs. The natural gas distribution utilities of Southern Company Gas generally recover environmental remediation expenditures through rate mechanisms approved by their applicable state regulatory agencies. See Notes 2 and 3 to the financial statements for additional information.
 Southern Power's PPAs generally contain provisions that permit charging the counterparty for some of the new costs incurred as a result of changes in environmental laws and regulations. Since Southern Power's units are generally newer natural gas and renewable generating facilities, costs associated with environmental compliance for these facilities have been less significant than for similarly situated coal or older natural gas generating facilities. Environmental, natural resource, and land use concerns, including the applicability of air quality limitations, the potential presence of wetlands or threatened and endangered species, the availability of water withdrawal rights, uncertainties regarding impacts such as increased light or noise, and concerns about potential adverse health impacts can, however, increase the cost of siting and/or operating any type of existing or future facility. The impact of such laws, regulations, and other considerations on Southern Power and subsequent recovery through PPA provisions cannot be determined at this time.
 Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity and natural gas, which could negatively affect results of operations, cash flows, and/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which may have the potential to affect their demand for electricity and natural gas.
 Although the timing, requirements, and estimated costs could change as environmental laws and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are initiated or completed, estimated capital expenditures through 2028 based on the current environmental compliance strategy for the Southern Company system and the traditional electric operating companies are as follows:

 2024
 2025
 2026
 2027
 2028
 Total

 $
 $
 $
 $
 $
 $

 These estimates do not include compliance costs associated with potential regulation of GHG emissions or the proposed ELG Supplemental Rule. See "Environmental Laws and Regulations – Greenhouse Gases" and " – Water Quality" herein for additional information. The Southern Company system also anticipates substantial expenditures associated with ash pond closure and groundwater monitoring under the CCR Rule and related state rules, which are reflected in the applicable Registrants' ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" herein and Note 6 to the financial statements for additional information.
 Environmental Laws and Regulations
 Air Quality
 Since 1990, the Southern Company system reduced SO2 and NOX air emissions by 99% and 92%, respectively, through 2022. Since 2005, the Southern Company system reduced mercury air emissions by 97% through 2022.
 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
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 Fifth Circuit. On June 8, 2023, the U.S. Court of Appeals for the Fifth Circuit stayed the EPA's disapproval of the Mississippi SIP, pending appeal. 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 August 17, 2023, the U.S. Court of Appeals for the Eleventh Circuit stayed the EPA's disapproval of the Alabama SIP, pending appeal.
 On June 5, 2023, the EPA published the 2015 Ozone NAAQS Good Neighbor federal implementation plan (FIP), which requires reductions in NOX emissions from sources in 23 states, including Alabama and Mississippi, to assure those states satisfy their Clean Air Act good neighbor obligations for the 2015 Ozone NAAQS. Georgia and North Carolina have approved interstate transport SIPs addressing the 2015 Ozone NAAQS and are not subject to this rule. 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 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. Both cases are being held in abeyance pending resolution of the Mississippi SIP disapproval and Alabama SIP disapproval cases, respectively.
 In July and September 2023, the EPA published an Interim Final Rule and an updated Interim Final Rule that stays the implementation of the FIPs for states with judicially stayed SIP disapprovals, including Mississippi and Alabama, respectively. 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
 In 2020, the EPA published the final steam electric ELG reconsideration rule (ELG Reconsideration Rule), a reconsideration of the 2015 ELG rule's limits on bottom ash transport water and flue gas desulfurization wastewater that extended the latest applicability date for both discharges to December 31, 2025. The ELG Reconsideration Rule also updated the voluntary incentive program and provided new subcategories for low utilization electric generating units and electric generating units that will permanently cease coal combustion by 2028. 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. The proposal also maintains the Voluntary Incentive Program (VIP) subcategory, which allows units to comply with VIP limits by December 31, 2028. 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.
 As required by the ELG Reconsideration Rule, in 2021, Alabama Power and Georgia Power each submitted initial notices of planned participation (NOPP) for applicable units seeking to qualify for these cessation of coal combustion or VIP subcategories that require compliance by December 31, 2028.
 Alabama Power submitted its NOPP to the Alabama Department of Environmental Management (ADEM) indicating plans to retire Plant Barry Unit 5 (700 MWs) and to cease using coal and begin operating solely on natural gas at Plant Barry Unit 4 (350 MWs) and Plant Gaston Unit 5 (880 MWs). Alabama Power, as agent for SEGCO, indicated plans to retire Plant Gaston Units 1 through 4 (1,000 MWs). However, Alabama Power, in conjunction with Georgia Power, is evaluating extending the operation of Plant Gaston Units 1 through 4 beyond the indicated retirement date. The NOPP submittals are subject to the review of the ADEM. Plant Barry Unit 4 ceased using coal and began to operate solely on natural gas in December 2022. See Notes 2 and 7 to the financial statements under "Georgia Power – Integrated Resource Plans" and "SEGCO," respectively, for additional information.
 The remaining assets for which Alabama Power has indicated retirement, due to early closure or repowering of the unit to natural gas, have net book values totaling approximately $1.2 billion (excluding capitalized asset retirement costs which are recovered through Rate CNP Compliance) at December 31, 2023. Based on an Alabama PSC order, Alabama Power is authorized to establish a regulatory asset to record the unrecovered investment costs, including the plant asset balance and the site removal and closure costs, associated with unit retirements caused by environmental regulations (Environmental Accounting Order). Under the Environmental Accounting Order, the regulatory asset would be amortized and recovered over an affected unit's remaining useful life, as established prior to the decision regarding early retirement, through Rate CNP Compliance. See Note 2 to the financial statements under "Alabama Power – Rate CNP Compliance" and " – Environmental Accounting Order" for additional information.
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 Georgia Power submitted its NOPP to the Georgia Environmental Protection Division (EPD) indicating plans to retire Plant Wansley Units 1 and 2 (926 MWs based on 53.5% ownership), which occurred in August 2022, Plant Bowen Units 1 and 2 (1,400 MWs), and Plant Scherer Unit 3 (614 MWs based on 75% ownership) on or before the compliance date of December 31, 2028. Georgia Power also submitted a NOPP indicating plans to pursue compliance with the ELG Reconsideration Rule for Plant Scherer Units 1 and 2 (137 MWs based on 8.4% ownership) through the voluntary incentive program by no later than December 31, 2028. Georgia Power intends to comply with the ELG Rules for Plant Bowen Units 3 and 4 through the generally applicable requirements by December 31, 2025; therefore, no NOPP submission was required for these units. The NOPP submittals and generally applicable requirements are subject to the review of the Georgia EPD and decisions related to retirement or continued operation of units are subject to Georgia PSC approval. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" for additional information.
 Coal Combustion Residuals
 In 2015, the EPA finalized non-hazardous solid waste regulations for the management and disposal of CCR, including coal ash and gypsum, in landfills and surface impoundments (ash ponds) at active electric generating power plants. The CCR Rule requires landfills and ash ponds to be evaluated against a set of performance criteria and potentially closed if certain criteria are not met. Closure of existing landfills and ash ponds requires installation of equipment and infrastructure to manage CCR in accordance with the CCR Rule. In addition to the federal CCR Rule, the States of Alabama and Georgia finalized state regulations regarding the management and disposal of CCR within their respective states. In 2019, the State of Georgia received partial approval from the EPA for its state CCR permitting program, which has broader applicability than the federal rule. The State of Mississippi has not developed a state CCR permit program.
 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.
 The Holistic Approach to Closure: Part A rule, finalized in 2020, revised the deadline to stop sending CCR and non-CCR wastes to unlined surface impoundments to April 11, 2021 and established a process for the EPA to approve extensions to the deadline. The traditional electric operating companies stopped sending CCR and non-CCR wastes to their unlined impoundments prior to April 11, 2021 and, therefore, did not submit requests for extensions. Beginning in January 2022, the EPA issued numerous Part A determinations that state its current positions on a variety of CCR Rule compliance requirements, such as criteria for groundwater corrective action and CCR unit closure. The traditional electric operating companies are working with state regulatory agencies to determine whether the EPA's current positions may impact closure and groundwater monitoring plans.
 In April 2022, the Utilities Solid Waste Activities Group and a group of generating facility operators filed petitions for review in the U.S. Court of Appeals for the D.C. Circuit challenging whether the EPA's January 2022 actions establish new legislative rules that should have gone through notice-and-comment rulemaking. A decision by the court is expected in 2024. The ultimate impacts of the EPA's current positions are subject to the outcome of the pending litigation and any potential future rulemaking and cannot be determined at this time.
 On May 18, 2023, the EPA published a proposed rule to establish two new categories of federally regulated CCR, legacy surface impoundments and CCR management units (CCRMUs). 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 a definition for CCRMUs. The EPA's proposal would also require facility evaluations to be completed at both active facilities and inactive facilities with one or more legacy surface impoundment to determine the presence or absence of CCRMUs. CCRMUs must comply with the CCR Rule's provisions for groundwater monitoring, corrective action, closure, and post-closure activities. On November 14, 2023, the EPA published a Notice of Data Availability supplementing the proposed rule, which sought comment on new data and a supplemental risk assessment that could be used to support final rulemaking. 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.
 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 FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements," Notes 2 and 3 to the financial statements under "Georgia Power – Rate Plans" and "General Litigation Matters – Alabama Power," respectively, and Note 6 to the financial statements for additional information.
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 Greenhouse Gases
 On May 23, 2023, the EPA published proposed GHG standards and state plan guidelines for fossil fuel-fired power plants, which would require GHG limits for subcategories of 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 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 may allow states to implement 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 subcategory. The EPA also proposes to simultaneously repeal the Affordable Clean Energy rule. On November 17, 2023, the EPA published a final rule updating the regulations governing the processes and timelines for state and federal plans to implement existing source GHG performance standards. While this rule establishes the general requirements and timelines for states to follow in implementing the EPA's emissions guidelines, the pending final rule for GHG emissions from fossil fuel-fired power plants is expected to include schedules and other implementation requirements that will supersede these general provisions. On November 20, 2023, the EPA published a Supplemental Notice of Proposed Rulemaking for the pending rules for fossil fuel-fired power plants requesting additional input on how the EPA should address reliability concerns in the final rules. 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.
 In 2021, the United States officially rejoined the Paris Agreement. The Paris Agreement establishes a non-binding universal framework for addressing GHG emissions based on nationally determined emissions reduction contributions and sets in place a process for tracking progress towards the goals every five years. In 2021, President Biden announced a new target for the United States to achieve a 50% to 52% reduction in economy-wide GHG emissions from 2005 levels by 2030. The target was accepted by the United Nations as the United States' nationally determined emissions reduction contribution under the Paris Agreement.
 Additional GHG policies, including legislation, may emerge in the future requiring the United States to accelerate its transition to a lower GHG emitting economy; however, associated impacts are currently unknown. The Southern Company system has transitioned from an electric generating mix of 70% coal and 15% natural gas in 2007 to a mix of 17% coal and 54% natural gas in 2023. This transition has been supported in part by the Southern Company system retiring over 6,700 MWs of coal-fired generating capacity since 2010 and converting 3,700 MWs of generating capacity from coal to natural gas since 2015. In addition, the Southern Company system's capacity mix consists of over 11,600 MWs of renewable and storage facilities through ownership and long-term PPAs. See "Environmental Laws and Regulations – Water Quality" herein for information on plans to retire or convert to natural gas additional coal-fired generating capacity. In addition, Southern Company Gas has replaced over 6,000 miles of pipe material that was more prone to fugitive emissions (unprotected steel and cast-iron pipe), resulting in mitigation of more than 3.3 million metric tons of CO2 equivalents from its natural gas distribution system since 1998.
 The following table provides the Registrants' 2022 and preliminary 2023 Scope 1 GHG emissions based on equity share of facilities:

 2022
 Preliminary 2023

 (in million metric tons of CO2 equivalent)

 Alabama Power(*)

 Southern Company Gas(*)

 (*)Includes GHG emissions attributable to disposed assets through the date of the applicable disposition and to acquired assets beginning with the date of the applicable acquisition. See Note 15 to the financial statements for additional information.
 Southern Company system management has established an intermediate goal of a 50% reduction in GHG emissions from 2007 levels by 2030 and a long-term goal of net zero GHG emissions by 2050. Based on the preliminary 2023 emissions, the Southern Company system has achieved an estimated GHG emission reduction of 49% since 2007. GHG emissions decreased in 2023 when compared to 2022 as coal generation was displaced by lower carbon generation, including from Plant Vogtle Unit 3, as discussed further under RESULTS OF OPERATIONS – "Southern Company – Electricity Business" herein. Southern Company system management expects to achieve GHG reductions of greater than 50% as early as 2025, five years earlier than the established interim goal, and remain close to 50% through the late 2020s, followed thereafter by continued reductions. While none
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 of Southern Company's subsidiaries are currently subject to renewable portfolio standards or similar requirements, management of the traditional electric operating companies is working with applicable regulators through their IRP processes to continue the generating fleet transition in a manner responsible to customers, communities, employees, and other stakeholders. Achievement of these goals is dependent on many factors, including natural gas prices and the pace and extent of development and deployment of low- to no-GHG energy technologies and negative carbon concepts. Southern Company system management plans to continue to pursue a diverse portfolio including low-carbon and carbon-free resources and energy efficiency resources; continue to transition the Southern Company system's generating fleet and make the necessary related investments in transmission and distribution systems; implement initiatives to reduce natural gas distribution operational emissions; continue its research and development with a particular focus on technologies that lower GHG emissions, including methods of removing carbon from the atmosphere; and constructively engage with policymakers, regulators, investors, customers, and other stakeholders to support outcomes leading to a net zero future.
 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 Southern Company Gas conduct studies to determine the extent of any required cleanup and have recognized the estimated costs to clean up known impacted sites in their financial statements. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The traditional electric operating companies and the natural gas distribution utilities in Illinois and Georgia (which represent substantially all of Southern Company Gas' accrued remediation costs) have all 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. The traditional electric operating companies and Southern Company Gas may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under "Environmental Remediation" for additional information.

 Regulatory Matters
 See OVERVIEW – "Recent Developments" herein and Note 2 to the financial statements 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.
 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 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information. Also see Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" for information regarding Georgia Power's request with the Georgia PSC to develop, own, and operate three simple cycle combustion turbines at Plant Yates.
 See Note 15 to the financial statements under "Southern Power" 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 under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" for additional information on Southern Company Gas' construction program.
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 See FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" herein for additional information regarding the Registrants' capital requirements for their construction programs, including estimated totals for each of the next five years.

 Southern Power's Power Sales Agreements
 General
 Southern Power has PPAs with some of the traditional electric operating companies, other investor-owned utilities, IPPs, municipalities, and other load-serving entities, as well as commercial and industrial customers. The PPAs are expected to provide Southern Power with a stable source of revenue during their respective terms.
 Many of Southern Power's PPAs have provisions that require Southern Power or the counterparty to post collateral or an acceptable substitute guarantee if (i) S&P or Moody's downgrades the credit ratings of the respective company to an unacceptable credit rating, (ii) the counterparty is not rated, or (iii) the counterparty fails to maintain a minimum coverage ratio. See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information.
 Southern Power works to maintain and expand its share of the wholesale market. During 2023, Southern Power continued to be successful in remarketing up to 438 MWs of annual natural gas generation capacity to load-serving entities through several PPAs extending over the next 16 years. Market demand is being driven by load-serving entities replacing expired purchase contracts and/or retired generation, as well as planning for future growth.
 Southern Power's electricity sales from natural gas facilities are primarily through long-term PPAs that consist of two types of agreements. The first type, referred to as a unit or block sale, is a customer purchase from a dedicated generating unit where all or a portion of the generation from that unit is reserved for that customer. Southern Power typically has the ability to serve the unit or block sale customer from an alternate resource. The second type, referred to as requirements service, provides that Southern Power serve the customer's capacity and energy requirements from a combination of the customer's own generating units and from Southern Power resources not dedicated to serve unit or block sales. Southern Power has rights to purchase power provided by the requirements customers' resources when economically viable.
 As a general matter, substantially all of the PPAs 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 or purchased power relating to the energy delivered under such PPAs. To the extent a particular generating facility does not meet the operational requirements contemplated in the PPAs, Southern Power may be responsible for excess fuel costs. With respect to fuel transportation risk, most of Southern Power's PPAs provide that the counterparties are responsible for the availability of fuel transportation to the particular generating facility.
 Capacity charges that form part of the PPA payments are designed to recover fixed and variable operation and maintenance costs based on dollars-per-kilowatt year. In general, to reduce Southern Power's exposure to certain operation and maintenance costs, Southern Power has LTSAs. See Note 1 to the financial statements under "Long-Term Service Agreements" for additional information.
 Solar and Wind
 Southern Power's electricity sales from solar and wind generating facilities are also primarily through long-term PPAs; however, these PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or provide Southern Power a certain fixed price for the electricity sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Generally, under the renewable generation PPAs, the purchasing party retains the right to keep or resell the associated renewable energy credits.

 Income Tax Matters
 Consolidated Income Taxes
 The impact of certain tax events at Southern Company and/or its other subsidiaries can, and does, affect each Registrant's ability to utilize certain tax credits. See "Tax Credits" and ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Accounting for Income Taxes" herein and Note 10 to the financial statements for additional information.
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 Tax Credits
 Southern Company has received ITCs and PTCs in connection with investments in solar, wind, fuel cell, advanced nuclear, and battery energy storage facilities (co-located with existing solar facilities) primarily at Southern Power and Georgia Power.
 Southern Power's ITCs relate to its investment in new solar facilities and battery energy storage facilities (co-located with existing solar facilities) that are acquired or constructed and its PTCs relate to the first 10 years of energy production from its wind facilities, which have had, and may continue to have, a material impact on Southern Power's cash flows and net income. At December 31, 2023, Southern Company and Southern Power had approximately $0.8 billion and $0.5 billion, respectively, of unutilized federal ITCs and PTCs, which are currently expected to be fully utilized by 2029, but could be further delayed. Since 2018, Southern Power has been utilizing tax equity partnerships for wind, solar, and battery energy storage projects, where the tax equity partner takes significantly all of the respective federal tax benefits. These tax equity partnerships are consolidated in Southern Company's and Southern Power's financial statements using the HLBV methodology to allocate partnership gains and losses.
 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 2 to the financial statements under "Georgia Power – Nuclear Construction – Joint Owner Contracts"), Georgia Power is purchasing advanced nuclear PTCs for Plant Vogtle Unit 3 from the other Vogtle Owners. The gain recognized on the purchase of the joint owner PTCs is recognized as an income tax benefit. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
 See Note 1 to the financial statements under "General" for additional information on the HLBV methodology and Note 1 to the financial statements under "Income Taxes" and Note 10 to the financial statements under "Deferred Tax Assets and Liabilities – Tax Credit Carryforwards" and "Effective Tax Rate" for additional information regarding utilization and amortization of credits and the tax benefit related to associated basis differences.
 Inflation Reduction Act
 In August 2022, the IRA was signed into law. The IRA extends, expands, and increases ITCs and PTCs for clean energy projects, allows PTCs for solar projects, adds ITCs for stand-alone energy storage projects with an option to elect out of the tax normalization requirement, and allows for the transferability of the tax credits. The IRA extends and increases the tax credits for carbon capture and sequestration projects and adds tax credits for clean hydrogen and nuclear projects. Additional ITC and PTC amounts are available if the projects meet domestic content requirements or are located in low-income or energy communities. The IRA also enacted a 15% corporate minimum tax on book income, with material adjustments for pension costs and tax depreciation. The 15% corporate minimum tax on book income can be reduced by energy tax credits.
 For solar projects placed in service in 2022 through 2032, the IRA provides for a 30% ITC and an option to claim a PTC instead of an ITC. Starting in 2023 and through 2032, the IRA provides for a 30% ITC for stand-alone energy storage projects. For wind projects placed in service in 2022 through 2032, the IRA provides for a 100% PTC, adjusted for inflation annually. For projects placed in service before 2022, the 2023 PTC rate is 2.8 cents per KWH. For projects placed in service in 2022 and later, the 2023 PTC rate is 2.75 cents per KWH. The same PTC rate applies for solar projects for which the PTC option has been elected. To realize the full value of ITCs and PTCs, the IRA requires satisfaction of prevailing wage and apprenticeship requirements.
 In June 2023, the IRS issued temporary regulations related to the transferability of tax credits. During the fourth quarter 2023, Southern Power executed an agreement to transfer certain PTCs generated in 2023. The discount recognized was booked through income tax expense and was immaterial. Southern Company and certain subsidiaries are considering the sale of additional tax credits that are eligible to be transferred.
 Implementation of the IRA provisions is subject to the issuance of additional guidance by the U.S. Treasury Department and the IRS. The Registrants are still evaluating the impacts and the ultimate outcome of this matter cannot be determined at this time.
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 Natural Gas Safe Harbor Method
 In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor tax method of accounting that taxpayers may use to determine whether certain expenditures to maintain, repair, replace, or improve natural gas transmission and distribution property must be capitalized or allowed as repair deductions. The revenue procedure allows multiple alternatives for implementation which will result in a tax accounting method change for Southern Company Gas' eligible expenditures. Due to the complexity of analysis needed and the various implementation options allowed under the revenue procedure, Southern Company and Southern Company Gas are still evaluating the impacts and the ultimate outcome of this matter cannot be determined at this time. See Note 10 to the financial statements under "Deferred Tax Assets and Liabilities – Tax Credit Carryforwards" for additional information.

 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 2 and 3 to the financial statements, 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 2 and 3 to the financial statements for a discussion of various contingencies, including matters being litigated, regulatory matters, and other matters which may affect future earnings potential.

 ACCOUNTING POLICIES
 Application of Critical Accounting Policies and Estimates
 The Registrants prepare their financial statements in accordance with GAAP, which requires the use of estimates, judgments, and assumptions. Significant accounting policies are described in the notes to the financial statements. Detailed further herein are certain estimates made in the application of these policies that may have a material impact on the results of operations, financial condition, and related disclosures of the applicable Registrants (as indicated in the section descriptions herein). Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed these critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.

 Utility Regulation (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas)
 The traditional electric operating companies and the natural gas distribution utilities are subject to retail regulation by their respective state PSCs or other applicable state regulatory agencies and wholesale regulation by the FERC. These regulatory agencies set the rates the traditional electric operating companies and the natural gas distribution utilities are permitted to charge customers based on allowable costs, including a reasonable ROE. As a result, the traditional electric operating companies and the natural gas distribution utilities apply accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards for rate regulated entities also impacts their financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the traditional electric operating companies and the natural gas distribution utilities; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and other postretirement benefits have less of a direct impact on the results of operations and financial condition of the applicable Registrants than they would on a non-regulated company. Additionally, a regulatory agency may disallow recovery of all or a portion of certain assets. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects – Nicor Gas" for information regarding the disallowance of certain capital investments at Nicor Gas and "Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4" herein for information regarding the Prudency Stipulation related to Georgia Power's construction of Plant Vogtle Units 3 and 4.
 Revenues related to regulated utility operations as a percentage of total operating revenues in 2023 for the applicable Registrants were as follows: 89% for Southern Company, 98% for Alabama Power, 96% for Georgia Power, 99% for Mississippi Power, and 87% for Southern Company Gas.
 As reflected in Note 2 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact
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 the amounts of such regulatory assets and liabilities and could adversely impact the financial statements of the applicable Registrants.

 Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4
 (Southern Company and Georgia Power)
 In 2016, the Georgia PSC approved a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with Georgia Power's fifteenth VCM report. In January 2018, the Georgia PSC issued an order approving Georgia Power's seventeenth VCM report, which included a modification of the Vogtle Cost Settlement Agreement. The January 2018 order and the modified Vogtle Cost Settlement Agreement resolved certain regulatory matters related to Plant Vogtle Units 3 and 4 including, but not limited to: (i) Georgia Power's total project capital cost forecast of $7.3 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds) was found reasonable and (ii) a prudence proceeding on cost recovery would occur subsequent to achieving fuel load for Unit 4. On December 19, 2023, the Georgia PSC voted to approve Georgia Power's Application as modified by the Prudency Stipulation. Under the terms of the approved Prudency Stipulation, 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 approval of the Application and the Prudency Stipulation resolves all issues for determination by the Georgia PSC regarding the reasonableness, prudence, and cost recovery for the remaining Plant Vogtle Units 3 and 4 construction and capital costs not already in retail base rates.
 As of December 31, 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 $36 million and is based on the actual in-service date of July 2023 for Unit 3 and a projected in-service date during the second quarter 2024 for Unit 4. Since 2018, established construction contingency and additional costs totaling $2.7 billion have been assigned to the base capital cost forecast. Georgia Power did not seek rate recovery for 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 and, until the prudency proceeding described above, did not seek rate recovery for subsequent construction and additional contingency costs assigned to the base capital cost forecast. After considering the significant level of uncertainty that existed regarding the future recoverability of these costs since the ultimate outcome of these matters was subject to the outcome of assessments by management, as well as Georgia PSC decisions in the related regulatory proceedings, Georgia Power recorded total pre-tax charges to income of $1.1 billion ($0.8 billion after tax) in 2018; $149 million ($111 million after tax) and $176 million ($131 million after tax) in the second quarter and the fourth quarter 2020, respectively; $48 million ($36 million after tax), $460 million ($343 million after tax), $264 million ($197 million after tax), and $480 million ($358 million after tax) in the first quarter 2021, the second quarter 2021, the third quarter 2021, and the fourth quarter 2021, respectively; and $36 million ($27 million after tax), $32 million ($24 million after tax), and $148 million ($110 million after tax) in the second quarter 2022, the third quarter 2022, and the fourth quarter 2022, respectively. As a result of the Georgia PSC's approval of the Prudency Stipulation, Georgia Power recorded a pre-tax credit to income of approximately $228 million ($170 million after tax) in the fourth quarter 2023 to recognize CWIP costs previously charged to income, which are now recoverable through retail rates. Associated AFUDC on these costs was also recognized.
 In September 2022, Georgia Power and MEAG Power reached an agreement to resolve a dispute regarding the cost-sharing and tender provisions of the Global Amendments (as defined in Note 2 to the financial statements under "Georgia Power – Nuclear Construction – Joint Owner Contracts"). 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.
 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 cost-sharing and tender provisions of 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,
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 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 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.
 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 and engineering support.
 The projected schedule for Unit 4 significantly depends on the progression of start-up and pre-operational testing, which may be impacted by equipment or other operational failures. Any further delays could result in a later in-service date and cost increases.
 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 June 2024 for Unit 4, including the current level of cost sharing described in Note 2, is estimated to result in additional base capital costs for Georgia Power of up to $25 million per month as well as any additional related construction, support resources, or testing costs. Pursuant to the Prudency Stipulation, any further changes to the capital cost forecast will not be recoverable through regulated rates and will be required to be charged to income, and such charges could be material.
 Given the significant complexity involved in estimating the future costs to complete construction and start-up of Plant Vogtle Unit 4, as well as the potential impact on results of operations and cash flows, Southern Company and Georgia Power consider these items to be critical accounting estimates. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information.

 Accounting for Income Taxes (Southern Company, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas)
 The consolidated income tax provision and deferred income tax assets and liabilities, as well as any unrecognized tax benefits and valuation allowances, require significant judgment and estimates. These estimates are supported by historical tax return data, reasonable projections of taxable income, the ability and intent to implement tax planning strategies if necessary, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. The effective tax rate reflects the statutory tax rates and calculated apportionments for the various states in which the Southern Company system operates.
 Southern Company files a consolidated federal income tax return and the Registrants file various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and each subsidiary is allocated an amount of tax similar to that which would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability. Certain deductions and credits can be limited or utilized at the consolidated or combined level resulting in tax credit and/or state NOL carryforwards that would not otherwise result on a stand-alone basis. Utilization of these carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis of Southern Company's and its subsidiaries' current financial position and results of operations, including currently available information about future years, to estimate when future taxable income will be realized. See Note 10 to the financial statements under "Deferred Tax Assets and Liabilities – Tax Credit Carryforwards" and " – Net Operating Loss Carryforwards" for additional information.
 Current and deferred state income tax liabilities and assets are estimated based on laws of multiple states that determine the income to be apportioned to their jurisdictions. States have various filing methodologies and utilize specific formulas to calculate the apportionment of taxable income. The calculation of deferred state taxes considers apportionment factors and filing methodologies that are expected to apply in future years. Any apportionments and/or filing methodologies ultimately finalized in a manner inconsistent with expectations could have a material effect on the financial statements of the applicable Registrants.

 Asset Retirement Obligations (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas)
 Estimating AROs requires significant judgment. AROs are computed as the present value of the estimated costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The estimated costs are capitalized as part of the
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 related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
 The ARO liabilities for the traditional electric operating companies primarily relate to facilities that are subject to the CCR Rule and the related state rules, principally ash ponds. In addition, Alabama Power and Georgia Power have retirement obligations related to the decommissioning of nuclear facilities (Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 through 3). Other significant AROs include various landfill sites and asbestos removal for Alabama Power, Georgia Power, and Mississippi Power and gypsum cells and mine reclamation for Mississippi Power.
 The traditional electric operating companies and Southern Company Gas also have identified other retirement obligations, such as obligations related to certain electric transmission and distribution facilities, certain asbestos-containing material within long-term assets not subject to ongoing repair and maintenance activities, certain wireless communication towers, the disposal of polychlorinated biphenyls in certain transformers, leasehold improvements, equipment on customer property, and property associated with the Southern Company system's rail lines and natural gas pipelines. However, liabilities for the removal of these assets have not been recorded because the settlement timing for certain retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these retirement obligations will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
 The cost estimates for AROs related to the disposal of CCR are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule and the related 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 these assumptions becomes available. Some of these updates have been, and future updates may be, material. The cost estimates for Alabama Power are based on closure-in-place for all ash ponds. The cost estimates for Georgia Power and Mississippi Power are based on a combination of closure-in-place for some ash ponds and closure by removal for others. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. See Note 6 to the financial statements and FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein for additional information, including updates to AROs related to ash ponds recorded during 2023 by certain Registrants.

 Pension and Other Postretirement Benefits (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas)
 The applicable Registrants' calculations of pension and other postretirement benefits expense are dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term rate of return (LRR) on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the applicable Registrants believe the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect their pension and other postretirement benefit costs and obligations.
 Key elements in determining the applicable Registrants' pension and other postretirement benefit expense are the LRR and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. For purposes of determining the applicable Registrants' liabilities related to the pension and other postretirement benefit plans, Southern Company discounts the future related cash flows using a single-point discount rate for each plan developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. The discount rate assumption impacts both the service cost and non-service costs components of net periodic benefit costs as well as the projected benefit obligations.
 The LRR on pension and other postretirement benefit plan assets is based on Southern Company's investment strategy, as described in Note 11 to the financial statements, historical experience, and expectations that consider external actuarial advice, and represents the average rate of earnings expected over the long term on the assets invested to provide for anticipated future benefit payments. Southern Company determines the amount of the expected return on plan assets component of non-service costs by applying the LRR of various asset classes to Southern Company's target asset allocation. The LRR only impacts the non-service costs component of net periodic benefit costs for the following year and is set annually at the beginning of the year.
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 The following table illustrates the sensitivity to changes in the applicable Registrants' long-term assumptions with respect to the discount rate, salary increases, and the long-term rate of return on plan assets:

 Increase/(Decrease) in

 25 Basis Point Change in:
 Total Benefit Expense for 2024

 Projected Obligation for Pension Plan at December 31, 2023

 Projected Obligation for
 Other Postretirement
 Benefit Plans at December 31, 2023

 Discount rate:

 $35/$(32)
 $419/$(397)
 $34/$(32)

 $9/$(9)
 $101/$(96)
 $9/$(8)

 $9/$(9)
 $122/$(116)
 $11/$(11)

 $2/$(1)
 $18/$(18)
 $1/$(1)

 $2/$(2)
 $27/$(25)
 $4/$(4)

 Salaries:

 $18/$(17)
 $87/$(84)
 $–/$–

 $5/(5)
 $24/$(23)
 $–/$–

 $5/(5)
 $23/$(23)
 $–/$–

 $1/$(1)
 $4/$(4)
 $–/$–

 $1/$(1)
 $3/$(3)
 $–/$–

 Long-term return on plan assets:

 $41/$(41)
 N/A
 N/A

 $10/$(10)
 N/A
 N/A

 $13/$(13)
 N/A
 N/A

 $2/$(2)
 N/A
 N/A

 $3/$(3)
 N/A
 N/A

 See Note 11 to the financial statements for additional information regarding pension and other postretirement benefits.

 Impairment (Southern Company, Southern Power, and Southern Company Gas)
 Goodwill (Southern Company and Southern Company Gas)
 The acquisition method of accounting for business combinations requires the assets acquired and liabilities assumed to be recorded at the date of acquisition at their respective estimated fair values. The applicable Registrants have recognized goodwill as of the date of their acquisitions, as a residual over the fair values of the identifiable net assets acquired. Goodwill is recorded at the reporting unit level, which is the operating segment or a business one level below the operating segment (a component), if discrete financial information is prepared and regularly reviewed by management. Components are aggregated if they have similar economic characteristics. Goodwill is tested for impairment at the reporting unit level on an annual basis in the fourth quarter of the year and on an interim basis if events and circumstances occur that indicate goodwill may be impaired.
 Goodwill is evaluated for impairment either under the qualitative assessment option or the quantitative option to determine the fair value of the reporting unit. If goodwill is determined to be impaired, an impairment loss measured at the amount by which the reporting unit's carrying amount exceeds its fair value, not to exceed the carrying amount of goodwill, is recorded.
 Goodwill for Southern Company and Southern Company Gas was $5.2 billion and $5.0 billion, respectively, at December 31, 2023. During 2022, Southern Company recorded a $119 million impairment loss as a result of its annual goodwill impairment test for PowerSecure.
 The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can significantly impact the applicable Registrant's results of operations. Fair values and useful lives are determined based on, among other factors, the expected future period of benefit of the asset, the various characteristics of the asset, and projected cash flows. As the determination of an asset's fair value and useful life involves management making certain estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, the applicable Registrants consider these estimates to be critical accounting estimates.
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 See Note 1 to the financial statements under "Goodwill and Other Intangible Assets" for additional information regarding the applicable Registrants' goodwill.
 Long-Lived Assets (Southern Company, Southern Power, and Southern Company Gas)
 The applicable Registrants assess their other long-lived assets for impairment whenever events or changes in circumstances indicate that an asset's carrying amount may not be recoverable. If an impairment indicator exists, the asset is tested for recoverability by comparing the asset carrying amount to the sum of the undiscounted expected future cash flows directly attributable to the asset's use and eventual disposition. If the estimate of undiscounted future cash flows is less than the carrying amount of the asset, the fair value of the asset is determined and a loss is recorded equal to the difference between the carrying amount and the fair value of the asset. In addition, when assets are identified as held for sale, an impairment loss is recognized to the extent the carrying amount of the assets or asset group exceeds their fair value less cost to sell. A high degree of judgment is required in developing estimates related to these evaluations, which are based on projections of various factors, some of which have been quite volatile in recent years.
 Southern Power's investments in long-lived assets are primarily generation assets. Excluding the natural gas distribution utilities, Southern Company Gas' investments in long-lived assets are primarily natural gas transportation assets.
 For Southern Power, examples of impairment indicators could include, but are not limited to, significant changes in construction schedules, current period losses combined with a history of losses or a projection of continuing losses, a significant decrease in market prices, changes in tax legislation, the inability to remarket generating capacity for an extended period, the unplanned termination of a customer contract, or the inability of a customer to perform under the terms of the contract. For Southern Company Gas, examples of impairment indicators could include, but are not limited to, significant changes in the U.S. natural gas storage market, construction schedules, current period losses combined with a history of losses or a projection of continuing losses, a significant decrease in market prices, the inability to renew or extend customer contracts or the inability of a customer to perform under the terms of the contract, attrition rates, or the inability to deploy a development project.
 As the determination of the expected future cash flows generated from an asset, an asset's fair value, and useful life involves management making certain estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, the applicable Registrants consider these estimates to be critical accounting estimates.
 During 2021, Southern Company recorded impairment charges totaling $7 million ($6 million after tax) related to its leveraged lease investments. During 2022, Southern Company Gas recorded pre-tax impairment charges totaling $131 million ($99 million after tax) related to natural gas storage facilities. During 2021, Southern Company Gas recorded total pre-tax impairment charges of $84 million ($67 million after tax) related to its equity method investment in the PennEast Pipeline project. See Notes 7 and 9 to the financial statements under "Southern Company Gas" and "Southern Company Leveraged Lease," respectively, and Note 15 to the financial statements for additional information on recent asset impairments.

 Revenue Recognition (Southern Power)
 Southern Power's power sale transactions, which include PPAs, are classified in one of four general categories: leases, normal sale derivatives or contracts with customers, derivatives designated as cash flow hedges, and derivatives not designated as hedges. Southern Power's revenues are dependent upon significant judgments used to determine the appropriate transaction classification, which must be documented upon the inception of each contract. The two categories with the most judgment required for Southern Power are described further below.
 Lease Transactions
 Southern Power considers the terms of a sales contract to determine whether it should be accounted for as a lease. A contract is or contains a lease if the contract conveys the right to control the use of identified property, plant, or equipment for a period of time in exchange for consideration. If the contract meets the criteria for a lease, Southern Power performs further analysis to determine whether the lease is classified as operating, financing, or sales-type. Generally, Southern Power's power sales contracts that are determined to be leases are accounted for as operating leases and the capacity revenue is recognized on a straight-line basis over the term of the contract and is included in Southern Power's operating revenues. Energy revenues and other contingent revenues are recognized in the period the energy is delivered or the service is rendered. For those contracts that are determined to be sales-type leases, capacity revenues are recognized by accounting for interest income on the net investment in the lease and are included in Southern Power's operating revenues. See Note 9 to the financial statements for additional information.
 Normal Sale Derivative Transactions and Contracts with Customers
 If the power sales contract is not classified as a lease, Southern Power further considers whether the contract meets the definition of a derivative. If the contract does meet the definition of a derivative, Southern Power will assess whether it can be designated as
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 a normal sale contract. The determination of whether a contract can be designated as a normal sale contract requires judgment, including whether the sale of electricity involves physical delivery in quantities within Southern Power's available generating capacity and that the purchaser will take quantities expected to be used or sold in the normal course of business.
 Contracts that do not meet the definition of a derivative or are designated as normal sales are accounted for as revenue from contracts with customers. For contracts that have a capacity charge, the revenue is generally recognized in the period that it becomes billable. Revenues related to energy and ancillary services are recognized in the period the energy is delivered or the service is rendered. See Note 4 to the financial statements for additional information.

 Acquisition Accounting (Southern Power)
 Southern Power may acquire generation assets as part of its overall growth strategy. At the time of an acquisition, Southern Power will assess if these assets and activities meet the definition of a business. Acquisitions that meet the definition of a business are accounted for under the acquisition method, whereby the identifiable assets acquired, liabilities assumed, and any noncontrolling interests (including any intangible assets, primarily related to acquired PPAs) are recognized and measured at fair value. Assets acquired that do not meet the definition of a business are accounted for as an asset acquisition. The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired.
 Determining the fair value of assets acquired and liabilities assumed requires management judgment and Southern Power may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. For potential or successful acquisitions that meet the definition of a business, any due diligence or transaction costs incurred are expensed as incurred. If the acquisition is an asset acquisition, direct and incremental transaction costs can be capitalized as a component of the cost of the assets acquired.
 See Note 13 to the financial statements for additional fair value information and Note 15 to the financial statements for additional information on recent acquisitions.

 Variable Interest Entities (Southern Power)
 Southern Power enters into partnerships with varying ownership structures. Upon entering into these arrangements, membership interests and other variable interests are evaluated to determine if the legal entity is a VIE. If the legal entity is a VIE, Southern Power will assess if it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE, making it the primary beneficiary. Making this determination may require significant management judgment.
 If Southern Power is the primary beneficiary and is considered to have a controlling ownership, the assets, liabilities, and results of operations of the entity are consolidated. If Southern Power is not the primary beneficiary, the legal entity is generally accounted for under the equity method of accounting. Southern Power reconsiders its conclusions as to whether the legal entity is a VIE and whether it is the primary beneficiary for events that impact the rights of variable interests, such as ownership changes in membership interests.
 Southern Power has controlling ownership in certain legal entities for which the contractual provisions represent profit-sharing arrangements because the allocations of cash distributions and tax benefits are not based on fixed ownership percentages. For these arrangements, the noncontrolling interest is accounted for under a balance sheet approach utilizing the HLBV method. The HLBV method calculates each partner's share of income based on the change in net equity the partner can legally claim in a HLBV at the end of the period compared to the beginning of the period.

 Contingent Obligations (All Registrants)
 The Registrants are subject to a number of federal and state laws and regulations, as well as other factors and conditions that subject them to environmental, litigation, and other risks. See FUTURE EARNINGS POTENTIAL herein and Notes 2 and 3 to the financial statements for more information regarding certain of these contingencies. The Registrants periodically evaluate their exposure to such risks and record reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the results of operations, cash flows, or financial condition of the Registrants.

 Recently Issued Accounting Standards
 See Note 1 to the financial statements under "Recently Adopted Accounting Standards" for additional information.
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 FINANCIAL CONDITION AND LIQUIDITY
 Overview
 The financial condition of each Registrant remained stable at December 31, 2023. The Registrants' cash requirements primarily consist of funding ongoing operations, including unconsolidated subsidiaries, as well as common stock dividends, capital expenditures, and debt maturities. Southern Power's cash requirements also include distributions to noncontrolling interests. Capital expenditures and other investing activities for the traditional electric operating companies include investments to build new generation facilities to meet projected long-term demand requirements and to replace units being retired as part of the generation fleet transition, to maintain existing generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing generating units and closures of ash ponds, to expand and improve transmission and distribution facilities, and for restoration following major storms. Southern Power's capital expenditures and other investing activities may include acquisitions or new construction associated with its overall growth strategy and to maintain its existing generation fleet's performance. Southern Company Gas' capital expenditures and other investing activities include investments to meet projected long-term demand requirements, to maintain existing natural gas distribution systems as well as to update and expand these systems, and to comply with environmental regulations. See "Cash Requirements" herein for additional information.
 Operating cash flows provide a substantial portion of the Registrants' cash needs. During 2023, Southern Power utilized tax credits, which provided $332 million in operating cash flows. For the three-year period from 2024 through 2026, projected stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows for each of Southern Company, the traditional electric operating companies, and Southern Company Gas. Southern Company plans to finance future cash needs in excess of its operating cash flows through one or more of the following: accessing borrowings from financial institutions, issuing debt and hybrid securities in the capital markets, and/or through its stock plans. Each Subsidiary Registrant plans to finance its future cash needs in excess of its operating cash flows primarily through external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. In addition, Southern Power may utilize tax equity partnership contributions. The Registrants plan to use commercial paper to manage seasonal variations in operating cash flows and for other working capital needs and 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 "Sources of Capital" and "Financing Activities" herein for additional information.
 The Registrants' investments in their qualified pension plans and Alabama Power's and Georgia Power's investments in their nuclear decommissioning trust funds increased in value at December 31, 2023 as compared to December 31, 2022. No contributions to the qualified pension plan were made during 2023 and no mandatory contributions to the qualified pension plans are anticipated during 2024. See Notes 6 and 11 to the financial statements under "Nuclear Decommissioning" and "Pension Plans," respectively, for additional information.
 At the end of 2023, the market price of Southern Company's common stock was $70.12 per share (based on the closing price as reported on the NYSE) and the book value was $28.83 per share, representing a market-to-book value ratio of 243%, compared to $71.41, $27.93, and 256%, respectively, at the end of 2022.
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 Cash Requirements
 Capital Expenditures
 Total estimated capital expenditures, including LTSA and nuclear fuel commitments, for the Registrants through 2028 based on their current construction programs are as follows:

 2024
 2025
 2026
 2027
 2028

 Southern Company(a)(b)

 $
 10.0
 $
 9.4
 $
 8.5
 $
 8.6
 $
 8.7

 2.1
 2.0
 1.9
 2.0
 1.9

 Georgia Power(a)

 5.4
 5.0
 4.4
 4.5
 4.7

 0.3
 0.3
 0.2
 0.3
 0.3

 Southern Power(b)

 0.3
 0.2
 0.1
 0.1
 0.1

 1.8
 1.8
 1.7
 1.7
 1.7

 (a)Includes expenditures of approximately $0.2 billion in 2024 for the construction of Plant Vogtle Unit 4. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information. Also includes certain expenditures related to the construction of Plant Yates Units 8 through 10 as requested in Georgia Power's 2023 IRP Update filing, which is subject to the approval of the Georgia PSC. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" for additional information.
 (b)Includes $0.1 billion in both 2024 and 2025 related to the South Cheyenne and Millers Branch solar projects. Excludes approximately $0.8 billion annually for Southern Power's planned acquisitions and placeholder growth, which may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Also excludes estimated capital expenditures associated with the phase two expansion of the Millers Branch solar project, which was committed to subsequent to December 31, 2023. See Note 15 to the financial statements under "Southern Power" for additional information regarding the South Cheyenne and Millers Branch solar projects.
 These capital expenditures include estimates to comply with environmental laws and regulations, but do not include compliance costs associated with potential regulation of GHG emissions or the proposed ELG Supplemental Rule. See FUTURE EARNINGS POTENTIAL – "Environmental Matters" herein for additional information. At December 31, 2023, significant purchase commitments were outstanding in connection with the Registrants' construction programs.
 The traditional electric operating companies also anticipate continued expenditures associated with closure and monitoring of ash ponds and landfills in accordance with the CCR Rule and the related state rules, which are reflected in the applicable Registrants' ARO liabilities. The cost estimates for Alabama Power are based on closure-in-place for all ash ponds. The cost estimates for Georgia Power and Mississippi Power are based on a combination of closure-in-place for some ash ponds and closure by removal for others. These estimated costs are likely to change, and could change materially, as assumptions and details pertaining to closure are refined and compliance activities continue. Current estimates of these costs through 2028 are provided in the table below. Material expenditures in future years for ARO settlements will also be required for ash ponds, nuclear decommissioning (for Alabama Power and Georgia Power), and other liabilities reflected in the applicable Registrants' AROs, as discussed further in Note 6 to the financial statements. Also see FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein.

 2024
 2025
 2026
 2027
 2028

 $
 $
 $
 $
 $

 The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation and/or regulation; the cost, availability, and efficiency of construction labor, equipment, and materials; project scope and design changes; abnormal weather; delays in construction due to judicial or regulatory action; storm impacts; and the cost of capital. 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
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 acquisitions may vary due to market opportunities and the execution of its growth strategy. See Note 15 to the financial statements under "Southern Power" for additional information regarding Southern Power's plant acquisitions and construction projects.
 The construction program of Georgia Power includes Plant Vogtle Unit 4, which includes components based on new technology that only within the last several years began initial operation in the global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for information regarding Plant Vogtle Unit 4 and additional factors that may impact construction expenditures.
 See FUTURE EARNINGS POTENTIAL – "Construction Programs" herein for additional information.
 Other Significant Cash Requirements
 Long-term debt maturities and the interest payable on long-term debt each represent a significant cash requirement for the Registrants. See Note 8 to the financial statements for information regarding the Registrants' long-term debt at December 31, 2023, the weighted average interest rate applicable to each long-term debt category, and a schedule of long-term debt maturities over the next five years. The Registrants plan to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
 Fuel and purchased power costs represent a significant component of funding ongoing operations for the traditional electric operating companies and Southern Power. See Note 3 to the financial statements under "Commitments" for information on Southern Company Gas' commitments for pipeline charges, storage capacity, and gas supply. Total estimated costs for fuel and purchased power commitments at December 31, 2023 for the applicable Registrants are provided in the table below. Fuel costs include purchases of coal (for the traditional electric operating companies) and natural gas (for the traditional electric operating companies and Southern Power), as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery; the amounts reflected below have been estimated based on the NYMEX future prices at December 31, 2023. As discussed under "Capital Expenditures" herein, estimated expenditures for nuclear fuel are included in the applicable Registrants' construction programs for the years 2024 through 2028. Nuclear fuel commitments at December 31, 2023 that extend beyond 2028 are included in the table below. Purchased power costs represent estimated minimum obligations for various PPAs for the purchase of capacity and energy, except for those accounted for as leases, which are discussed in Note 9 to the financial statements.

 2024
 2025
 2026
 2027
 2028

 $
 3,347
 $
 3,151
 $
 2,201
 $
 1,738
 $
 1,171
 $
 4,820

 1,210
 1,181
 1,136

 Georgia Power(*)

 1,262
 1,111
 2,008

 1,002

 (*)Excludes capacity payments related to Plant Vogtle Units 1 and 2, which are discussed in Note 3 to the financial statements under "Commitments."
 In connection with Georgia Power's 2022 IRP, the Georgia PSC approved five affiliate PPAs with Southern Power, which are expected to be accounted for as leases, and are contingent upon approval by the FERC. The expected capacity payments associated with the PPAs total $5 million in 2024, $68 million in 2025, $75 million in 2026, $76 million in 2027, $86 million in 2028, and $584 million thereafter. In connection with Georgia Power's 2023 IRP Update, Georgia Power has requested certification of a non-affiliate PPA, which is expected to be accounted for as a lease and is contingent upon approval by the Georgia PSC. The expected capacity payments associated with the PPA are $10 million in 2024, $17 million in 2025, $18 million in 2026, $19 million in 2027, and $19 million in 2028. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" for additional information.
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 The traditional electric operating companies and Southern Power have entered into LTSAs for the purpose of securing maintenance support for certain of their generating facilities. See Note 1 to the financial statements under "Long-term Service Agreements" for additional information. As discussed under "Capital Expenditures" herein, estimated expenditures related to LTSAs are included in the applicable Registrants' construction programs for the years 2024 through 2028. Total estimated payments for LTSA commitments at December 31, 2023 that extend beyond 2028 are provided in the following table and include price escalation based on inflation indices:

Power

 LTSA commitments (after 2028)

 $
 1,594
 $
 $
 $
 $

 In addition, Southern Power has certain other operations and maintenance agreements. Total estimated costs for these commitments at December 31, 2023 are provided in the table below.

 2024
 2025
 2026
 2027
 2028

 Southern Power's operations and maintenance agreements
 $
 $
 $
 $
 $
 $

 See Note 9 to the financial statements for information on the Registrants' operating lease obligations, including a maturity analysis of the lease liabilities over the next five years and thereafter.

 Sources of Capital
 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 2024, 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" 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 2023, Southern Power obtained tax equity funding for existing tax equity partnerships totaling $21 million. See Notes 1 and 15 to the financial statements under "General" and "Southern Power," respectively, for additional information.

 The issuance of securities by the traditional electric operating companies and Nicor Gas is generally subject to the approval of the applicable state PSC or other applicable state regulatory agency. The issuance of all securities by Mississippi Power and short-term securities by Georgia Power is generally subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, Southern Company, the traditional electric operating companies, and Southern Power (excluding its subsidiaries), Southern Company Gas Capital, and Southern Company Gas (excluding its other subsidiaries) file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the securities registered under the 1933 Act, are closely monitored and appropriate filings are made to ensure flexibility in the capital markets.
 The Registrants generally obtain financing separately without credit support from any affiliate. See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of each company are not commingled with funds of any other company in the Southern Company system, except in the case of Southern Company Gas, as described below.
 The traditional electric operating companies and SEGCO may utilize a Southern Company subsidiary organized to issue and sell commercial paper at their request and for their benefit. Proceeds from such issuances for the benefit of an individual company are loaned directly to that company. The obligations of each traditional electric operating company and SEGCO under these
 II-58

 arrangements are several and there is no cross-affiliate credit support. Alabama Power also maintains its own separate commercial paper program.
 Southern Company Gas Capital obtains external financing for Southern Company Gas and its subsidiaries, other than Nicor Gas, which obtains financing separately without credit support from any affiliates. Southern Company Gas maintains commercial paper programs at Southern Company Gas Capital and Nicor Gas. Nicor Gas' commercial paper program supports its working capital needs as Nicor Gas is not permitted to make money pool loans to affiliates. All of the other Southern Company Gas subsidiaries benefit from Southern Company Gas Capital's commercial paper program.
 By regulation, Nicor Gas is restricted, up to 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 December 31, 2023, the amount of subsidiary retained earnings restricted to dividend totaled $1.7 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. See Note 8 to the financial statements for additional information. Also see "Financing Activities" herein for information on financing activities that occurred subsequent to December 31, 2023. The following table shows the amount by which current liabilities exceeded current assets at December 31, 2023 for the applicable Registrants:

Power

 Current liabilities in excess of current assets
 $
 3,035
 $
 1,674
 $
 $

 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 December 31, 2023, the Registrants' unused committed credit arrangements with banks were as follows:

parent
Power
 Power(a)

 Southern Company Gas(b)

 SEGCO

 Unused committed credit
 $
 1,998
 $
 1,350
 $
 1,726
 $
 $
 $
 1,598
 $
 $
 7,566

 (a)At December 31, 2023, Southern Power also had two continuing letters of credit facilities for standby letters of credit, of which $15 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 December 31, 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 December 31, 2023, Georgia Power had approximately $325 million 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 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 the End of the Period

 Amount
Outstanding

 December 31,
 December 31,

 2023
 2022
 2021
 2023
 2022
 2021

 $
 2,314
 $
 2,609
 $
 1,440
 5.7
 %
 4.9
 %
 0.4
 %

 —
 —
 5.5
 —
 —

 1,329
 1,600
 —
 5.9
 5.0
 —

 5.5
 4.7
 0.3

 Southern Company Gas Capital
 $
 $
 $
 5.5
 %
 4.8
 %
 0.3
 %

 5.5
 4.7
 0.4

 Southern Company Gas Total
 $
 $
 $
 1,209
 5.5
 %
 4.7
 %
 0.4
 %

 Short-term Debt During the Period(*)

 Average Amount Outstanding
 Maximum Amount Outstanding

 2023
 2022
 2021
 2023
 2022
 2021
 2023
 2022
 2021

 $
 2,191
 $
 1,995
 $
 1,141
 5.6
 %
 2.2
 %
 0.3
 %
 $
 3,270
 $
 2,894
 $
 1,809

 5.0
 2.1
 0.1

 1,440
 5.8
 3.1
 0.2
 2,260
 1,710

 5.5
 1.6
 0.2

 5.6
 2.3
 0.2

 Southern Company Gas Capital
 $
 $
 $
 5.3
 %
 1.8
 %
 0.2
 %
 $
 $
 $

 5.1
 2.1
 0.4

 Southern Company Gas Total
 $
 $
 $
 5.2
 %
 2.0
 %
 0.4
 %

 (*) Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2023, 2022, and 2021.
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 Analysis of Cash Flows
 Net cash flows provided from (used for) operating, investing, and financing activities in 2023 and 2022 are presented in the following table:

 Net cash provided from (used for):
Power

 2023

 Operating activities
 $
 7,553
 $
 2,079
 $
 2,752
 $
 $
 1,096
 $
 1,762

 Investing activities
 (9,668)
 (2,196)
 (5,079)
 (370)
 (265)
 (1,656)

 Financing activities
 (161)
 1,922
 (20)
 (820)
 (154)

 2022

 Operating activities
 $
 6,302
 $
 1,639
 $
 2,038
 $
 $
 $
 1,519

 Investing activities
 (8,430)
 (2,263)
 (3,954)
 (317)
 (194)
 (1,580)

 Financing activities
 2,336
 2,363
 (68)
 (623)

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

 Net cash provided from operating activities increased $1.3 billion in 2023 as compared to 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 in 2023 and 2022 was primarily related to the Subsidiary Registrants' construction programs.
 The net cash provided from financing activities in 2023 was primarily related to net issuances of long-term debt and an increase in commercial paper borrowings, partially offset by common stock dividend payments and net repayments of short-term bank loans. The net cash provided from financing activities in 2022 was primarily related to net issuances of long-term debt, the issuance of common stock to settle the purchase contracts entered into as part of the Equity Units (as discussed in Note 8 to the financial statements under "Equity Units"), and an increase in short-term borrowings, partially offset by common stock dividend payments.

 Net cash provided from operating activities increased $440 million in 2023 as compared to 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 in 2023 and 2022 was primarily related to gross property additions, including approximately $79 million and $211 million, respectively, related to the construction of Plant Barry Unit 8 and, for 2022, $171 million related to the acquisition of the Calhoun Generating Station. See Notes 2 and 15 to the financial statements under "Alabama Power" for additional information.
 The net cash used for financing activities in 2023 was primarily related to common stock dividend payments, largely offset by net issuances of long-term debt and capital contributions from Southern Company. The net cash provided from financing activities in 2022 was primarily related to net long-term debt issuances and capital contributions from Southern Company, partially offset by common stock dividend payments and preferred stock redemptions.

 Net cash provided from operating activities increased $714 million in 2023 as compared to 2022 primarily due to increased fuel cost recovery, partially offset by the timing of vendor payments.
 The net cash used for investing activities in 2023 and 2022 was primarily related to gross property additions, including approximately $1.1 billion and $1.0 billion, respectively, related to the construction of Plant Vogtle Units 3 and 4. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information on construction of Plant Vogtle Units 3 and 4.
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 The net cash provided from financing activities in 2023 was primarily related to capital contributions from Southern Company, net issuances of senior notes, an increase in commercial paper borrowings, 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. The net cash provided from financing activities in 2022 was primarily related to a net increase in short-term bank debt, capital contributions from Southern Company, and net issuances of senior notes, partially offset by common stock dividend payments.

 Net cash provided from operating activities decreased $14 million in 2023 as compared to 2022 primarily due to the timing of vendor payments, partially offset by a decrease in power pool sales and the timing of customer receivable collections.
 The net cash used for investing activities in 2023 and 2022 was primarily related to gross property additions.
 The net cash used for financing activities in 2023 was primarily related to common stock dividend payments, partially offset by the issuance of senior notes. The net cash used for financing activities in 2022 was primarily related to common stock dividend payments, partially offset by capital contributions from Southern Company and the issuance of revenue bonds.

 Net cash provided from operating activities increased $281 million in 2023 as compared to 2022 primarily due to an increase in the utilization of tax credits and the timing of customer receivable collections, partially offset by the timing of vendor payments.
 The net cash used for investing activities in 2023 was primarily related to the acquisitions of the South Cheyenne and Millers Branch solar facilities and ongoing construction activities. The net cash used for investing activities in 2022 was primarily related to ongoing construction activities. See Note 15 to the financial statements under "Southern Power" for additional information.
 The net cash used for financing activities in 2023 was primarily related to the repayment of senior notes at maturity, common stock dividend payments, net distributions to noncontrolling interests, and net repayments of short-term debt. The net cash used for financing activities in 2022 was primarily related to the repayment of senior notes at maturity, common stock dividend payments, and net capital distributions to noncontrolling interests, partially offset by capital contributions from Southern Company.

 Net cash provided from operating activities increased $243 million in 2023 as compared to 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 in 2023 and 2022 was primarily related to construction of transportation and distribution assets recovered through base rates and infrastructure investment recovered through replacement programs at gas distribution operations, partially offset by proceeds from dispositions. See Note 15 to the financial statements for additional information.
 The net cash used for financing activities in 2023 was primarily related to repayment of short-term borrowings and common stock dividend payments, partially offset by net issuances of long-term debt and capital contributions from Southern Company. The net cash provided from financing activities in 2022 was primarily related to net issuances of long-term debt and capital contributions from Southern Company, partially offset by common stock dividend payments and a decrease in short-term borrowings.

 Significant Balance Sheet Changes

 Significant balance sheet changes in 2023 for Southern Company included:
 • an increase of $5.3 billion in total property, plant, and equipment primarily related to the Subsidiary Registrants' construction programs;
 • an increase of $4.7 billion in long-term debt (including securities due within one year) related to new issuances;
 • a decrease of $1.2 billion in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Southern Company" herein;
 • an increase of $1.0 billion in total common stockholders' equity primarily related to net income, partially offset by common stock dividend payments;
 • an increase of $1.0 billion in accumulated deferred income taxes primarily related to an increase in property-related timing differences and the expected utilization of ITCs;
 • a decrease of $0.6 billion in accounts payable primarily related to the timing of vendor payments;
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 • a decrease of $0.6 billion in deferred credits related to income taxes primarily due to the flowback of excess deferred income taxes; and
 • a decrease of $0.5 billion in AROs primarily due to cost estimate updates at Georgia Power for ash pond closures.
 See "Financing Activities" herein and Notes 2, 5, 6, 8, and 10 to the financial statements for additional information.

 Significant balance sheet changes in 2023 for Alabama Power included:
 • an increase of $0.8 billion in total property, plant, and equipment primarily related to the construction of Plant Barry Unit 8 and construction of distribution and transmission facilities;
 • an increase of $0.6 billion in total 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 $0.6 billion in long-term debt (including securities due within one year) primarily due to the issuance of senior notes and revenue bonds;
 • a decrease of $0.4 billion in deferred credits related to income taxes primarily due to the flowback of excess deferred income taxes;
 • a decrease of $0.4 billion in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Alabama Power" herein; and
 • a decrease of $0.2 billion in other regulatory assets, deferred primarily due to a decrease in deferred under recovered fuel costs.
 See "Financing Activities – Alabama Power" herein and Notes 2, 5, and 8 to the financial statements for additional information.

 Significant balance sheet changes in 2023 for Georgia Power included:
 • an increase of $3.5 billion in total property, plant, and equipment primarily related to the construction of generation, transmission, and distribution facilities, including $1.2 billion for Plant Vogtle Units 3 and 4;
 • an increase of $2.5 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 $1.8 billion in long-term debt (including securities due within one year) primarily due to net issuances of senior notes;
 • decreases of $0.4 billion in AROs and $0.3 billion in regulatory assets associated with AROs primarily due to cost estimate updates for ash pond closures;
 • a decrease of $0.4 billion in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Georgia Power" herein;
 • an increase of $0.3 billion in accumulated deferred income taxes primarily due to an increase in property-related timing differences; and
 • a decrease of $0.3 billion in notes payable primarily due to net repayments of short-term bank debt, largely offset by an increase in commercial paper borrowings.
 See "Financing Activities – Georgia Power" herein and Notes 2, 5, 6, 8, and 10 to the financial statements for additional information.

 Significant balance sheet changes in 2023 for Mississippi Power included:
 • an increase of $161 million in total property, plant, and equipment primarily related to the construction of generation, 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;
 • an increase of $72 million in common stockholder's equity related to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company; and
 • a decrease of $53 million in affiliated receivables primarily due to a decrease in power pool sales.
 See "Financing Activities – Mississippi Power" herein and Notes 5 and 8 to the financial statements for additional information.
 II-63

 Significant balance sheet changes in 2023 for Southern Power included:
 • an increase of $335 million in accumulated deferred income taxes primarily related to the expected utilization of ITCs;
 • a decrease of $268 million in long-term debt (including securities due within one year) primarily due to the repayment of senior notes at maturity;
 • a decrease of $218 million in total stockholder's equity primarily due to dividends paid to Southern Company and net distributions to noncontrolling interests, partially offset by net income and capital contributions from Southern Company; and
 • a decrease of $189 million in total property, plant, and equipment in service primarily due to 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.
 See "Financing Activities – Southern Power" herein and Notes 5, 8, and 15 to the financial statements for additional information.

 Significant balance sheet changes in 2023 for Southern Company Gas included:
 • an increase of $1.1 billion in total property, plant, and equipment primarily related to the construction of transportation and distribution assets and additional infrastructure investment;
 • a decrease of $0.4 billion in total accounts receivable primarily relating to decreases of $0.2 billion in customer accounts receivable and $0.2 billion in unbilled revenues as a result of seasonality;
 • an increase of $0.4 billion in common stockholder's equity related to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company;
 • an increase of $0.4 billion in long-term debt (including securities due within one year) due to issuances of senior notes and first mortgage bonds;
 • a decrease of $0.4 billion in notes payable due to repayments of short-term debt and commercial paper borrowings;
 • a decrease of $0.3 billion in other accounts payable due to the timing of vendor payments; and
 • an increase of $0.2 billion in natural gas cost over recovery primarily due to lower natural gas prices and the timing of natural gas purchases.
 See "Financing Activities – Southern Company Gas" herein and Notes 2, 5, and 8 to the financial statements for additional information.

 Financing Activities
 The following table outlines the Registrants' long-term debt financing activities for the year ended December 31, 2023:

 Issuances and Reofferings

 Maturities and Redemptions

 Senior Notes
 Revenue
Bonds
 Other Long-Term Debt
 Senior
Notes
 Revenue Bonds
 Other Long-Term Debt(a)

 Southern Company parent
 $
 4,525
 $
 —
 $
 —
 $
 1,850
 $
 —
 $

 —

 2,450
 —
 —

 —
 —
 —
 —

 —
 —
 —
 —
 —

 —
 —

 Other
 —
 —
 —
 —
 —

 Elimination(b)

 —
 —
 —
 —
 —
 (9)

 $
 8,075
 $
 $
 $
 3,590
 $
 —
 $

 (a)Includes reductions in finance lease obligations resulting from cash payments under finance leases and, for Georgia Power, principal amortization payments totaling $86 million for FFB borrowings. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" for additional information.
 (b)Represents reductions in affiliate finance lease obligations at Georgia Power, which are eliminated in Southern Company's consolidated financial statements.
 II-64

 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.

 During 2023, Southern Company issued approximately 2.1 million shares of common stock primarily through equity compensation plans and received proceeds of approximately $36 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 8 to the financial statements under "Convertible Senior Notes" 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.
 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.

 During 2023, a subsidiary of Alabama Power borrowed $20 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, which it repaid in December 2023 using approximately $9 million of borrowings under a new $20 million fixed rate bank loan maturing December 2030.
 In November 2023, Alabama Power issued $300 million aggregate principal amount of Series 2023B 5.85% Senior Notes due November 15, 2033.
 In December 2023, Alabama Power repaid at maturity $300 million aggregate principal amount of its Series 2013A 3.55% Senior Notes.
 Subsequent to December 31, 2023, Alabama Power received a capital contribution of $425 million from Southern Company and also repaid at maturity approximately $21 million aggregate principal amount of Industrial Development Board of the Town of Wilsonville (Alabama) Pollution Control Revenue Bonds (Alabama Power Company Gaston Plant Project), Series D.
 II-65

 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.
 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.
 In November 2023, Georgia Power issued $700 million aggregate principal amount of Series 2023C Floating Rate Senior Notes due May 8, 2025.
 Also in November 2023, Georgia Power repaid $780 million of a $1.2 billion short-term floating rate bank loan entered into in November 2022 and extended the maturity of the remaining outstanding amount of $420 million to November 2024.
 In December 2023 and subsequent to December 31, 2023, Georgia Power borrowed $100 million and $150 million, respectively, pursuant to a short-term uncommitted bank credit arrangement bearing interest at a mutually agreed upon rate and payable on demand.

 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.

 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. In October 2023, Southern Power borrowed the remaining $50 million under the arrangement. In December 2023, Southern Power repaid the $100 million outstanding amount.
 In September 2023, Southern Power repaid at maturity $290 million aggregate principal amount of its Series 2016C 2.75% Senior Notes.
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 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.
 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. In October 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.
 In October 2023, Southern Company Gas Capital repaid at maturity $350 million aggregate principal amount of its 2.450% Senior Notes.
 In December 2023, Nicor Gas repaid at maturity $50 million aggregate principal amount of its 5.80% Series First Mortgage Bonds.
 During 2023, Southern Company Gas received cash advances totaling $37 million under a long-term financing agreement related to a construction contract.

 Credit Rating Risk
 At December 31, 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.
 The maximum potential collateral requirements under these contracts at December 31, 2023 were as follows:

 Credit Ratings

 Power(*)

 At BBB and/or Baa2
 $
 $
 $
 —
 $
 —
 $
 $
 —

 At BBB- and/or Baa3
 —

 At BB+ and/or Ba1 or below
 2,074
 1,289

 (*)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 December 31, 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.
 Mississippi Power and its largest retail customer, Chevron Products Company (Chevron), have agreements under which Mississippi Power provides retail service to the Chevron refinery in Pascagoula, Mississippi through at least 2038. The agreements grant Chevron a security interest in the co-generation assets owned by Mississippi Power located at the refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of Mississippi Power's credit rating to below investment grade by two of the three rating agencies.
 On August 2, 2023, S&P revised its credit rating outlook for Southern Company and its subsidiaries to positive from stable.
 On September 1, 2023, Fitch upgraded the senior unsecured long-term debt rating of Georgia Power to A- from BBB+ and revised the rating outlook to positive from stable.
 II-67

 Also on September 1, 2023, Fitch revised the ratings outlook of Southern Company, Alabama Power, Southern Power, Nicor Gas, and SEGCO to stable from negative.
 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.

 Market Price Risk
 The Registrants had no material change in market risk exposure for the year ended December 31, 2023 when compared to the year ended December 31, 2022. See Note 14 to the financial statements for an in-depth discussion of the Registrants' derivatives, as well as Note 1 to the financial statements under "Financial Instruments" for additional information.
 Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities that sell natural gas directly to end-use customers continue to have limited exposure to market volatility in interest rates, foreign currency exchange rates, commodity fuel prices, and prices of electricity. The traditional electric operating companies and certain of the natural gas distribution utilities manage fuel-hedging programs implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. Mississippi Power also manages wholesale fuel-hedging programs under agreements with its wholesale customers. Because energy from Southern Power's facilities is primarily sold under long-term PPAs with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the counterparties, Southern Power's exposure to market volatility in commodity fuel prices and prices of electricity is generally limited. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the traditional electric operating companies and Southern Power may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases; however, a significant portion of contracts are priced at market.
 Certain of Southern Company Gas' non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and OTC energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Southern Company Gas' gas marketing services business also actively manages storage positions through a variety of hedging transactions for the purpose of managing exposures arising from changing natural gas prices. These hedging instruments are used to substantially protect economic margins (as spreads between wholesale and retail natural gas prices widen between periods) and thereby minimize exposure to declining earnings. Some of these economic hedge activities may not qualify, or may not be designated, for hedge accounting treatment.
 The following table provides information related to variable interest rate exposure on long-term debt (including amounts due within one year) at December 31, 2023 for the applicable Registrants:

Power
Power
Power
Gas

 (in millions, except percentages)

 Long-term variable interest rate exposure

 $
 5,290
 $
 1,083
 $
 1,939
 $
 $

 Weighted average interest rate on long-term variable interest rate exposure
 5.87
 %
 4.75
 %
 5.48
 %
 5.39
 %
 5.85
 %

 Impact on annualized interest expense of 100 basis point change in interest rates
 $
 $
 $
 $
 $

 (*)Includes $1.4 billion of long-term variable interest rate exposure at the Southern Company parent entity.
 The Registrants may enter into interest rate derivatives designated as hedges, which are intended to mitigate interest rate volatility related to forecasted debt financings and existing fixed and floating rate obligations. See Note 14 to the financial statements under "Interest Rate Derivatives" for additional information.
 Southern Company and Southern Power had foreign currency denominated debt at December 31, 2023 and have each mitigated exposure to foreign currency exchange rate risk through the use of foreign currency swaps. See Note 14 to the financial statements under "Foreign Currency Derivatives" for additional information.
 II-68

 Changes in fair value of energy-related derivative contracts for Southern Company and Southern Company Gas for the years ended December 31, 2023 and 2022 are provided in the table below. At December 31, 2023 and 2022, substantially all of the traditional electric operating companies' and certain of the natural gas distribution utilities' energy-related derivative contracts were designated as regulatory hedges and were related to the applicable company's fuel-hedging program.

 Southern Company(a)

 Southern Company Gas(a)

 Contracts outstanding at December 31, 2021, assets (liabilities), net

 $
 $

 Contracts realized or settled
 (327)

 Current period changes(b)

 (55)

 Contracts outstanding at December 31, 2022, assets (liabilities), net

 $
 (11)
 $
 (37)

 Contracts realized or settled

 Current period changes(b)

 (500)
 (45)

 Contracts outstanding at December 31, 2023, assets (liabilities), net

 $
 (304)
 $
 (49)

 (a)Excludes cash collateral held on deposit in broker margin accounts of $62 million, $41 million, and $3 million at December 31, 2023, 2022, and 2021, respectively, and immaterial premium and intrinsic value associated with weather derivatives for all periods presented.
 (b)The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
 The net hedge volumes of energy-related derivative contracts for natural gas purchased (sold) at December 31, 2023 and 2022 for Southern Company and Southern Company Gas were as follows:

 mmBtu Volume (in millions)

 Commodity – Natural gas swaps
 —

 Commodity – Natural gas options

 Total hedge volume

 Commodity – Natural gas swaps
 —

 Commodity – Natural gas options

 Total hedge volume

 Southern Company Gas' derivative contracts are comprised of 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. The volumes presented above for Southern Company Gas represent the net of long natural gas positions of 112 million mmBtu and short natural gas positions of 10 million mmBtu at December 31, 2023 and the net of long natural gas positions of 98 million mmBtu and short natural gas positions of 5 million mmBtu at December 31, 2022.
 For the Southern Company system, the weighted average swap contract cost per mmBtu was approximately $0.76 per mmBtu below market prices at December 31, 2023 and was approximately $0.08 per mmBtu above market prices at December 31, 2022. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price. Substantially all of the traditional electric operating companies' natural gas hedge gains and losses are recovered through their respective fuel cost recovery clauses.
 II-69

 The Registrants use over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. In addition, Southern Company Gas uses exchange-traded market-observable contracts, which are categorized as Level 1. See Note 13 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts for Southern Company and Southern Company Gas at December 31, 2023 were as follows:

 Fair Value Measurements of Contracts at

 Total
Fair Value
 Maturity

 2024

 2025 – 2026

 2027 – 2028

 Level 1(a)

 $
 (40)
 $
 (36)
 $
 (4)
 $
 —
 $
 —

 Level 2(b)

 (264)
 (180)
 (87)

 Southern Company total(c)

 $
 (304)
 $
 (216)
 $
 (91)
 $
 $

 Level 1(a)

 $
 (40)
 $
 (36)
 $
 (4)
 $
 —
 $
 —

 Level 2(b)

 (9)
 (8)
 (1)
 —
 —

 Southern Company Gas total(c)

 $
 (49)
 $
 (44)
 $
 (5)
 $
 —
 $
 —

 (a)Valued using NYMEX futures prices.
 (b)Level 2 amounts for Southern Company Gas are valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers.
 (c)Excludes cash collateral of $62 million as well as immaterial premium and associated intrinsic value associated with weather derivatives.
 The Registrants are exposed to risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts, as applicable. 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. Therefore, the Registrants do not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments" and Note 14 to the financial statements.

 Credit Risk
 Southern Company (except as discussed herein), the traditional electric operating companies, and Southern Power are not exposed to any concentrations of credit risk. Southern Company Gas' exposure to concentrations of credit risk is discussed herein.
 Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of the 13 Marketers in Georgia. The credit risk exposure to the Marketers varies seasonally, with the lowest exposure in the non-peak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. The provisions of Atlanta Gas Light's tariff allow Atlanta Gas Light to obtain credit security support in an amount equal to a minimum of two times a Marketer's highest month's estimated bill from Atlanta Gas Light. For 2023, the four largest Marketers based on customer count, which includes SouthStar, accounted for 18% of Southern Company Gas' operating revenues and 20% of operating revenues for Southern Company Gas' gas distribution operations segment.
 Several factors are designed to mitigate Southern Company Gas' risks from the increased concentration of credit that has resulted from deregulation. In addition to the security support described above, Atlanta Gas Light bills intrastate delivery service to Marketers in advance rather than in arrears. Atlanta Gas Light accepts credit support in the form of cash deposits, letters of credit/surety bonds from acceptable issuers, and corporate guarantees from investment-grade entities. Southern Company Gas reviews the adequacy of credit support coverage, credit rating profiles of credit support providers, and payment status of each Marketer. Southern Company Gas believes that adequate policies and procedures are in place to properly quantify, manage, and report on Atlanta Gas Light's credit risk exposure to Marketers.
 II-70

 Atlanta Gas Light also faces potential credit risk in connection with assignments of interstate pipeline transportation and storage capacity to Marketers. Although Atlanta Gas Light assigns this capacity to Marketers, in the event that a Marketer fails to pay the interstate pipelines for the capacity, the interstate pipelines would likely seek repayment from Atlanta Gas Light.
 Gas Marketing Services
 Southern Company Gas obtains credit scores for its firm residential and small commercial customers using a national credit reporting agency, enrolling only those customers that meet or exceed Southern Company Gas' credit threshold. Southern Company Gas considers potential interruptible and large commercial customers based on reviews of publicly available financial statements and commercially available credit reports. Prior to entering into a physical transaction, Southern Company Gas also assigns physical wholesale counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements.
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 Item 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 Page

 The Southern Company and Subsidiary Companies:

 II- 73

 Consolidated Statements of Income for the Years Ended December 31, 2023, 2022, and 2021

 II- 75

 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2023, 2022, and 2021

 II- 76

 Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022, and 2021

 II- 77

 Consolidated Balance Sheets at December 31, 2023 and 2022

 II- 78

 Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2023, 2022, and 2021

 II- 80

 Alabama Power:

 II- 81

 Statements of Income for the Years Ended December 31, 2023, 2022, and 2021

 II- 83

 Statements of Comprehensive Income for the Years Ended December 31, 2023, 2022, and 2021

 II- 83

 Statements of Cash Flows for the Years Ended December 31, 2023, 2022, and 2021

 II- 84

 Balance Sheets at December 31, 2023 and 2022

 II- 85

 Statements of Common Stockholder's Equity for the Years Ended December 31, 2023, 2022, and 2021

 II- 87

 Georgia Power:

 II- 88

 Statements of Income for the Years Ended December 31, 2023, 2022, and 2021

 II- 90

 Statements of Comprehensive Income for the Years Ended December 31, 2023, 2022, and 2021

 II- 90

 Statements of Cash Flows for the Years Ended December 31, 2023, 2022, and 2021

 II- 91

 Balance Sheets at December 31, 2023 and 2022

 II- 92

 Statements of Common Stockholder's Equity for the Years Ended December 31, 2023, 2022, and 2021

 II- 94

 Mississippi Power:

 II- 95

 Statements of Income for the Years Ended December 31, 2023, 2022, and 2021

 II- 97

 Statements of Comprehensive Income for the Years Ended December 31, 2023, 2022, and 2021

 II- 97

 Statements of Cash Flows for the Years Ended December 31, 2023, 2022, and 2021

 II- 98

 Balance Sheets at December 31, 2023 and 2022

 II- 99

 Statements of Common Stockholder's Equity for the Years Ended December 31, 2023, 2022, and 2021

 II- 101

 Southern Power and Subsidiary Companies:

 II- 102

 Consolidated Statements of Income for the Years Ended December 31, 2023, 2022, and 2021

 II- 104

 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2023, 2022, and 2021

 II- 105

 Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022, and 2021

 II- 106

 Consolidated Balance Sheets at December 31, 2023 and 2022

 II- 107

 Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2023, 2022, and 2021

 II- 109

 Southern Company Gas and Subsidiary Companies:

 II- 110

 Consolidated Statements of Income for the Years Ended December 31, 2023, 2022, and 2021

 II- 114

 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2023, 2022, and 2021

 II- 114

 Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022, and 2021

 II- 115

 Consolidated Balance Sheets at December 31, 2023 and 2022

 II- 116

 Consolidated Statements of Common Stockholder's Equity for the Years Ended December 31, 2023, 2022, and 2021

 II- 118

 Combined Notes to Financial Statements

 II- 119

 II-72

 To the stockholders and the Board of Directors of The Southern Company and Subsidiary Companies
 Opinions on the Financial Statements and Internal Control over Financial Reporting
 We have audited the accompanying consolidated balance sheets of The Southern Company and Subsidiary Companies (Southern Company) as of December 31, 2023 and 2022, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2023, the related notes, and the financial statement schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). We also have audited Southern Company's internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
 In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southern Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, Southern Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.
 Basis for Opinions
 Southern Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on Southern Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Southern Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
 Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
 Definition and Limitations of Internal Control over Financial Reporting
 A company's internal control over financial reporting is a process designed 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. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
 Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the Audit Committee of Southern Company's Board of Directors and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective,
 II-73

 or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
 Impact of Rate Regulation on the Financial Statements – Refer to Note 1 (Summary of Significant Accounting Policies – Regulatory Assets and Liabilities) and Note 2 (Regulatory Matters) to the financial statements
 Southern Company's traditional electric operating companies and natural gas distribution utilities (the "regulated utility subsidiaries") are subject to rate regulation by their respective state Public Service Commissions or other applicable state regulatory agencies and wholesale regulation by the Federal Energy Regulatory Commission (collectively, the "Commissions"). Management has determined that the regulated utility subsidiaries meet the requirements under accounting principles generally accepted in the United States of America to utilize specialized rules to account for the effects of rate regulation in the preparation of its financial statements. Accounting for the economics of rate regulation may impact multiple financial statement line items and disclosures.
 The Commissions set the rates the regulated utility subsidiaries are permitted to charge customers. Rates are determined and approved in regulatory proceedings based on an analysis of the applicable regulated utility subsidiary's costs to provide utility service and a return on, and recovery of, its investment in the utility business. Current and future regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investments, and the timing and amount of assets to be recovered through rates. The Commissions' regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. While Southern Company's regulated utility subsidiaries expect to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on those investments.
 We identified the impact of rate regulation related to certain assets and liabilities as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and/or the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on incurred costs. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and/or (3) a refund to customers. Auditing these judgments, which include assumptions about the outcome of future decisions by the Commissions, required specialized knowledge of accounting for rate regulations and the rate setting process due to its inherent complexities.
 Our audit procedures related to the impact of rate regulation on certain assets and liabilities included the following, among others:
 • We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of certain incurred costs and (2) refunds or future reductions in rates that should be reported as regulatory liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering certain costs in future rates or of a future reduction in rates. We also tested the effectiveness of management's controls over the initial recognition of regulatory assets or liabilities.
 • We read and evaluated relevant regulatory orders and/or other relevant publicly available information to assess the likelihood of recovery of certain incurred costs in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances.
 • We tested certain incurred costs recorded as regulatory assets or liabilities during the period for completeness and accuracy.
 • We obtained representation from management regarding the likelihood of recoverability of incurred costs and potential refund or future reduction in rates to assess management's assertions about the likelihood of recovery, refund, or a future reduction in rates.
 • We evaluated Southern Company's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments, including where there is a high degree of subjectivity involved in assessing the potential impact of future regulatory orders on incurred costs.
 We have served as Southern Company's auditor since 2002.
 II-74

 CONSOLIDATED STATEMENTS OF INCOME

 2023
 2022
 2021

 Retail electric revenues
 $
 16,343
 $
 18,197
 $
 14,852

 2,467
 3,641
 2,455

 Other electric revenues

 Natural gas revenues
 4,702
 5,962
 4,380

 25,253
 29,279
 23,113

 Fuel
 4,365
 6,835
 4,010

 1,593

 1,644
 3,004
 1,619

 Cost of other sales

 6,093
 6,573
 5,902

 4,525
 3,663
 3,565

 1,425
 1,411
 1,290

 ( 68)
 1,692

 —

 19,427
 23,909
 19,415

 5,826
 5,370
 3,698

 ( 2,446)
 ( 2,022)
 ( 1,837)

 ( 1,481)
 ( 1,147)
 ( 1,122)

 4,345
 4,223
 2,576

 Consolidated Net Income
 3,849
 3,428
 2,309

 Dividends on preferred stock of subsidiaries
 —

 Net loss attributable to noncontrolling interests
 ( 99)

 Consolidated Net Income Attributable to Southern Company
 $
 3,976
 $
 3,524
 $
 2,393

 Common Stock Data:

 Earnings per share —

 Basic
 $
 3.64
 $
 3.28
 $
 2.26

 Diluted
 3.62
 3.26
 2.24

 Average number of shares of common stock outstanding — (in millions)

 Basic
 1,092
 1,075
 1,061

 Diluted
 1,098
 1,081
 1,068

 The accompanying notes are an integral part of these consolidated financial statements.

 II-75

 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 2023
 2022
 2021

 Consolidated Net Income
 $
 3,849
 $
 3,428
 $
 2,309

 Other comprehensive income (loss):

 Changes in fair value, net of tax of
 $( 17), $( 19), and $( 16), respectively

 ( 41)
 ( 60)
 ( 49)

 net of tax of $ 27, $ 23, and $ 31, respectively

 Pension and other postretirement benefit plans:

 Benefit plan net gain (loss),
 net of tax of $( 14), $ 18, and $ 37, respectively

 ( 39)

 net of tax of $ —, $ 3, and $ 5, respectively

 Total other comprehensive income (loss)
 ( 10)

 Dividends on preferred stock of subsidiaries
 —

 Comprehensive loss attributable to noncontrolling interests
 ( 99)

 Consolidated Comprehensive Income Attributable to Southern Company
 $
 3,966
 $
 3,595
 $
 2,551

 The accompanying notes are an integral part of these consolidated financial statements.

 II-76

 CONSOLIDATED STATEMENTS OF CASH FLOWS

 2023
 2022
 2021

 Consolidated net income
 $
 3,849
 $
 3,428
 $
 2,309

 Adjustments to reconcile consolidated net income

 4,986
 4,064
 3,973

 ( 49)

 Utilization of federal investment tax credits

 ( 268)
 ( 224)
 ( 190)

 Pension, postretirement, and other employee benefits
 ( 527)
 ( 436)
 ( 305)

 Settlement of asset retirement obligations
 ( 617)
 ( 455)
 ( 456)

 Storm damage and reliability reserve accruals

 Stock based compensation expense

 ( 68)
 1,692

 —

 Retail fuel cost under recovery – long-term
 ( 206)
 ( 2,166)
 ( 536)

 Natural gas cost under recovery – long-term
 —
 ( 207)

 ( 138)
 ( 25)
 ( 89)

 ( 771)
 ( 77)

 -Retail fuel cost under recovery
 ( 100)
 ( 4)

 -Fossil fuel for generation
 ( 368)
 ( 125)

 -Materials and supplies
 ( 345)
 ( 160)
 ( 130)

 -Natural gas cost under recovery
 ( 266)

 ( 186)
 ( 270)

 ( 863)
 1,021
 ( 8)

 -Customer refunds

 -Natural gas cost over recovery
 —
 —

 ( 258)

 7,553
 6,302
 6,169

 ( 9,095)
 ( 7,923)
 ( 7,586)

 Nuclear decommissioning trust fund purchases
 ( 1,142)
 ( 1,125)
 ( 1,598)

 Nuclear decommissioning trust fund sales
 1,121
 1,112
 1,593

 Proceeds from dispositions

 Cost of removal, net of salvage
 ( 592)
 ( 649)
 ( 442)

 Change in construction payables, net
 ( 124)

 Payments pursuant to LTSAs
 ( 99)
 ( 190)
 ( 188)

 ( 43)
 ( 133)

 ( 9,668)
 ( 8,430)
 ( 7,353)

 ( 337)

 Long-term debt
 8,972
 5,132
 8,262

 2,650

 Common stock
 1,808

 Redemptions and repurchases —

 Long-term debt
 ( 4,294)
 ( 2,158)
 ( 4,327)

 ( 1,630)
 ( 1,150)
 ( 25)

 Preferred stock
 —
 ( 298)
 —

 Capital contributions from noncontrolling interests

 Distributions to noncontrolling interests
 ( 234)

 ( 3,035)
 ( 2,907)
 ( 2,777)

 ( 160)
 ( 218)
 ( 266)

 Net cash provided from financing activities
 2,336
 1,945

 ( 1,116)

 2,037
 1,829
 1,068

 $
 $
 2,037
 $
 1,829

 Interest (net of $ 132, $ 103, and $ 92 capitalized, respectively)

 $
 2,184
 $
 1,758
 $
 1,718

 Noncash transactions —

 Accrued property additions at year-end
 1,027
 1,024

 LTSA credits utilized from the sale of spare parts
 —
 —

 Contributions from noncontrolling interests
 —

 Contributions of wind turbine equipment
 —
 —

 The accompanying notes are an integral part of these consolidated financial statements.
 II-77

 2023
 2022

 $
 $
 1,917

 Customer accounts
 2,030
 2,128

 1,012

 Under recovered fuel clause revenues

 Accumulated provision for uncollectible accounts
 ( 68)
 ( 71)

 1,989
 1,664

 Fossil fuel for generation

 Natural gas for sale

 Prepaid expenses

 Assets from risk management activities, net of collateral

 Regulatory assets – asset retirement obligations

 Natural gas cost under recovery
 —

 1,120

 10,432
 10,416

 128,428
 117,529

 Less: Accumulated depreciation
 37,725
 35,297

 90,703
 82,232

 Other utility plant, net

 Nuclear fuel, at amortized cost

 7,784
 10,896

 99,844
 94,570

 5,161
 5,161

 Nuclear decommissioning trusts, at fair value
 2,424
 2,145

 1,368
 1,443

 Other intangible assets, net of amortization of $ 376 and $ 340, respectively

 Miscellaneous property and investments

 9,986
 9,757

 1,432
 1,531

 Deferred charges related to income taxes

 Prepaid pension costs
 2,079
 2,290

 Unamortized loss on reacquired debt

 Deferred under recovered retail fuel clause revenues

 1,261
 2,056

 Regulatory assets – asset retirement obligations, deferred
 5,459
 5,764

 6,264
 5,918

 1,468
 1,485

 19,069
 20,148

 $
 139,331
 $
 134,891

 The accompanying notes are an integral part of these consolidated financial statements.
 II-78

 Liabilities and Stockholders' Equity
 2023
 2022

 $
 2,476
 $
 4,285

 2,314
 2,609

 Accounts payable
 2,898
 3,525

 Customer deposits

 Accrued taxes —

 Accrued income taxes

 Other accrued taxes

 Accrued interest

 1,151
 1,127

 Asset retirement obligations

 Liabilities from risk management activities, net of collateral

 Natural gas cost over recovery
 —

 1,029

 13,467
 15,724

 57,210
 50,656

 10,990
 10,036

 4,674
 5,235

 Accumulated deferred ITCs
 2,067
 2,133

 1,115
 1,238

 Operating lease obligations, deferred
 1,307
 1,388

 Asset retirement obligations, deferred
 9,573
 10,146

 Other cost of removal obligations
 1,957
 1,903

 1,031
 1,167

 33,429
 33,979

 104,106
 100,359

 Common Stockholders' Equity:

 Common stock, par value $ 5 per share (Authorized - 1.5 billion shares)

 5,423
 5,417

 (Issued - 1.1 billion shares; Treasury - 1.0 million shares)

 13,775
 13,673

 Treasury, at cost
 ( 59)
 ( 53)

 Retained earnings
 12,482
 11,538

 Accumulated other comprehensive loss
 ( 177)
 ( 167)

 Total common stockholders' equity
 31,444
 30,408

 Noncontrolling interests
 3,781
 4,124

 Total Stockholders' Equity (See accompanying statements)

 35,225
 34,532

 Total Liabilities and Stockholders' Equity
 $
 139,331
 $
 134,891

 The accompanying notes are an integral part of these consolidated financial statements.
 II-79

 CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

 Southern Company Common Stockholders' Equity

 Number of Common Shares
 Accumulated
Other
(Loss)
 Noncontrolling
Interests

 Issued
 Treasury
 Par Value
 Treasury
 Retained Earnings
 Total

 1,058
 ( 1)
 $
 5,268
 $
 11,834
 $
 ( 46)
 $
 11,311
 $
 ( 395)
 $
 4,262
 $
 32,234

 Consolidated net income (loss)
 —
 —
 —
 —
 —
 2,393
 —
 ( 99)
 2,294

 —
 —
 —
 —
 —
 —
 —

 Stock issued
 —
 —
 —
 —
 —

 Stock-based compensation
 —
 —
 —
 —
 —
 —
 —

 Cash dividends of $ 2.6200 per share

 —
 —
 —
 —
 —
 ( 2,777)
 —
 —
 ( 2,777)

 —
 —
 —
 —
 —
 —
 —

 Distributions to
 —
 —
 —
 —
 —
 —
 —

 Other
 —
 —
 —
 ( 8)
 ( 1)
 —
 —
 ( 7)

 1,061
 ( 1)
 5,279
 11,950
 ( 47)
 10,929
 ( 237)
 4,402
 32,276

 Consolidated net income (loss)
 —
 —
 —
 —
 —
 3,524
 —
 3,417

 —
 —
 —
 —
 —
 —
 —

 Stock issued
 —
 1,670
 —
 —
 —
 —
 1,808

 Stock-based compensation
 —
 —
 —
 —
 —
 —
 —

 Cash dividends of $ 2.7000 per share

 —
 —
 —
 —
 —
 ( 2,907)
 —
 —
 ( 2,907)

 —
 —
 —
 —
 —
 —
 —

 Distributions to
 —
 —
 —
 —
 —
 —
 —

 Other
 —
 —
 —
 ( 6)
 ( 8)
 ( 1)
 —
 ( 6)

 1,090
 ( 1)
 5,417
 13,673
 ( 53)
 11,538
 ( 167)
 4,124
 34,532

 Consolidated net income (loss)
 —
 —
 —
 —
 —
 3,976
 —
 3,849

 Other comprehensive income (loss)
 —
 —
 —
 —
 —
 —
 ( 10)
 —
 ( 10)

 Stock issued
 —
 —
 —
 —
 —

 Stock-based compensation
 —
 —
 —
 —
 —
 —
 —

 Cash dividends of $ 2.7800 per share

 —
 —
 —
 —
 —
 ( 3,035)
 —
 —
 ( 3,035)

 —
 —
 —
 —
 —
 —
 —

 Distributions to
 —
 —
 —
 —
 —
 —
 —
 ( 236)
 ( 236)

 Other
 —
 —
 —
 ( 1)
 ( 6)
 —
 ( 1)
 ( 5)

 1,092
 ( 1)
 $
 5,423
 $
 13,775
 $
 ( 59)
 $
 12,482
 $
 ( 177)
 $
 3,781
 $
 35,225

 The accompanying notes are an integral part of these consolidated financial statements.
 II-80

 To the stockholders and the Board of Directors of Alabama Power Company
 We have audited the accompanying balance sheets of Alabama Power Company (Alabama Power) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2023 and 2022, the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2023, the related notes, and the financial statement schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Alabama Power as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
 These financial statements are the responsibility of Alabama Power's management. Our responsibility is to express an opinion on Alabama Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Alabama Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Alabama Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Alabama Power's internal control over financial reporting. Accordingly, we express no such opinion.
 Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
 The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the Audit Committee of Southern Company's Board of Directors and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
 Impact of Rate Regulation on the Financial Statements – Refer to Note 1 (Summary of Significant Accounting Policies – Regulatory Assets and Liabilities) and Note 2 (Regulatory Matters – Alabama Power) to the financial statements
 Alabama Power is subject to retail rate regulation by the Alabama Public Service Commission and wholesale regulation by the Federal Energy Regulatory Commission (collectively, the "Commissions"). Management has determined that it meets the requirements under accounting principles generally accepted in the United States of America to utilize specialized rules to account for the effects of rate regulation in the preparation of its financial statements. Accounting for the economics of rate regulation may impact multiple financial statement line items and disclosures.
 The Commissions set the rates Alabama Power is permitted to charge customers. Rates are determined and approved in regulatory proceedings based on an analysis of Alabama Power's costs to provide utility service and a return on, and recovery of, its investment in the utility business. Current and future regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investments, and the timing and amount of assets to be recovered through rates. The Commissions' regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. While Alabama Power expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on those investments.
 II-81

 We identified the impact of rate regulation related to certain assets and liabilities as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and/or the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on incurred costs. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and/or (3) a refund to customers. Auditing these judgments, which include assumptions about the outcome of future decisions by the Commissions, required specialized knowledge of accounting for rate regulations and the rate setting process due to its inherent complexities.
 Our audit procedures related to the impact of rate regulation on certain assets and liabilities included the following, among others:
 • We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of certain incurred costs and (2) refunds or future reductions in rates that should be reported as regulatory liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering certain costs in future rates or of a future reduction in rates. We also tested the effectiveness of management's controls over the initial recognition of regulatory assets or liabilities.
 • We read and evaluated relevant regulatory orders and/or other relevant publicly available information to assess the likelihood of recovery of certain incurred costs in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances.
 • We tested certain incurred costs recorded as regulatory assets or liabilities during the period for completeness and accuracy.
 • We obtained representation from management regarding the likelihood of recoverability of incurred costs and potential refund or future reduction in rates to assess management's assertions about the likelihood of recovery, refund, or a future reduction in rates.
 • We evaluated Alabama Power's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments, including where there is a high degree of subjectivity involved in assessing the potential impact of future regulatory orders on incurred costs.
 Birmingham, Alabama
 We have served as Alabama Power's auditor since 2002.
 II-82

 STATEMENTS OF INCOME

 2023
 2022
 2021

 Retail revenues
 $
 6,159
 $
 6,470
 $
 5,499

 Wholesale revenues, non-affiliates

 Wholesale revenues, affiliates

 7,050
 7,817
 6,413

 Fuel
 1,299
 1,840
 1,235

 Purchased power, non-affiliates

 Purchased power, affiliates

 1,769
 1,935
 1,735

 1,401

 5,415
 5,875
 4,607

 1,635
 1,942
 1,806

 ( 425)
 ( 382)
 ( 340)

 ( 184)
 ( 168)
 ( 181)

 1,451
 1,774
 1,625

 1,370
 1,351
 1,253

 Dividends on Preferred Stock
 —

 Net Income After Dividends on Preferred Stock
 $
 1,370
 $
 1,340
 $
 1,238

 STATEMENTS OF COMPREHENSIVE INCOME

 2023
 2022
 2021

 $
 1,370
 $
 1,351
 $
 1,253

 Other comprehensive income:

 Changes in fair value, net of tax of $ —, $ —, and $ 1, respectively

 —
 ( 1)

 net of tax of $ 1, $ 2, and $ 2, respectively

 Total other comprehensive income

 $
 1,372
 $
 1,355
 $
 1,259

 II-83

 STATEMENTS OF CASH FLOWS

 2023
 2022
 2021

 $
 1,370
 $
 1,351
 $
 1,253

 Adjustments to reconcile net income

 1,554
 1,014
 1,005

 ( 242)

 ( 82)
 ( 70)
 ( 52)

 Pension, postretirement, and other employee benefits
 ( 118)

 Settlement of asset retirement obligations
 ( 270)
 ( 205)
 ( 202)

 Natural disaster reserve and reliability reserve accruals

 Retail fuel cost under recovery – long-term
 —
 ( 520)
 ( 126)

 ( 50)
 ( 53)

 ( 24)
 ( 321)

 -Fossil fuel stock
 ( 70)

 -Materials and supplies
 ( 105)
 ( 7)
 ( 6)

 -Retail fuel cost under recovery
 ( 102)
 —

 ( 20)
 ( 23)
 ( 31)

 ( 162)
 ( 109)

 -Customer refunds
 ( 39)

 ( 34)
 ( 86)

 2,079
 1,639
 2,053

 ( 2,022)
 ( 2,016)
 ( 1,753)

 Nuclear decommissioning trust fund purchases
 ( 301)
 ( 355)
 ( 638)

 Nuclear decommissioning trust fund sales

 Cost of removal net of salvage
 ( 178)
 ( 234)

 Change in construction payables
 ( 44)
 ( 16)

 ( 62)
 ( 26)

 ( 2,196)
 ( 2,263)
 ( 1,961)

 Increase in notes payable, net
 —
 —

 1,700
 1,300

 —
 —

 —
 —

 Redemptions and repurchases —

 ( 300)
 ( 750)
 ( 200)

 Preferred stock
 —
 ( 298)
 —

 —
 —
 ( 65)

 —
 —
 ( 206)

 ( 1,141)
 ( 1,016)
 ( 984)

 ( 22)
 ( 34)
 ( 43)

 Net cash provided from (used for) financing activities
 ( 161)

 ( 278)
 ( 373)

 1,060

 $
 $
 $
 1,060

 Interest (net of $ 27, $ 20, and $ 15 capitalized, respectively)

 $
 $
 $

 Noncash transactions — Accrued property additions at year-end

 II-84

 2023
 2022

 $
 $

 Customer accounts

 Accumulated provision for uncollectible accounts
 ( 16)
 ( 14)

 Fossil fuel stock

 Prepaid expenses

 Regulatory assets – under recovered retail fuel clause revenues

 3,077
 2,924

 35,429
 33,472

 Less: Accumulated provision for depreciation
 11,131
 10,470

 24,298
 23,002

 Other utility plant, net

 Nuclear fuel, at amortized cost

 1,095
 1,526

 26,145
 25,366

 Nuclear decommissioning trusts, at fair value
 1,261
 1,127

 Miscellaneous property and investments

 1,468
 1,308

 Deferred charges related to income taxes

 Prepaid pension and other postretirement benefit costs

 Regulatory assets – asset retirement obligations
 1,810
 1,845

 1,858
 2,107

 5,090
 5,372

 $
 35,780
 $
 34,970

 II-85

 Liabilities and Stockholder's Equity
 2023
 2022

 $
 $

 —

 Other

 Customer deposits

 Accrued interest

 Asset retirement obligations

 2,304
 2,414

 10,960
 10,329

 4,170
 3,981

 1,506
 1,925

 Accumulated deferred ITCs

 Asset retirement obligations, deferred
 3,812
 3,957

 10,183
 10,540

 23,447
 23,283

 Common stock, par value $ 40 per share
 (Authorized - 40 million shares; Outstanding - 31 million shares)

 1,222
 1,222

 7,125
 6,710

 Retained earnings
 3,993
 3,764

 Accumulated other comprehensive loss
 ( 7)
 ( 9)

 Total common stockholder's equity (See accompanying statements)

 12,333
 11,687

 Total Liabilities and Stockholder's Equity
 $
 35,780
 $
 34,970

 II-86

 STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

 Number of
Common
Shares
Issued
 Common
Stock
 Paid-In
Capital
 Retained
Earnings
 Accumulated
Other
Comprehensive
Income (Loss)
 Total

 $
 1,222
 $
 5,413
 $
 3,194
 $
 ( 19)
 $
 9,810

 Net income after dividends on
 preferred stock
 —
 —
 —
 1,238
 —
 1,238

 —
 —
 —
 —

 —
 —
 —
 —

 —
 —
 —
 ( 984)
 —
 ( 984)

 1,222
 6,056
 3,448
 ( 13)
 10,713

 Net income after dividends on
 preferred stock
 —
 —
 —
 1,340
 —
 1,340

 —
 —
 —
 —

 —
 —
 —
 —

 —
 —
 —
 ( 1,016)
 —
 ( 1,016)

 Other
 —
 —
 —
 ( 8)
 —
 ( 8)

 1,222
 6,710
 3,764
 ( 9)
 11,687

 Net income after dividends on
 preferred stock
 —
 —
 —
 1,370
 —
 1,370

 —
 —
 —
 —

 —
 —
 —
 —

 —
 —
 —
 ( 1,141)
 —
 ( 1,141)

 $
 1,222
 $
 7,125
 $
 3,993
 $
 ( 7)
 $
 12,333

 II-87

 To the stockholder and the Board of Directors of Georgia Power Company
 We have audited the accompanying balance sheets of Georgia Power Company (Georgia Power) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2023 and 2022, the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2023, the related notes, and the financial statement schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Georgia Power as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
 These financial statements are the responsibility of Georgia Power's management. Our responsibility is to express an opinion on Georgia Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Georgia Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Georgia Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Georgia Power's internal control over financial reporting. Accordingly, we express no such opinion.
 Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
 The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the Audit Committee of Southern Company's Board of Directors and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
 Impact of Rate Regulation on the Financial Statements – Refer to Note 1 (Summary of Significant Accounting Policies – Regulatory Assets and Liabilities) and Note 2 (Regulatory Matters – Georgia Power) to the financial statements
 Georgia Power is subject to retail rate regulation by the Georgia Public Service Commission and wholesale regulation by the Federal Energy Regulatory Commission (collectively, the "Commissions"). Management has determined that it meets the requirements under accounting principles generally accepted in the United States of America to utilize specialized rules to account for the effects of rate regulation in the preparation of its financial statements. Accounting for the economics of rate regulation may impact multiple financial statement line items and disclosures.
 The Commissions set the rates Georgia Power is permitted to charge customers. Rates are determined and approved in regulatory proceedings based on an analysis of Georgia Power's costs to provide utility service and a return on, and recovery of, its investment in the utility business. Current and future regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investments, and the timing and amount of assets to be recovered through rates. The Commissions' regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. While Georgia Power expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on those investments.
 II-88

 We identified the impact of rate regulation related to certain assets and liabilities as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and/or the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on incurred costs. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and/or (3) a refund to customers. Auditing these judgments, which include assumptions about the outcome of future decisions by the Commissions, required specialized knowledge of accounting for rate regulations and the rate setting process due to its inherent complexities.
 Our audit procedures related to the impact of rate regulation on certain assets and liabilities included the following, among others:
 • We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of certain incurred costs and (2) refunds or future reductions in rates that should be reported as regulatory liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering certain costs in future rates or of a future reduction in rates. We also tested the effectiveness of management's controls over the initial recognition of regulatory assets or liabilities.
 • We read and evaluated relevant regulatory orders and/or other relevant publicly available information to assess the likelihood of recovery of certain incurred costs in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances.
 • We tested certain incurred costs recorded as regulatory assets or liabilities during the period for completeness and accuracy.
 • We obtained representation from management regarding the likelihood of recoverability of incurred costs and potential refund or future reduction in rates to assess management's assertions about the likelihood of recovery, refund, or a future reduction in rates.
 • We evaluated Georgia Power's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments, including where there is a high degree of subjectivity involved in assessing the potential impact of future regulatory orders on incurred costs.
 We have served as Georgia Power's auditor since 2002.
 II-89

 STATEMENTS OF INCOME

 2023
 2022
 2021

 Retail revenues
 $
 9,222
 $
 10,792
 $
 8,478

 Wholesale revenues

 10,118
 11,584
 9,260

 Fuel
 1,781
 2,486
 1,449

 Purchased power, non-affiliates

 Purchased power, affiliates
 1,401

 2,083
 2,349
 2,213

 1,681
 1,430
 1,371

 ( 68)
 1,692

 7,299
 9,232
 8,692

 2,819
 2,352

 ( 626)
 ( 485)
 ( 421)

 ( 291)
 ( 169)
 ( 152)

 2,528
 2,183

 ( 168)

 $
 2,080
 $
 1,813
 $

 STATEMENTS OF COMPREHENSIVE INCOME

 2023
 2022
 2021

 $
 2,080
 $
 1,813
 $

 Other comprehensive income:

 Changes in fair value, net of tax of $( 1), $ 8, and $ —, respectively

 ( 2)
 —

 net of tax of $ 2, $ 2, and $ 2, respectively

 Total other comprehensive income

 $
 2,083
 $
 1,841
 $

 II-90

 STATEMENTS OF CASH FLOWS

 2023
 2022
 2021

 $
 2,080
 $
 1,813
 $

 Adjustments to reconcile net income

 1,914
 1,622
 1,557

 ( 550)

 ( 140)

 Pension, postretirement, and other employee benefits
 ( 272)
 ( 240)
 ( 148)

 Settlement of asset retirement obligations
 ( 304)
 ( 212)
 ( 210)

 Storm damage accruals

 Retail fuel cost under recovery – long-term

 ( 1,646)
 ( 410)

 ( 68)
 1,692

 ( 82)

 ( 57)
 ( 286)

 -Retail fuel cost under recovery
 —
 —

 -Fossil fuel stock
 ( 189)
 ( 43)

 -Materials and supplies
 ( 154)
 ( 73)
 ( 82)

 ( 63)
 ( 83)
 ( 30)

 ( 206)

 -Accrued taxes

 -Retail fuel cost over recovery
 —
 —
 ( 113)

 -Customer refunds
 ( 117)

 ( 5)
 ( 14)
 ( 1)

 2,752
 2,038
 2,747

 ( 4,786)
 ( 3,809)
 ( 3,311)

 Nuclear decommissioning trust fund purchases
 ( 841)
 ( 770)
 ( 960)

 Nuclear decommissioning trust fund sales

 Cost of removal, net of salvage
 ( 279)
 ( 274)
 ( 149)

 Change in construction payables, net of joint owner portion
 ( 65)

 Payments pursuant to LTSAs
 ( 49)
 ( 44)
 ( 42)

 Proceeds from dispositions

 ( 54)
 ( 57)
 ( 27)

 ( 5,079)
 ( 3,954)
 ( 3,590)

 —
 ( 60)

 2,450
 1,500

 2,100
 —

 FFB loan
 —
 —

 Redemptions and repurchases —

 ( 800)
 ( 400)
 ( 325)

 ( 1,430)
 ( 500)
 —

 FFB loan
 ( 86)
 ( 88)
 ( 96)

 —
 ( 53)
 ( 69)

 —
 ( 125)
 —

 2,291
 1,471
 1,782

 ( 1,855)
 ( 1,691)
 ( 1,649)

 ( 38)
 ( 51)
 ( 28)

 Net cash provided from financing activities
 1,922
 2,363

 ( 405)

 $
 $
 $

 Interest (net of $ 86, $ 73, and $ 63 capitalized, respectively)

 $
 $
 $

 Noncash transactions — Accrued property additions at year-end

 II-91

 2023
 2022

 $
 $

 Customer accounts, net

 Under recovered retail fuel clause revenues

 —

 Joint owner accounts

 Fossil fuel stock

 Regulatory assets – asset retirement obligations

 4,261
 3,399

 49,370
 41,879

 Less: Accumulated provision for depreciation
 13,955
 13,115

 35,415
 28,764

 Nuclear fuel, at amortized cost

 4,975
 8,103

 40,995
 37,471

 Nuclear decommissioning trusts, at fair value
 1,163
 1,018

 Miscellaneous property and investments

 1,361
 1,176

 1,007

 Deferred charges related to income taxes

 Prepaid pension costs

 Deferred under recovered retail fuel clause revenues

 1,211
 2,056

 Regulatory assets – asset retirement obligations, deferred
 3,407
 3,671

 2,890
 2,522

 10,200
 11,117

 $
 56,817
 $
 53,163

 II-92

 Liabilities and Stockholder's Equity
 2023
 2022

 $
 $

 1,329
 1,600

 Other
 1,147
 1,076

 Customer deposits

 Accrued interest

 Asset retirement obligations

 5,935
 6,578

 16,198
 14,009

 4,018
 3,707

 2,161
 2,244

 Accumulated deferred ITCs

 Operating lease obligations, deferred

 Asset retirement obligations, deferred
 5,327
 5,739

 13,301
 13,718

 35,434
 34,305

 Common stock, without par value
 (Authorized - 20 million shares; Outstanding - 9 million shares)

 17,923
 15,626

 Retained earnings
 3,071
 2,846

 Accumulated other comprehensive loss
 ( 9)
 ( 12)

 Total common stockholder's equity (See accompanying statements)

 21,383
 18,858

 Total Liabilities and Stockholder's Equity
 $
 56,817
 $
 53,163

 II-93

 STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

 Number of Common Shares Issued
 Retained Earnings
 Accumulated Other Comprehensive Income (Loss)
 Total

 $
 $
 12,361
 $
 3,789
 $
 ( 47)
 $
 16,501

 —
 —
 —
 —

 —
 —
 1,792
 —
 —
 1,792

 —
 —
 —
 —

 —
 —
 —
 ( 1,649)
 —
 ( 1,649)

 14,153
 2,724
 ( 41)
 17,234

 —
 —
 —
 1,813
 —
 1,813

 —
 —
 1,473
 —
 —
 1,473

 —
 —
 —
 —

 —
 —
 —
 ( 1,691)
 —
 ( 1,691)

 Other
 —
 —
 —
 —

 15,626
 2,846
 ( 12)
 18,858

 —
 —
 —
 2,080
 —
 2,080

 —
 —
 2,297
 —
 —
 2,297

 —
 —
 —
 —

 —
 —
 —
 ( 1,855)
 —
 ( 1,855)

 $
 $
 17,923
 $
 3,071
 $
 ( 9)
 $
 21,383

 II-94

 To the stockholder and the Board of Directors of Mississippi Power Company
 We have audited the accompanying balance sheets of Mississippi Power Company (Mississippi Power) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2023 and 2022, the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2023, the related notes, and the financial statement schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Mississippi Power as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
 These financial statements are the responsibility of Mississippi Power's management. Our responsibility is to express an opinion on Mississippi Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Mississippi Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Mississippi Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Mississippi Power's internal control over financial reporting. Accordingly, we express no such opinion.
 Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
 The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the Audit Committee of Southern Company's Board of Directors and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
 Impact of Rate Regulation on the Financial Statements – Refer to Note 1 (Summary of Significant Accounting Policies – Regulatory Assets and Liabilities) and Note 2 (Regulatory Matters – Mississippi Power) to the financial statements
 Mississippi Power is subject to retail rate regulation by the Mississippi Public Service Commission and wholesale regulation by the Federal Energy Regulatory Commission (collectively, the "Commissions"). Management has determined that it meets the requirements under accounting principles generally accepted in the United States of America to utilize specialized rules to account for the effects of rate regulation in the preparation of its financial statements. Accounting for the economics of rate regulation may impact multiple financial statement line items and disclosures.
 The Commissions set the rates Mississippi Power is permitted to charge customers. Rates are determined and approved in regulatory proceedings based on an analysis of Mississippi Power's costs to provide utility service and a return on, and recovery of, its investment in the utility business. Current and future regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investments, and the timing and amount of assets to be recovered through rates. The Commissions' regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. While Mississippi Power expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on those investments.
 II-95

 We identified the impact of rate regulation related to certain assets and liabilities as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and/or the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on incurred costs. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and/or (3) a refund to customers. Auditing these judgments, which include assumptions about the outcome of future decisions by the Commissions, required specialized knowledge of accounting for rate regulations and the rate setting process due to its inherent complexities.
 Our audit procedures related to the impact of rate regulation on certain assets and liabilities included the following, among others:
 • We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of certain incurred costs and (2) refunds or future reductions in rates that should be reported as regulatory liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering certain costs in future rates or of a future reduction in rates. We also tested the effectiveness of management's controls over the initial recognition of regulatory assets or liabilities.
 • We read and evaluated relevant regulatory orders and/or other relevant publicly available information to assess the likelihood of recovery of certain incurred costs in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances.
 • We tested certain incurred costs recorded as regulatory assets or liabilities during the period for completeness and accuracy.
 • We obtained representation from management regarding the likelihood of recoverability of incurred costs and potential refund or future reduction in rates to assess management's assertions about the likelihood of recovery, refund, or a future reduction in rates.
 • We evaluated Mississippi Power's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments, including where there is a high degree of subjectivity involved in assessing the potential impact of future regulatory orders on incurred costs.
 We have served as Mississippi Power's auditor since 2002.

 II-96

 STATEMENTS OF INCOME

 2023
 2022
 2021

 Retail revenues
 $
 $
 $

 Wholesale revenues, non-affiliates

 Wholesale revenues, affiliates

 1,474
 1,694
 1,322

 Fuel and purchased power

 1,214
 1,470
 1,117

 ( 71)
 ( 56)
 ( 60)

 ( 36)
 ( 23)
 ( 25)

 $
 $
 $

 STATEMENTS OF COMPREHENSIVE INCOME

 2023
 2022
 2021

 $
 $
 $

 Other comprehensive income:

 net of tax of $ —, $ —, and $ —, respectively

 —
 —

 Total other comprehensive income
 —
 —

 $
 $
 $

 II-97

 STATEMENTS OF CASH FLOWS

 2023
 2022
 2021

 $
 $
 $

 Adjustments to reconcile net income

 ( 13)
 ( 6)
 ( 4)

 Pension, postretirement, and other employee benefits
 ( 20)
 ( 18)
 ( 10)

 Settlement of asset retirement obligations
 ( 18)
 ( 20)
 ( 24)

 System restoration rider and reliability reserve accruals
 ( 2)

 Retail fuel cost under recovery – long-term
 ( 50)
 —
 —

 ( 5)
 ( 21)

 ( 82)

 -Materials and supplies
 ( 9)
 ( 10)
 ( 6)

 ( 15)
 —

 ( 81)
 ( 35)

 -Accrued taxes
 ( 7)

 -Retail fuel cost over recovery
 —
 ( 24)

 ( 8)
 ( 15)

 ( 319)

 Cost of removal net of salvage
 ( 32)
 ( 27)
 ( 20)

 Payments pursuant to LTSAs
 ( 26)
 ( 29)
 ( 29)

 ( 4)
 ( 10)

 ( 370)
 ( 317)

 —
 —
 ( 25)

 —

 —
 —

 Redemptions —

 —
 —
 ( 320)

 —
 —
 ( 100)

 ( 185)
 ( 170)

 ( 3)
 ( 1)
 ( 10)

 Net cash provided from (used for) financing activities
 ( 20)
 ( 68)

 ( 21)
 ( 2)

 $
 $
 $

 Interest
 $
 $
 $

 Noncash transactions — Accrued property additions at year-end

 II-98

 2023
 2022

 $
 $

 Customer accounts, net

 Fossil fuel stock

 5,523
 5,254

 Less: Accumulated provision for depreciation
 1,792
 1,689

 3,731
 3,565

 3,934
 3,773

 Other Property and Investments

 Deferred charges related to income taxes

 Prepaid pension costs

 Deferred under recovered retail fuel clause revenues

 —

 Regulatory assets – asset retirement obligations

 $
 5,344
 $
 5,272

 II-99

 Liabilities and Stockholder's Equity
 2023
 2022

 $
 $

 Other

 Asset retirement obligations

 Over recovered retail fuel clause revenues

 —

 1,443
 1,544

 Asset retirement obligations, deferred

 Other cost of removal obligations

 1,219
 1,243

 3,341
 3,341

 Common stock, without par value
 (Authorized - 50 million shares; Outstanding - 1 million shares)

 4,721
 4,652

 Accumulated deficit
 ( 2,756)
 ( 2,759)

 Total common stockholder's equity (See accompanying statements)

 2,003
 1,931

 Total Liabilities and Stockholder's Equity
 $
 5,344
 $
 5,272

 II-100

 STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

 Number of Common Shares Issued
 Common
Stock
 Retained Earnings (Accumulated Deficit)
 Accumulated Other Comprehensive Income (Loss)
 Total

 $
 $
 4,460
 $
 ( 2,754)
 $
 ( 2)
 $
 1,742

 —
 —
 —
 —

 —
 —
 —
 —

 —
 —
 —
 —

 —
 —
 —
 —

 Other
 —
 —
 —
 ( 1)
 —

 4,582
 ( 2,753)
 —
 1,867

 —
 —
 —
 —

 —
 —
 —
 —

 —
 —
 —
 ( 170)
 —
 ( 170)

 4,652
 ( 2,759)
 —
 1,931

 —
 —
 —
 —

 —
 —
 —
 —

 —
 —
 —
 ( 185)
 —
 ( 185)

 $
 $
 4,721
 $
 ( 2,756)
 $
 —
 $
 2,003

 II-101

 To the stockholder and the Board of Directors of Southern Power Company and Subsidiary Companies
 We have audited the accompanying consolidated balance sheets of Southern Power Company and subsidiary companies (Southern Power) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2023 and 2022, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2023, the related notes, and the financial statement schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Southern Power as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
 These financial statements are the responsibility of Southern Power's management. Our responsibility is to express an opinion on Southern Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Southern Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Southern Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Southern Power's internal control over financial reporting. Accordingly, we express no such opinion.
 Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
 The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the Audit Committee of Southern Company's Board of Directors and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
 Income/Loss Allocation to Noncontrolling Interests – Refer to Notes 1 and 7 to the financial statements
 Southern Power has entered into a number of tax equity partnership arrangements, wherein they agree to sell 100% of a class of membership interests (e.g. Class A) in an entity to a noncontrolling investor in exchange for cash contributions, while retaining control of the entity through a separate class of membership interests (e.g. Class B). The agreements for these partnerships give different rights and priorities to their owners in terms of cash distributions, tax attribute allocations, and partnership income or loss allocations. These provisions make the conventional equity method of accounting where an investor applies its "percentage ownership interest" to the investee's net income under generally accepted accounting principles to determine the investor's share of earnings or losses difficult to apply. Therefore, Southern Power uses the Hypothetical Liquidation at Book Value (HLBV) accounting method to account for these partnership arrangements. The HLBV accounting method calculates each partner's share of income or loss based on the change in net equity the partner can legally claim at the end of the reporting period compared to the beginning of the reporting period. The application of the HLBV accounting method by Southern Power required significant consideration of the allocations between Southern Power and the noncontrolling investors over the life of the agreement and the liquidation provisions of the agreement to determine the appropriate allocation of income or loss between the parties.
 II-102

 The determination of the appropriate amount of allocated partnership income or loss to noncontrolling interests using the HLBV accounting method required increased audit effort and specialized skill and knowledge, including evaluation of the terms of the agreement and consideration of the appropriateness of the HLBV model based on the provisions of the agreement.
 Our audit procedures included the following, among others:
 • We read certain agreements to understand the liquidation provisions and the provisions governing the allocation of benefits.
 • We evaluated certain HLBV models utilized by management to determine whether the models accurately reflect the allocation of income or loss and tax attributes in accordance with the liquidation provisions and allocation terms defined in the agreements, as well as whether the inputs in the models are accurate and complete.
 We have served as Southern Power's auditor since 2002.
 II-103

 CONSOLIDATED STATEMENTS OF INCOME

 2023
 2022
 2021

 Wholesale revenues, non-affiliates
 $
 1,597
 $
 2,458
 $
 1,671

 Wholesale revenues, affiliates

 2,189
 3,369
 2,216

 Fuel
 1,614

 Loss on sales-type leases
 —

 ( 20)
 ( 2)
 ( 41)

 1,830
 2,971
 1,925

 ( 129)
 ( 138)
 ( 147)

 ( 117)
 ( 131)
 ( 137)

 ( 13)

 Net loss attributable to noncontrolling interests
 ( 99)

 Net Income Attributable to Southern Power
 $
 $
 $

 The accompanying notes are an integral part of these consolidated financial statements.
 II-104

 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 2023
 2022
 2021

 $
 $
 $

 Other comprehensive income:

 Changes in fair value, net of tax of $( 1), $( 30), and $( 22), respectively

 ( 3)
 ( 91)
 ( 67)

 net of tax of $ 4, $ 26, and $ 30, respectively

 Pension and other postretirement benefit plans:

 Benefit plan net gain (loss),
 net of tax of $( 2), $ 6, and $ 5, respectively

 ( 7)

 net of tax of $ —, $ 1, and $ 1, respectively

 —

 Total other comprehensive income

 Comprehensive loss attributable to noncontrolling interests
 ( 99)

 Comprehensive Income Attributable to Southern Power
 $
 $
 $

 The accompanying notes are an integral part of these consolidated financial statements.

 II-105

 CONSOLIDATED STATEMENTS OF CASH FLOWS

 2023
 2022
 2021

 $
 $
 $

 Adjustments to reconcile net income

 Utilization of federal investment tax credits

 Amortization of investment tax credits
 ( 58)
 ( 58)
 ( 58)

 ( 20)
 ( 2)
 ( 41)

 Loss on sales-type leases
 —

 ( 1)

 ( 82)
 ( 44)

 -Prepaid income taxes
 ( 16)

 ( 24)
 ( 11)
 ( 14)

 ( 60)

 1,096

 Acquisitions, net of cash acquired
 ( 181)
 —
 ( 345)

 ( 118)
 ( 100)
 ( 396)

 Change in construction payables
 ( 69)
 ( 15)

 Proceeds from dispositions

 Payments pursuant to LTSAs
 ( 50)
 ( 71)
 ( 82)

 ( 2)

 ( 265)
 ( 194)
 ( 803)

 ( 83)

 Proceeds — Senior notes
 —
 —

 Redemptions — Senior notes

 ( 290)
 ( 677)
 ( 300)

 Return of capital to parent company
 —
 —
 ( 271)

 Capital contributions from noncontrolling interests

 Distributions to noncontrolling interests
 ( 234)

 ( 252)

 —
 ( 2)
 ( 14)

 Net cash used for financing activities
 ( 820)
 ( 623)
 ( 195)

 ( 2)
 ( 47)

 $
 $
 $

 Cash paid (received) during the period for —

 Interest (net of $ 3, $ —, and $ 6 capitalized, respectively)

 $
 $
 $

 ( 254)
 ( 15)
 ( 275)

 Noncash transactions —

 Accrued property additions at year-end

 LTSA credits utilized from the sale of spare parts
 —
 —

 Contributions from noncontrolling interests
 —

 Contributions of wind turbine equipment
 —
 —

 The accompanying notes are an integral part of these consolidated financial statements.
 II-106

 2023
 2022

 $
 $

 Customer accounts, net

 Other

 14,690
 14,658

 Less: Accumulated provision for depreciation
 4,119
 3,661

 10,571
 10,997

 10,849
 11,038

 Intangible assets, net of amortization of $ 148 and $ 129, respectively

 —

 Net investment in sales-type leases

 Prepaid LTSAs

 Income taxes receivable, non-current

 $
 12,761
 $
 13,081

 The accompanying notes are an integral part of these consolidated financial statements.
 II-107

 Liabilities and Stockholders' Equity
 2023
 2022

 $
 —
 $

 Other

 Accrued interest

 2,711
 2,689

 Accumulated deferred ITCs
 1,498
 1,556

 Operating lease obligations, deferred

 2,862
 2,592

 6,063
 6,165

 Common stock, par value $ 0.01 per share
 (Authorized - 1 million shares; Outstanding - 1,000 shares)

 —
 —

 1,088
 1,069

 Retained earnings
 1,846
 1,741

 Accumulated other comprehensive loss
 ( 17)
 ( 18)

 Total common stockholder's equity
 2,917
 2,792

 Noncontrolling Interests
 3,781
 4,124

 Total Stockholders' Equity (See accompanying statements)

 6,698
 6,916

 Total Liabilities and Stockholders' Equity
 $
 12,761
 $
 13,081

 The accompanying notes are an integral part of these consolidated financial statements.
 II-108

 CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

 Number of Common Shares Issued
 Retained Earnings
 Accumulated Other Comprehensive Income (Loss)
 Total Common Stockholder's Equity
 Noncontrolling Interests
 Total

 —
 $
 —
 $
 $
 1,522
 $
 ( 67)
 $
 2,369
 $
 4,262
 $
 6,631

 Net income (loss)
 —
 —
 —
 —
 ( 99)

 Return of capital to parent
 company
 —
 —
 ( 271)
 —
 —
 ( 271)
 —
 ( 271)

 Capital contributions from parent
 company
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —

 Cash dividends on common
 stock
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —
 —

 Distributions to noncontrolling
 interests
 —
 —
 —
 —
 —
 —

 Other
 —
 —
 ( 15)
 —
 ( 14)
 —
 ( 14)

 —
 —
 1,585
 ( 27)
 2,196
 4,402
 6,598

 Net income (loss)
 —
 —
 —
 —

 Capital contributions from parent
 company
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —

 Cash dividends on common
 stock
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —

 Distributions to noncontrolling
 interests
 —
 —
 —
 —
 —
 —

 Other
 —
 —
 —
 —
 ( 1)
 ( 1)
 —
 ( 1)

 —
 —
 1,069
 1,741
 ( 18)
 2,792
 4,124
 6,916

 Net income (loss)
 —
 —
 —
 —

 Capital contributions from parent
 company
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —

 Cash dividends on common
 stock
 —
 —
 —
 ( 252)
 —
 ( 252)
 —
 ( 252)

 —
 —
 —
 —
 —
 —

 Distributions to noncontrolling
 interests
 —
 —
 —
 —
 —
 —
 ( 236)
 ( 236)

 Other
 —
 —
 —
 —
 —
 —
 ( 1)
 ( 1)

 —
 $
 —
 $
 1,088
 $
 1,846
 $
 ( 17)
 $
 2,917
 $
 3,781
 $
 6,698

 The accompanying notes are an integral part of these consolidated financial statements.
 II-109

 To the stockholder and the Board of Directors of Southern Company Gas and Subsidiary Companies
 We have audited the accompanying consolidated balance sheets of Southern Company Gas and subsidiary companies (Southern Company Gas) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2023 and 2022, the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2023, the related notes, and the financial statement schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Southern Company Gas as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
 We did not audit the financial statements of Southern Natural Gas Company, L.L.C. (SNG), Southern Company Gas' investment which is accounted for by the use of the equity method. The accompanying consolidated financial statements of Southern Company Gas include its equity investment in SNG of $1,202 million and $1,243 million as of December 31, 2023 and December 31, 2022, respectively, and its earnings from its equity method investment in SNG of $139 million, $146 million, and $127 million for the years ended December 31, 2023, 2022, and 2021, respectively. Those statements were audited by other auditors whose reports (which express unqualified opinions on SNG's financial statements and contain an emphasis of matter paragraph calling attention to SNG's significant transactions with related parties) have been furnished to us, and our opinion, insofar as it relates to the amounts included for SNG, is based solely on the reports of the other auditors.
 These financial statements are the responsibility of Southern Company Gas' management. Our responsibility is to express an opinion on Southern Company Gas' financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Southern Company Gas in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Southern Company Gas is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Southern Company Gas' internal control over financial reporting. Accordingly, we express no such opinion.
 Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits and the reports of the other auditors provide a reasonable basis for our opinion.
 The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the Audit Committee of Southern Company's Board of Directors and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
 Impact of Rate Regulation on the Financial Statements – Refer to Note 1 (Summary of Significant Accounting Policies – Regulatory Assets and Liabilities) and Note 2 (Regulatory Matters – Southern Company Gas) to the financial statements
 Southern Company Gas' natural gas distribution utilities (the "regulated utility subsidiaries") are subject to rate regulation by their respective state Public Service Commission or other applicable state regulatory agencies (collectively, the "Commissions"). Management has determined that it meets the requirements under accounting principles generally accepted in the United States of America to utilize specialized rules to account for the effects of rate regulation in the preparation of its financial statements. Accounting for the economics of rate regulation may impact multiple financial statement line items and disclosures.
 II-110

 The Commissions set the rates the regulated utility subsidiaries are permitted to charge customers. Rates are determined and approved in regulatory proceedings based on an analysis of the applicable regulated utility subsidiary's costs to provide utility service and a return on, and recovery of, its investment in the utility business. Current and future regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investments, and the timing and amount of assets to be recovered through rates. The Commissions' regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. While Southern Company Gas' regulated utility subsidiaries expect to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on those investments.
 We identified the impact of rate regulation related to certain assets and liabilities as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and/or the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on incurred costs. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and/or (3) a refund to customers. Auditing these judgments, which include assumptions about the outcome of future decisions by the Commissions, required specialized knowledge of accounting for rate regulations and the rate setting process due to its inherent complexities.
 Our audit procedures related to the impact of rate regulation on certain assets and liabilities included the following, among others:
 • We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of certain incurred costs and (2) refunds or future reductions in rates that should be reported as regulatory liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering certain costs in future rates or of a future reduction in rates, including Qualifying Infrastructure Plant capital investments by Nicor Gas. We also tested the effectiveness of management's controls over the initial recognition of regulatory assets or liabilities.
 • We read and evaluated relevant regulatory orders and/or other relevant publicly available information to assess the likelihood of recovery of certain incurred costs in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances.
 • We tested certain incurred costs recorded as regulatory assets or liabilities during the period for completeness and accuracy.
 • We obtained representation from management regarding the likelihood of recoverability of incurred costs and potential refund or future reduction in rates to assess management's assertions about the likelihood of recovery, refund, or a future reduction in rates.
 • We evaluated Southern Company Gas' disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments, including where there is a high degree of subjectivity involved in assessing the potential impact of future regulatory orders on incurred costs.
 We have served as Southern Company Gas' auditor since 2016.
 II-111

 Board of Directors and Members
 Southern Natural Gas Company, L.L.C.
 Houston, Texas

 Opinion on the Consolidated Financial Statements
 We have audited the accompanying consolidated balance sheets of Southern Natural Gas Company, L.L.C. (the "Company") as of December 31, 2023 and 2022, the related consolidated statements of income, members' equity, and cash flows for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
 These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
 Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
 The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
 II-112

 Fair Value of Investments Measured at Fair Value
 As discussed in Note 5 to the consolidated financial statements, the fair value of postretirement benefit plan assets on December 31, 2023, was $66 million. Of this amount, $65 million represents the fair value of private debt and equity securities measured at net asset value (NAV).
 We identified the assessment of the fair value of investments measured at NAV as a critical audit matter. Subjective auditor judgment was required in the application and performance of procedures to assess the fair value of the investments measured at NAV because the determination involved the use of unobservable inputs. Additionally, specialized skills and knowledge were required to assess the fair value of the investments measured at NAV and to assess the sufficiency of audit evidence obtained.
 The primary procedures we performed to address this critical audit matter included:
 • Comparing the fair values as recorded by the Company to external confirmations received directly from the third-party investment managers.
 • Utilized specialists who performed a benchmark analysis to determine the correlation of the funds and the stated benchmark; the results were used to estimate the high and low fair value range of the investments to compare to the Company's fair value.
 Emphasis of Matter – Significant Transactions with Related Parties
 As discussed in Note 6 to the consolidated financial statements, the Company has entered into significant transactions with related parties.
 /s/ BDO USA, P.C.
 We have served as the Company's auditor since 2018.
 Houston, Texas
 February 6, 2024
 II-113

 CONSOLIDATED STATEMENTS OF INCOME

 2023
 2022
 2021

 Natural gas revenues (includes revenue taxes of
 $ 133, $ 162, and $ 122, respectively)

 $
 4,702
 $
 5,962
 $
 4,380

 4,702
 5,962
 4,380

 1,644
 3,004
 1,619

 1,194
 1,176
 1,072

 —
 —

 —
 —

 ( 7)
 ( 4)

 3,763
 5,148
 3,325

 1,055

 ( 310)
 ( 263)
 ( 238)

 ( 53)

 ( 113)
 ( 62)
 ( 241)

 $
 $
 $

 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 2023
 2022
 2021

 $
 $
 $

 Other comprehensive income (loss):

 Changes in fair value, net of tax of $( 18), $ 5, and $ 5, respectively

 ( 45)

 net of tax of $ 19, $( 9), and $( 5), respectively

 ( 24)
 ( 11)

 Pension and other postretirement benefit plans:

 Benefit plan net gain (loss),
 net of tax of $( 7), $ 8, and $ 17, respectively

 ( 15)

 net of tax of $ —, $ —, and $ —, respectively

 ( 1)
 —
 —

 Total other comprehensive income (loss)
 ( 15)

 $
 $
 $

 The accompanying notes are an integral part of these consolidated financial statements.

 II-114

 CONSOLIDATED STATEMENTS OF CASH FLOWS

 2023
 2022
 2021

 Consolidated net income
 $
 $
 $

 Adjustments to reconcile net income to net cash
 provided from operating activities —

 —

 ( 7)
 ( 4)

 Mark-to-market adjustments
 ( 7)

 Natural gas cost under recovery – long-term
 —
 ( 207)

 —
 —

 ( 60)
 ( 32)
 ( 30)

 ( 345)
 ( 143)

 -Natural gas for sale, net of temporary LIFO liquidation
 ( 77)

 -Prepaid income taxes
 ( 11)
 ( 82)

 -Natural gas cost under recovery
 ( 266)

 ( 17)
 ( 6)
 ( 116)

 ( 276)

 -Natural gas cost over recovery
 —
 —

 ( 51)
 ( 26)

 1,762
 1,519

 ( 1,561)
 ( 1,533)
 ( 1,421)

 Cost of removal, net of salvage
 ( 112)

 Change in construction payables, net
 ( 38)
 ( 29)

 Investments in unconsolidated subsidiaries
 ( 11)
 ( 5)

 Proceeds from dispositions

 ( 1,656)
 ( 1,580)
 ( 1,379)

 ( 153)
 ( 341)

 First mortgage bonds

 —

 —

 Redemptions and repurchases —

 —
 —
 ( 300)

 ( 200)
 ( 150)
 —

 Medium-term notes
 ( 350)
 ( 46)
 ( 30)

 First mortgage bonds
 ( 50)
 —
 —

 ( 585)
 ( 519)
 ( 530)

 ( 1)
 ( 1)
 ( 2)

 Net cash provided from (used for) financing activities
 ( 154)

 ( 48)

 $
 $
 $

 Interest (net of $ 16, $ 10, and $ 8 capitalized, respectively)

 $
 $
 $

 Noncash transactions — Accrued property additions at year-end

 The accompanying notes are an integral part of these consolidated financial statements.
 II-115

 2023
 2022

 $
 $

 Customer accounts

 Accumulated provision for uncollectible accounts
 ( 44)
 ( 50)

 Natural gas for sale

 Prepaid expenses

 Natural gas cost under recovery
 —

 1,486
 2,038

 20,840
 19,723

 Less: Accumulated depreciation
 5,534
 5,276

 15,306
 14,447

 1,110

 16,416
 15,356

 5,015
 5,015

 1,235
 1,276

 Other intangible assets, net of amortization of $ 166 and $ 156, respectively

 Miscellaneous property and investments

 6,291
 6,345

 Prepaid pension costs

 $
 25,083
 $
 24,621

 The accompanying notes are an integral part of these consolidated financial statements.
 II-116

 Liabilities and Stockholder's Equity
 2023
 2022

 $
 —
 $

 Other

 Customer deposits

 Natural gas cost over recovery
 —

 1,708
 2,570

 Long-term Debt
 7,833
 7,042

 1,671
 1,560

 Other cost of removal obligations
 1,771
 1,707

 Accrued environmental remediation

 4,739
 4,612

 14,280
 14,224

 Common stock, par value $ 0.01 per share
 (Authorized - 100 million shares; Outstanding - 100 shares)

 10,836
 10,445

 Accumulated deficit
 ( 49)
 ( 79)

 Accumulated other comprehensive income (loss)

 Total common stockholder's equity (See accompanying statements)

 10,803
 10,397

 Total Liabilities and Stockholder's Equity
 $
 25,083
 $
 24,621

 The accompanying notes are an integral part of these consolidated financial statements.

 II-117

 CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

 Number of Common Shares
Issued
 Retained Earnings (Accumulated Deficit)
 Accumulated
Other
Comprehensive Income (Loss)
 Total

 —
 $
 —
 $
 9,930
 $
 ( 141)
 $
 ( 22)
 $
 9,767

 —
 —
 —
 —

 —
 —
 —
 —

 —
 —
 —
 —

 —
 —
 —
 ( 530)
 —
 ( 530)

 —
 —
 10,024
 ( 132)
 9,916

 —
 —
 —
 —

 —
 —
 —
 —

 —
 —
 —
 —

 —
 —
 —
 ( 519)
 —
 ( 519)

 —
 —
 10,445
 ( 79)
 10,397

 —
 —
 —
 —

 —
 —
 —
 —

 Other comprehensive income (loss)
 —
 —
 —
 —
 ( 15)
 ( 15)

 —
 —
 —
 ( 585)
 —
 ( 585)

 —
 $
 —
 $
 10,836
 $
 ( 49)
 $
 $
 10,803

 The accompanying notes are an integral part of these consolidated financial statements.
 II-118

 Notes to the Financial Statements
 for
 The Southern Company and Subsidiary Companies

 Index to the Combined Notes to Financial Statements

 Note
 Page

 Summary of Significant Accounting Policies

 II- 120

 Regulatory Matters

 II- 135

 Contingencies, Commitments, and Guarantees

 II- 157

 Revenue from Contracts with Customers

 II- 163

 Property, Plant, and Equipment

 II- 167

 Asset Retirement Obligations

 II- 171

 Consolidated Entities and Equity Method Investments

 II- 175

 Financing

 II- 178

 Leases

 II- 187

 II- 194

 Retirement Benefits

 II- 201

 Stock Compensation

 II- 228

 Fair Value Measurements

 II- 231

 Derivatives

 II- 239

 Acquisitions and Dispositions

 II- 248

 Segment and Related Information

 II- 250

 Index to Applicable Notes to Financial Statements by Registrant
 The following notes to the 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 note applies.

 Applicable Notes

 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16

 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15

 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14

 1, 2, 3, 4, 5, 6, 8, 9, 10, 11, 12, 13, 14

 1, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15

 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16

 II-119

 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 General
 Southern Company is the parent company of three traditional electric operating companies, as well as Southern Power, Southern Company Gas, SCS, Southern Linc, Southern Holdings, Southern Nuclear, PowerSecure, and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in three Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through natural gas distribution utilities, including Nicor Gas (Illinois), Atlanta Gas Light (Georgia), Virginia Natural Gas, and Chattanooga Gas (Tennessee). Southern Company Gas is also involved in several other complementary businesses including gas pipeline investments and gas marketing services. Prior to the sale of Sequent on July 1, 2021, these businesses also included wholesale gas services. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, including Alabama Power's Plant Farley and Georgia Power's Plant Hatch and Plant Vogtle Units 1 through 3, and is currently managing construction and start-up of Plant Vogtle Unit 4. PowerSecure develops distributed energy and resilience solutions and deploys microgrids for commercial, industrial, governmental, and utility customers. See Note 15 for information regarding the sale of Sequent.
 The Registrants' financial statements reflect investments in subsidiaries on a consolidated basis. Intercompany transactions have been eliminated in consolidation. The equity method is used for investments in entities in which a Registrant has significant influence but does not have control and for VIEs where a Registrant has an equity investment but is not the primary beneficiary. Southern Power has controlling ownership in certain legal entities for which the contractual provisions represent profit-sharing arrangements because the allocations of cash distributions and tax benefits are not based on fixed ownership percentages. For these arrangements, the noncontrolling interest is accounted for under a balance sheet approach utilizing the HLBV method. The HLBV method calculates each partner's share of income based on the change in net equity the partner can legally claim in a HLBV at the end of the period compared to the beginning of the period. See "Variable Interest Entities" herein and Note 7 for additional information.
 The traditional electric operating companies, Southern Power, certain subsidiaries of Southern Company Gas, and certain other subsidiaries are subject to regulation by the FERC, and the traditional electric operating companies and the natural gas distribution utilities are also subject to regulation by their respective state PSCs or other applicable state regulatory agencies. As such, the respective financial statements of the applicable Registrants reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by relevant state PSCs or other applicable state regulatory agencies.
 The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the Registrants' results of operations, financial position, or cash flows.

 Recently Adopted Accounting Standards
 In 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (ASU 2020-04) providing temporary guidance to ease the potential burden in accounting for reference rate reform primarily resulting from the discontinuation of LIBOR, which began phasing out on December 31, 2021. The discontinuation date of the overnight 1-, 3-, 6-, and 12-month tenors of LIBOR was June 30, 2023, which was beyond the original effective date of ASU 2020-04; therefore, in December 2022, the FASB issued ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848 (ASU 2022-06) to defer the sunset date of ASU 2020-04 from December 31, 2022 to December 31, 2024.
 The amendments were elective and applied to all entities that have contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued. The guidance (i) simplified accounting analyses under current GAAP for contract modifications; (ii) simplified the assessment of hedge effectiveness and allows hedging relationships affected by reference rate reform to continue; and (iii) allowed a one-time election to sell or transfer debt securities classified as held to maturity that reference a rate affected by reference rate reform. An entity could elect to apply the amendments
 II-120

 prospectively from March 12, 2020 through December 31, 2024 by accounting topic. The Registrants elected to apply the amendments to modifications of debt and derivative arrangements that meet the scope of ASU 2020-04 and ASU 2022-06.
 Certain provisions in PPAs at Southern Power included 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 had 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 14 under "Interest Rate Derivatives" for additional information.

 Affiliate Transactions
 The traditional electric operating companies, Southern Power, and Southern Company Gas have agreements with SCS under which certain of the following services are rendered to them at direct or allocated cost: general executive and advisory, general and design engineering, operations, purchasing, accounting, finance, treasury, legal, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, cellular tower space, and other services with respect to business and operations, construction management, and Southern Company power pool transactions. These costs are primarily included in other operations and maintenance expenses or capitalized to property, plant, and equipment. Costs for these services from SCS in 2023, 2022, and 2021 were as follows:

Power
Power
Power
Power

 2023
 $
 $
 $
 $
 $

 2022

 2021

 Alabama Power and Georgia Power also have agreements with Southern Nuclear under which Southern Nuclear renders the following nuclear-related services at cost: general executive and advisory services; general operations, management, and technical services; administrative services including procurement, accounting, employee relations, systems, and procedures services; strategic planning and budgeting services; other services with respect to business and operations; and, for Georgia Power, construction management. These costs are primarily included in other operations and maintenance expenses or capitalized to property, plant, and equipment. Costs for these services in 2023, 2022, and 2021 amounted to $ 251 million, $ 267 million, and $ 258 million, respectively, for Alabama Power and $ 899 million, $ 895 million, and $ 906 million, respectively, for Georgia Power. See Note 2 under "Georgia Power – Nuclear Construction" for additional information regarding Southern Nuclear's construction management of Plant Vogtle Unit 4 for Georgia Power.
 Cost allocation methodologies used by SCS and Southern Nuclear prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.
 Alabama Power's and Georgia Power's power purchases from affiliates through the Southern Company power pool are included in purchased power, affiliates on their respective statements of income. Mississippi Power's and Southern Power's power purchases from affiliates through the Southern Company power pool are included in purchased power on their respective statements of income and were as follows:

Power
Power

 2023
 $
 $

 2022

 2021

 Georgia Power has entered into several PPAs with Southern Power for capacity and energy. Georgia Power's total expenses associated with these PPAs were $ 143 million, $ 151 million, and $ 132 million in 2023, 2022, and 2021, respectively. Southern Power's total revenues from all PPAs with Georgia Power, included in wholesale revenue affiliates on Southern Power's consolidated statements of income, were $ 145 million, $ 154 million, and $ 139 million for 2023, 2022, and 2021, respectively. Included within these revenues were affiliate PPAs accounted for as operating leases, which totaled $ 116 million, $ 116 million,
 II-121

 and $ 112 million for 2023, 2022, and 2021, respectively. See Note 9 for additional information. Also see Note 2 under "Georgia Power – Integrated Resource Plans" for information regarding additional affiliate PPAs commencing in 2024.
 SCS (as agent for Alabama Power, Georgia Power, and Southern Power) and Southern Company Gas have long-term interstate natural gas transportation agreements with SNG that are governed by the terms and conditions of SNG's natural gas tariff and are subject to FERC regulation. See Note 7 under "Southern Company Gas – Equity Method Investments" for additional information. Transportation costs under these agreements in 2023, 2022, and 2021 were as follows:

Power
Power
Power

 2023
 $
 $
 $
 $

 2022

 2021

 SCS, as agent for the traditional electric operating companies and Southern Power, has agreements with certain subsidiaries of Southern Company Gas to purchase natural gas. Natural gas purchases made under these agreements were immaterial for Alabama Power, Georgia Power, and Mississippi Power for all periods presented, immaterial for Southern Power in 2023 and 2022, and $ 18 million for Southern Power in 2021.
 Alabama Power and Mississippi Power jointly own Plant Greene County. The companies have an agreement under which Alabama Power operates Plant Greene County and Mississippi Power reimburses Alabama Power for its proportionate share of non-fuel operations and maintenance expenses, which totaled $ 5 million, $ 6 million, and $ 10 million in 2023, 2022, and 2021, respectively. See Note 5 under "Joint Ownership Agreements" for additional information.
 Alabama Power, Georgia Power, and Mississippi Power each have agreements with PowerSecure for equipment purchases and/or services related to utility infrastructure construction, distributed energy, and energy efficiency projects. Costs under these agreements were immaterial for all periods presented.
 Southern Company Gas has a $ 77 million contract with the U.S. General Services Administration to increase energy efficiency at certain federal buildings across Georgia, with completion expected by the end of 2024. Southern Company Gas engaged PowerSecure to provide the majority of the construction services under the contract. During 2023 and 2022, Southern Company Gas paid $ 29 million and $ 10 million, respectively, to PowerSecure related to this agreement.
 See Note 7 under "SEGCO" for information regarding Alabama Power's and Georgia Power's equity method investment in SEGCO and related affiliate purchased power costs, as well as Alabama Power's gas pipeline ownership agreement with SEGCO.
 Southern Power has several agreements with SCS for transmission services, which are billed to Southern Power based on the Southern Company Open Access Transmission Tariff as filed with the FERC. Transmission services purchased by Southern Power from SCS totaled $ 33 million, $ 39 million, and $ 28 million for 2023, 2022, and 2021, respectively, and were charged to other operations and maintenance expenses in Southern Power's consolidated statements of income.
 The traditional electric operating companies and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 14 under "Contingent Features" for additional information. Southern Power and the traditional electric operating companies generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity. See "Revenues – Southern Power" herein for additional information.
 The traditional electric operating companies, Southern Power, and Southern Company Gas provide incidental services to and receive such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the traditional electric operating companies, Southern Power, and Southern Company Gas neither provided nor received any material services to or from affiliates in any year presented.
 Regulatory Assets and Liabilities
 The traditional electric operating companies and the natural gas distribution utilities are subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent costs recovered that are expected to be incurred in the future or probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
 II-122

 In the event that a portion of a traditional electric operating company's or a natural gas distribution utility's operations is no longer subject to applicable accounting rules for rate regulation, such company would be required to write off to income or reclassify to AOCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the traditional electric operating company or the natural gas distribution utility would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 2 for additional information including details of regulatory assets and liabilities reflected in the balance sheets for Southern Company, the traditional electric operating companies, and Southern Company Gas.

 Revenues
 The Registrants generate revenues from a variety of sources which are accounted for under various revenue accounting guidance, including revenue from contracts with customers, lease, derivative, and regulatory accounting. See Notes 4, 9, and 14 for additional information.
 Traditional Electric Operating Companies
 The majority of the revenues of the traditional electric operating companies are generated from contracts with retail electric customers. These revenues, generated from the integrated service to deliver electricity when and if called upon by the customer, are recognized as a single performance obligation satisfied over time, at a tariff rate, and as electricity is delivered to the customer during the month. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Retail rates may include provisions to adjust revenues for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered from or returned to customers, respectively, through adjustments to the billing factors. See Note 2 for additional information regarding regulatory matters of the traditional electric operating companies.
 Wholesale capacity revenues from PPAs are recognized in amounts billable under the contract terms. Energy and other revenues are generally recognized as services are provided. The contracts for capacity and energy in a wholesale PPA have multiple performance obligations where the contract's total transaction price is allocated to each performance obligation based on the standalone selling price. The standalone selling price is primarily determined by the price charged to customers for the specific goods or services transferred with the performance obligations. Generally, the traditional electric operating companies recognize revenue as the performance obligations are satisfied over time as electricity is delivered to the customer or as generation capacity is available to the customer.
 For both retail and wholesale revenues, the traditional electric operating companies have elected to recognize revenue for their sales of electricity and capacity using the invoice practical expedient as they generally have a right to consideration in an amount that corresponds directly with the value to the customer of the performance completed to date and that may be invoiced. Payment for goods and services rendered is typically due in the subsequent month following satisfaction of the Registrants' performance obligation.

 Southern Power sells capacity and energy at rates specified under contractual terms in long-term PPAs. These PPAs are accounted for as leases, normal sale derivatives, or contracts with customers. Capacity revenues from PPAs classified as operating leases are recognized on a straight-line basis over the term of the agreement. Energy revenues are recognized in the period the energy is delivered. Capacity revenues from PPAs classified as sales-type leases are recognized by accounting for interest income on the net investment in the lease.
 Southern Power's non-lease contracts commonly include capacity and energy which are considered separate performance obligations. In these contracts, the total transaction price is allocated to each performance obligation based on the standalone selling price. The standalone selling price is primarily determined by the price charged to customers for the specific goods or services transferred with the performance obligations. Generally, Southern Power recognizes revenue as the performance obligations are satisfied over time, as electricity is delivered to the customer or as generation capacity is made available to the customer.
 Southern Power generally has a right to consideration in an amount that corresponds directly with the value to the customer of the performance completed to date and may recognize revenue in the amount to which the entity has a right to invoice. Payment for goods and services rendered is typically due in the subsequent month following satisfaction of Southern Power's performance obligation.
 When multiple contracts exist with the same counterparty, the revenues from each contract are accounted for as separate arrangements.
 II-123

 Southern Power may also enter into contracts to sell short-term capacity in the wholesale electricity markets. These sales are generally classified as mark-to-market derivatives and net unrealized gains and losses on such contracts are recorded in wholesale revenues. See Note 14 and "Financial Instruments" herein for additional information.

 Southern Company Gas records revenues when goods or services are provided to customers. Those revenues are based on rates approved by the state regulatory agencies of the natural gas distribution utilities. Atlanta Gas Light operates in a deregulated natural gas market whereby Marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and handle customer billing functions. As required by the Georgia PSC, Atlanta Gas Light bills Marketers in equal monthly installments for each residential, commercial, and industrial end-use customer's distribution costs as well as for capacity costs utilizing a seasonal rate design for the calculation of each residential end-use customer's annual straight-fixed-variable charge, which reflects the historic volumetric usage pattern for the entire residential class.
 The majority of the revenues of Southern Company Gas are generated from contracts with natural gas distribution customers. Revenues from this integrated service to deliver gas when and if called upon by the customer are recognized as a single performance obligation satisfied over time and are recognized at a tariff rate as gas is delivered to the customer during the month.
 The standalone selling price is primarily determined by the price charged to customers for the specific goods or services transferred with the performance obligations. Generally, Southern Company Gas recognizes revenue as the performance obligations are satisfied over time as natural gas is delivered to the customer. The performance obligations related to wholesale gas services are satisfied, and revenue is recognized, at a point in time when natural gas is delivered to the customer.
 Southern Company Gas has elected to recognize revenue for sales of gas using the invoice practical expedient as it generally has a right to consideration in an amount that corresponds directly with the value to the customer of the performance completed to date and that may be invoiced. Payment for goods and services rendered is typically due in the subsequent month following satisfaction of Southern Company Gas' performance obligation.
 With the exception of Atlanta Gas Light, the natural gas distribution utilities have rate structures that include volumetric rate designs that allow the opportunity to recover certain costs based on gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. Additionally, unbilled revenues are recognized for estimated deliveries of gas not yet billed to these customers, from the last bill date to the end of the accounting period. For other commercial and industrial customers, revenues are based on actual deliveries through the end of the period.
 The tariffs for the natural gas distribution utilities include provisions which allow for the recognition of certain revenues prior to the time such revenues are billed to customers. These provisions are referred to as alternative revenue programs and provide for the recognition of certain revenues prior to billing, as long as the amounts recognized will be collected from customers within 24 months of recognition. Revenue related to alternative revenue programs was $ 20 million, $( 5) million, and $ 11 million in 2023, 2022, and 2021, respectively. These programs are as follows:
 • Weather normalization adjustments – reduce customer bills when winter weather is colder than normal and increase customer bills when weather is warmer than normal and are included in the tariffs for Virginia Natural Gas and Chattanooga Gas;
 • Revenue normalization mechanisms – mitigate the impact of conservation and declining customer usage and are contained in the tariffs for Virginia Natural Gas and Nicor Gas; and
 • Revenue true-up adjustment – included within the provisions of the GRAM program in which Atlanta Gas Light participates as a short-term alternative to formal rate case filings, the revenue true-up feature provides for a positive (or negative) adjustment to record revenue in the amount of any variance to budgeted revenues, which are submitted and approved annually as a requirement of GRAM. Such adjustments are reflected in customer billings in a subsequent program year.
 Wholesale Gas Services
 Prior to the sale of Sequent on July 1, 2021, Southern Company Gas netted revenues from energy and risk management activities with the associated costs. Profits from sales between segments were eliminated and recognized as goods or services sold to end-use customers. Southern Company Gas recorded wholesale gas services' transactions that qualified as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains
 II-124

 and losses on derivatives held for energy trading purposes were presented on a net basis in revenue. See Note 15 under "Southern Company Gas" for additional information on the sale of Sequent.
 Gas Marketing Services
 Southern Company Gas recognizes revenues from natural gas sales and transportation services in the same period in which the related volumes are delivered to customers and recognizes sales revenues from residential and certain commercial and industrial customers on the basis of scheduled meter readings. Southern Company Gas also recognizes unbilled revenues for estimated deliveries of gas not yet billed to these customers from the most recent meter reading date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries during the period.
 Southern Company Gas recognizes revenues on 12-month utility-bill management contracts as the lesser of cumulative earned or cumulative billed amounts.

 Concentration of Revenue
 Southern Company, Alabama Power, Georgia Power, Mississippi Power (with the exception of its full requirements cost-based MRA electric tariffs described below), Southern Power, and Southern Company Gas each have a diversified base of customers and no single customer comprises 10% or more of each company's revenues.
 Mississippi Power provides service under long-term contracts with rural electric cooperative associations and a municipality located in southeastern Mississippi under requirements cost-based MRA electric tariffs, which are subject to regulation by the FERC. The contracts with these wholesale customers represented 14.0 % of Mississippi Power's total operating revenues in 2023.
 Fuel Costs
 Fuel costs for the traditional electric operating companies and Southern Power are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. For Alabama Power and Georgia Power, fuel expense also includes the amortization of the cost of nuclear fuel. For the traditional electric operating companies, fuel costs also include gains and/or losses from fuel-hedging programs as approved by their respective state PSCs.
 Cost of Natural Gas
 Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, Southern Company Gas charges its utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the applicable state regulatory agencies. Under these mechanisms, all prudently-incurred natural gas costs are passed through to customers without markup, subject to regulatory review. Southern Company Gas defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period such that no operating income is recognized related to these costs. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred and accrued natural gas costs are included in the balance sheets as regulatory assets and regulatory liabilities, respectively.
 Southern Company Gas' gas marketing services' customers are charged for actual or estimated natural gas consumed. Within cost of natural gas, Southern Company Gas also includes costs of lost and unaccounted for gas and gains and losses associated with certain derivatives.
 The Registrants use the liability method of accounting for deferred income taxes and provide deferred income taxes for all significant income tax temporary differences. In accordance with regulatory requirements, deferred federal ITCs for the traditional electric operating companies are amortized over the average life of the related property, with such amortization normally applied as a credit to reduce depreciation and amortization in the statements of income. Southern Power's and the natural gas distribution utilities' deferred federal ITCs, as well as certain state ITCs for Nicor Gas, are amortized to income tax expense over the life of the respective asset.
 Under current tax law, certain projects at Southern Power related to the construction of renewable facilities are eligible for federal ITCs. Southern Power estimates eligible costs which, as they relate to acquisitions, may not be finalized until the allocation of the purchase price to assets has been finalized. Southern Power applies the deferred method to ITCs, whereby the ITCs are recorded as a deferred credit and amortized to income tax expense over the life of the respective asset. Furthermore, the tax basis of the asset is reduced by 50 % of the ITCs received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. State ITCs are recognized as an income tax benefit in the period in which the credits are generated. In addition, certain projects are eligible for federal and state PTCs, which are recognized as an income tax benefit based on KWH production.
 II-125

 Federal ITCs and PTCs, as well as state ITCs and other state tax credits available to reduce income taxes payable, were not fully utilized in 2023 and will be carried forward and utilized in future years. In addition, Southern Company is expected to have various state net operating loss (NOL) carryforwards for certain of its subsidiaries, including Mississippi Power and Southern Power, which would result in income tax benefits in the future, if utilized. See Note 10 under "Current and Deferred Income Taxes – Tax Credit Carryforwards" and " – Net Operating Loss Carryforwards" for additional information.
 In June 2023, the IRS issued temporary regulations related to the transferability of certain tax credits under the IRA. Southern Company and certain subsidiaries have tax credits that are eligible to be transferred. The discount recorded on transferred credits is booked through income tax expense.
 Under current tax law, Georgia Power is eligible to generate advanced nuclear PTCs for Plant Vogtle Unit 3, which are recognized as an income tax benefit based on KWH production and are eligible to be transferred. Pursuant to the Global Amendments to the Vogtle Joint Ownership Agreements (as defined in Note 2 under "Georgia Power – Nuclear Construction – Joint Owner Contracts"), Georgia Power is purchasing advanced nuclear PTCs for Plant Vogtle Unit 3 from the other Vogtle Owners. The gain recognized on the purchase of the joint owner PTCs is recognized as an income tax benefit.
 The Registrants recognize tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 10 under "Unrecognized Tax Benefits" for additional information.
 Other Taxes
 Taxes imposed on and collected from customers on behalf of governmental agencies are presented net on the Registrants' statements of income and are excluded from the transaction price in determining the revenue related to contracts with a customer.
 Southern Company Gas is taxed on its gas revenues by various governmental authorities, but is allowed to recover these taxes from its customers. Revenue taxes imposed on the natural gas distribution utilities are recorded at the amount charged to customers, which may include a small administrative fee, as operating revenues, and the related taxes imposed on Southern Company Gas are recorded as operating expenses on the statements of income. Revenue taxes included in operating expenses were $ 129 million, $ 158 million, and $ 119 million in 2023, 2022, and 2021, respectively.
 Allowance for Funds Used During Construction and Interest Capitalized
 The traditional electric operating companies and the natural gas distribution utilities record AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the asset through a higher rate base and higher depreciation. The equity component of AFUDC is not taxable.
 Interest related to financing the construction of new facilities at Southern Power and new facilities not included in the traditional electric operating companies' and Southern Company Gas' regulated rates is capitalized in accordance with standard interest capitalization requirements.
 Total AFUDC and interest capitalized for the applicable Registrants in 2023, 2022, and 2021 was as follows:

Power
Power(*)

Power

 2023
 $
 $
 $
 $
 $

 2022
 —

 2021

 (*)See Note 2 under "Georgia Power – Nuclear Construction" for information on the inclusion of a portion of construction costs related to Plant Vogtle Unit 4 in Georgia Power's rate base.
 II-126

 The average AFUDC composite rates for 2023, 2022, and 2021 for the traditional electric operating companies and the natural gas distribution utilities were as follows:

 2023
 2022
 2021

 8.1
 %
 7.9
 %
 7.9
 %

 Georgia Power(a)

 7.6
 %
 7.3
 %
 7.2
 %

 Mississippi Power(b)

 —
 %
 5.3
 %
 2.5
 %

 7.4
 %
 7.6
 %
 7.7
 %

 7.1
 %
 7.1
 %
 7.1
 %

 4.6
 %
 2.0
 %
 0.1
 %

 (a)Excludes AFUDC related to the construction of Plant Vogtle Units 3 and 4. See Note 2 under "Georgia Power – Nuclear Construction" for additional information.
 (b)Mississippi Power's AFUDC was immaterial in 2023.
 Impairment of Long-Lived Assets
 The Registrants evaluate long-lived assets and finite-lived intangible assets for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance, a sales transaction price that is less than the asset group's carrying amount, or an estimate of undiscounted future cash flows attributable to the asset group, as compared with the carrying amount of the assets. If an impairment has occurred, the amount of the impairment loss recognized is determined by either the amount of regulatory disallowance or by the amount the carrying amount exceeds the estimated fair value of the assets. For assets identified as held for sale, the carrying amount is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. See Notes 7 and 9 under "Southern Company Gas" and "Southern Company Leveraged Lease," respectively, and Note 15 under "Southern Company" and "Southern Company Gas" for information regarding impairment charges recorded during the periods presented.
 Goodwill and Other Intangible Assets
 Southern Power's intangible assets consist primarily of certain PPAs acquired, which are amortized over the term of the respective PPA. Southern Company Gas' goodwill and other intangible assets primarily relate to its 2016 acquisition by Southern Company. In addition to these items, Southern Company's goodwill and other intangible assets also relate to its 2016 acquisition of PowerSecure.
 For its 2023 and 2022 annual impairment tests, Southern Company Gas management performed the qualitative assessment and determined that it was more likely than not that the fair value of all of its reporting units with goodwill exceeded their carrying amounts, and therefore no quantitative assessment was required. For its 2021 annual impairment test, Southern Company Gas management performed the quantitative assessment and confirmed that the fair values of all of its reporting units with goodwill exceeded their carrying amounts.
 For its 2023 and 2021 annual impairment tests, PowerSecure management performed the quantitative assessment, which resulted in the fair value of PowerSecure exceeding its carrying amount. For its 2022 annual impairment test, PowerSecure management performed the quantitative assessment, which resulted in the fair value of PowerSecure being lower than its carrying amount. The fair value was estimated using a discounted cash flow analysis. The decline in fair value primarily resulted from declining macroeconomic conditions, reducing sales growth and estimated cash flows. As a result, a goodwill impairment of $ 119 million was recorded in the fourth quarter 2022.
 II-127

 At December 31, 2023 and 2022, goodwill was as follows:

 $
 5,161
 $
 5,161

 Gas distribution operations
 $
 4,034
 $
 4,034

 Southern Company Gas total
 $
 5,015
 $
 5,015

 At December 31, 2023 and 2022, other intangible assets were as follows:

 Gross Carrying Amount
 Accumulated Amortization
 Other
Intangible Assets, Net
 Gross Carrying Amount
 Accumulated Amortization
 Other
Intangible Assets, Net

 Subject to amortization:

 Customer relationships
 $
 $
 ( 172)
 $
 $
 $
 ( 162)
 $

 Trade names
 ( 53)
 ( 44)

 PPA fair value adjustments
 ( 148)
 ( 129)

 Other
 ( 3)
 —
 ( 5)
 —

 Total subject to amortization
 $
 $
 ( 376)
 $
 $
 $
 ( 340)
 $

 Not subject to amortization:

 FCC licenses
 —
 —

 Total other intangible assets
 $
 $
 ( 376)
 $
 $
 $
 ( 340)
 $

 Southern Power(*)

 PPA fair value adjustments
 $
 $
 ( 148)
 $
 $
 $
 ( 129)
 $

 Southern Company Gas(*)

 Customer relationships
 $
 $
 ( 145)
 $
 $
 $
 ( 139)
 $

 Trade names
 ( 21)
 ( 17)

 Total other intangible assets
 $
 $
 ( 166)
 $
 $
 $
 ( 156)
 $

 (*)All subject to amortization.
 II-128

 Amortization associated with other intangible assets in 2023, 2022, and 2021 was as follows:

 2023
 2022
 2021

 Southern Company(a)

 $
 $
 $

 Southern Power(b)

 (a)Includes $ 20 million annually recorded as a reduction to operating revenues.
 (b)Recorded as a reduction to operating revenues.
 At December 31, 2023, the estimated amortization associated with other intangible assets for the next five years is as follows:

 2024
 2025
 2026
 2027
 2028

 $
 $
 $
 $
 $

 —
 —

 Acquisition Accounting
 At the time of an acquisition, management will assess whether acquired assets and activities meet the definition of a business. Acquisitions that meet the definition of a business are accounted for under the acquisition method, and operating results from the date of acquisition are included in the acquiring entity's financial statements. Identifiable assets acquired, liabilities assumed, and any noncontrolling interests (including any intangible assets) are recognized and measured at fair value. Assets acquired that do not meet the definition of a business are accounted for as an asset acquisition. The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired.
 Determining the fair value of assets acquired and liabilities assumed requires management judgment and management may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. For potential or successful acquisitions that meet the definition of a business, any due diligence or transaction costs incurred are expensed as incurred. If the acquisition is an asset acquisition, direct and incremental transaction costs can be capitalized as a component of the cost of the assets acquired.
 Historically, any contingent consideration relates to fixed amounts due to the seller once an acquired construction project is placed in service. For contingent consideration with variable payments, management fair values the arrangement with any changes recorded in the statements of income. See Note 13 for additional fair value information.
 Development Costs
 For Southern Power, development costs are capitalized once a project is probable of completion, primarily based on a review of its economics and operational feasibility, as well as the status of power off-take agreements and regulatory approvals, if applicable. Southern Power's capitalized development costs are included in CWIP on the balance sheets. All of Southern Power's development costs incurred prior to the determination that a project is probable of completion are expensed as incurred and included in other operations and maintenance expense in the statements of income. If it is determined that a project is no longer probable of completion, any of Southern Power's capitalized development costs are expensed and included in other operations and maintenance expense in the statements of income.
 Long-Term Service Agreements
 The traditional electric operating companies and Southern Power have entered into LTSAs for the purpose of securing maintenance support for certain of their generating facilities. The LTSAs cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. The LTSAs also obligate the counterparties to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in each contract.
 Payments made under the LTSAs for the performance of any planned inspections or unplanned capital maintenance are recorded in the statements of cash flows as investing activities. Receipts of major parts into materials and supplies inventory prior to planned inspections are treated as noncash transactions in the statements of cash flows. Any payments made prior to the work
 II-129

 being performed are recorded as prepayments in other current assets and noncurrent assets on the balance sheets. At the time work is performed, an appropriate amount is accrued for future payments or transferred from the prepayment and recorded as property, plant, and equipment or expensed.
 Transmission Receivables/Prepayments
 As a result of Southern Power's acquisition and construction of generating facilities, Southern Power has transmission receivables and/or prepayments representing the portion of interconnection network and transmission upgrades that will be reimbursed to Southern Power. Upon completion of the related project, transmission costs are generally reimbursed by the interconnection provider within a five-year period and the receivable/prepayments are reduced as payments or services are received.
 Cash, Cash Equivalents, and Restricted Cash
 For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
 The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets that total to the amount shown in the statements of cash flows for the applicable Registrants:

Power
Power
Company Gas

 $
 $
 $
 $
 $

 Restricted cash(a):

 —
 —

 Total cash, cash equivalents, and restricted cash(b)

 $
 $
 $
 $
 $

 $
 1,917
 $
 $
 $
 $

 Restricted cash(a):

 —
 —

 —
 —

 Total cash, cash equivalents, and restricted cash(b)

 $
 2,037
 $
 $
 $
 $

 (a)For Alabama Power, 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. See Note 8 under "Long-term Debt" for additional information. For Southern Power, reflects $ 17 million at December 31, 2023 resulting from an arbitration award held to fund future replacement costs and $ 3 million at both December 31, 2023 and 2022 held to fund estimated construction completion costs at the Deuel Harvest wind facility. See Note 3 under "General Litigation Matters – Southern Power" and Note 15 under "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.
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 Storm Damage and Reliability Reserves
 In accordance with their respective state PSC orders, the traditional electric operating companies accrue certain amounts annually related to storm damage recovery. Each traditional electric operating company maintains a reserve to cover or is allowed to defer and recover the cost of damages from major storms to its transmission and distribution lines and, for Mississippi Power, the cost of uninsured damages to its generation facilities and other property. Alabama Power also has authority from the Alabama PSC to accrue certain additional amounts as circumstances warrant. Alabama Power recorded an additional accrual of $ 65 million in 2021.
 Storm damage reserve activity for the traditional electric operating companies during 2023 was as follows:

Power

 $
 $
 $
 $

 Accrual

 Weather-related damages

 ( 211)
 ( 39)
 ( 168)
 ( 4)

 $
 $
 $
 ( 54)
 $

 The traditional electric operating companies accrued the following amounts related to storm damage recovery in 2022 and 2021:

 Company(a)(b)

Power(a)

Power
 Power(b)

 2022
 $
 $
 $
 $

 2021
 ( 2)

 (a)Alabama Power's 2021 amount includes the $ 65 million additional accrual discussed above.
 (b)Mississippi Power's net accrual includes carrying costs, as well as amortization of related excess deferred income tax benefits.
 In 2022, costs for weather-related damages charged against storm damage reserves totaled $ 24 million and $ 82 million for Alabama Power and Georgia Power, respectively, and were immaterial for Mississippi Power.
 See Note 2 under "Alabama Power – Rate NDR," "Georgia Power – Storm Damage Recovery," and "Mississippi Power – System Restoration Rider" for additional information regarding each company's storm damage reserve.
 During 2022, the Alabama PSC and the Mississippi PSC authorized Alabama Power and Mississippi Power, respectively, to make accruals to a reliability reserve if certain conditions are met. During 2023 and 2022, Alabama Power and Mississippi Power accrued the following amounts to their reliability reserves:

Power
Power

 2023
 $
 $
 $

 2022

 See Note 2 under "Alabama Power – Reliability Reserve Accounting Order" and "Mississippi Power – Reliability Reserve Accounting Order" for additional information.
 Materials and Supplies
 Materials and supplies for the traditional electric operating companies generally includes the average cost of transmission, distribution, and generating plant materials. Materials and supplies for Southern Company Gas generally includes propane gas inventory, liquefied natural gas inventory, fleet fuel, and other materials and supplies. Materials and supplies for Southern Power generally includes the average cost of generating plant materials.
 Materials are recorded to inventory when purchased and then expensed or capitalized to property, plant, and equipment, as appropriate, at weighted average cost when installed. In addition, certain major parts are recorded as inventory when acquired and then capitalized at cost when installed to property, plant, and equipment.
 II-131

 Fuel Inventory
 Fuel inventory for the traditional electric operating companies includes the average cost of coal, natural gas, oil, transportation, and emissions allowances. Fuel inventory for Southern Power, which is included in other current assets, includes the average cost of oil, natural gas, and emissions allowances. Fuel is recorded to inventory when purchased and then expensed, at weighted average cost, as used. Emissions allowances granted by the EPA are included in inventory at zero cost. The traditional electric operating companies recover fuel expense through fuel cost recovery rates approved by each state PSC or, for wholesale rates, the FERC.

 Natural Gas for Sale
 With the exception of Nicor Gas, Southern Company Gas records natural gas inventories on a weighted average cost of gas basis. In Georgia's deregulated, competitive environment, Marketers sell natural gas to firm end-use customers at market-based prices. On a monthly basis, Atlanta Gas Light assigns to Marketers the majority of the pipeline storage services that it has under contract, along with a corresponding amount of inventory. Atlanta Gas Light retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand.
 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. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's or Southern Company Gas' net income. At December 31, 2023, the Nicor Gas LIFO inventory balance was $ 186 million. Based on the average cost of gas purchased in December 2023, the estimated replacement cost of Nicor Gas' inventory at December 31, 2023 was $ 268 million.

 Provision for Uncollectible Accounts
 The customers of the traditional electric operating companies and the natural gas distribution utilities are billed monthly. For the majority of receivables, a provision for uncollectible accounts is established based on historical collection experience and other factors. For the remaining receivables, if the company is aware of a specific customer's inability to pay, a provision for uncollectible accounts is recorded to reduce the receivable balance to the amount reasonably expected to be collected. If circumstances change, the estimate of the recoverability of accounts receivable could change as well. Circumstances that could affect this estimate include, but are not limited to, customer credit issues, customer deposits, and general economic conditions. Customers' accounts are written off once they are deemed to be uncollectible. For all periods presented, uncollectible accounts averaged less than 1 % of revenues for each Registrant.
 Credit risk exposure at Nicor Gas is mitigated by a bad debt rider approved by the Illinois Commission. The bad debt rider provides for the recovery from (or refund to) customers of the difference between Nicor Gas' actual bad debt experience on an annual basis and the benchmark bad debt expense used to establish its base rates for the respective year.

 Concentration of Credit Risk
 Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 13 Marketers in Georgia (including SouthStar). The credit risk exposure to the Marketers varies seasonally, with the lowest exposure in the non-peak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. The functions of the retail sale of gas include the purchase and sale of natural gas, customer service, billings, and collections. The provisions of Atlanta Gas Light's tariff allow Atlanta Gas Light to obtain credit security support in an amount equal to a minimum of two times a Marketer's highest month's estimated bill from Atlanta Gas Light.

 Financial Instruments
 The traditional electric operating companies and Southern Power use derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. Southern Company Gas uses derivative financial instruments to limit exposure to fluctuations in natural gas prices, weather, interest rates, and commodity prices. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 13 for additional information regarding fair value. Substantially all of the traditional electric operating companies' and Southern Power's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the
 II-132

 traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs result in the deferral of related gains and losses in AOCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. Cash flows from derivatives are classified on the statements of cash flows in the same category as the hedged item. See Note 14 for additional information regarding derivatives.
 The Registrants offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under netting arrangements. The Registrants had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2023.
 The Registrants are exposed to potential losses related to financial instruments in the event of counterparties' nonperformance. The Registrants have 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 enters into weather derivative contracts as economic hedges of natural gas revenues in the event of warmer-than-normal weather in the Heating Season. Exchange-traded options are carried at fair value, with changes reflected in natural gas revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are also reflected in natural gas revenues in the statements of income.
 Southern Company Gas enters into transactions to secure transportation capacity between delivery points in order to serve its customers and various markets. NYMEX futures and OTC contracts are used to capture the price differential or spread between the locations served by the capacity to substantially protect the natural gas revenues that will ultimately be realized when the physical flow of natural gas between delivery points occurs. These contracts generally meet the definition of derivatives and are carried at fair value on the balance sheets, with changes in fair value included in earnings in the period of change. These contracts are not designated as hedges for accounting purposes.
 The purchase, transportation, storage, and sale of natural gas are accounted for on a weighted average cost or accrual basis, as appropriate, rather than on the fair value basis utilized for the derivatives used to mitigate the natural gas price risk associated with the storage and transportation portfolio. Monthly demand charges are incurred for the contracted storage and transportation capacity and payments associated with asset management agreements, and these demand charges and payments are recognized on the statements of income in the period they are incurred. This difference in accounting methods can result in volatility in reported earnings, even though the economic margin is substantially unchanged from the dates the transactions were consummated.

 The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income attributable to the Registrant, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income. Comprehensive income also consists of certain changes in pension and other postretirement benefit plans for Southern Company, Southern Power, and Southern Company Gas.
 II-133

 AOCI (loss) balances, net of tax effects, for Southern Company, Southern Power, and Southern Company Gas were as follows:

 Qualifying
Hedges
 Pension and Other
Postretirement
Benefit Plans
 Accumulated Other
 Comprehensive
 Income (Loss)(*)

 $
 ( 149)
 $
 ( 18)
 $
 ( 167)

 Current period change
 ( 38)
 ( 10)

 $
 ( 121)
 $
 ( 56)
 $
 ( 177)

 $
 ( 9)
 $
 ( 9)
 $
 ( 18)

 Current period change
 ( 7)

 $
 ( 1)
 $
 ( 16)
 $
 ( 17)

 $
 ( 25)
 $
 $

 Current period change
 ( 16)
 ( 15)

 $
 ( 24)
 $
 $

 (*)May not add due to rounding.
 Variable Interest Entities
 The Registrants may hold ownership interests in a number of business ventures with varying ownership structures. Partnership interests and other variable interests are evaluated to determine if each entity is a VIE. The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. See Note 7 for additional information regarding VIEs.
 II-134

 2. REGULATORY MATTERS

 Regulatory Assets and Liabilities
 Details of regulatory assets and (liabilities) reflected in the balance sheets at December 31, 2023 and 2022 are provided in the following tables:

 AROs(a)(w)

 $
 5,733
 $
 1,936
 $
 3,505
 $
 $
 —

 Retiree benefit plans(b)(w)

 3,011

 Remaining net book value of retired assets(c)

 1,357
 —

 Deferred income tax charges(d)

 —

 Under recovered regulatory clause revenues(e)

 —

 Fuel-hedging (realized and unrealized) losses(f)

 —

 Deferred depreciation(g)

 —
 —

 Environmental remediation(h)(w)

 —
 —

 Loss on reacquired debt(i)

 Vacation pay(j)(w)

 Software and cloud computing costs(k)

 Regulatory clauses(l)

 —
 —

 Storm damage(m)

 —
 —

 Nuclear outage(n)

 —
 —

 Long-term debt fair value adjustment(o)

 —
 —
 —

 Qualifying repairs of natural gas distribution systems(p)

 —
 —
 —

 Plant Daniel Units 3 and 4(q)

 —
 —
 —

 Kemper County energy facility assets, net(r)

 —
 —
 —

 Other regulatory assets(s)

 Deferred income tax credits(d)

 ( 4,686)
 ( 1,506)
 ( 2,161)
 ( 241)
 ( 759)

 Other cost of removal obligations(a)

 ( 1,312)
 ( 186)
 ( 1,771)

 Over recovered regulatory clause revenues(e)

 ( 287)
 ( 3)
 ( 46)
 —
 ( 238)

 Reliability reserves(t)

 ( 179)
 ( 143)
 —
 ( 36)
 —

 Storm/property damage reserves(t)

 ( 120)
 ( 76)
 —
 ( 44)
 —

 Customer refunds(u)

 ( 19)
 ( 15)
 ( 4)
 —
 —

 Fuel-hedging (realized and unrealized) gains(f)

 ( 6)
 ( 5)
 ( 1)

 —

 Other regulatory liabilities(v)

 ( 308)
 ( 74)
 ( 18)
 ( 2)
 ( 101)

 Total regulatory assets (liabilities), net
 $
 6,523
 $
 2,720
 $
 5,090
 $
 $
 ( 2,225)

 II-135

 AROs(a)(w)

 $
 6,096
 $
 1,971
 $
 3,829
 $
 $
 —

 Retiree benefit plans(b)(w)

 2,517

 Remaining net book value of retired assets(c)

 1,543
 —

 Under recovered regulatory clause revenues(e)

 —

 Deferred income tax charges(d)

 —

 Environmental remediation(h)(w)

 —
 —

 Loss on reacquired debt(i)

 Vacation pay(j)(w)

 Regulatory clauses(l)

 —
 —
 —

 Software and cloud computing costs(k)

 —

 Nuclear outage(n)

 —
 —

 Long-term debt fair value adjustment(o)

 —
 —
 —

 Fuel-hedging (realized and unrealized) losses(f)

 —
 —

 Storm damage(m)

 —
 —
 —

 Plant Daniel Units 3 and 4(q)

 —
 —
 —

 Qualifying repairs of natural gas distribution systems(p)

 —
 —
 —

 Kemper County energy facility assets, net(r)

 —
 —
 —

 Other regulatory assets(s)

 Deferred income tax credits(d)

 ( 5,251)
 ( 1,925)
 ( 2,244)
 ( 269)
 ( 788)

 Other cost of removal obligations(a)

 ( 1,430)
 ( 196)
 ( 1,707)

 Storm/property damage reserves(t)

 ( 216)
 ( 97)
 ( 83)
 ( 36)
 —

 Reliability reserves(t)

 ( 191)
 ( 166)
 —
 ( 25)
 —

 Customer refunds(u)

 ( 183)
 ( 62)
 ( 121)
 —
 —

 Fuel-hedging (realized and unrealized) gains(f)

 ( 83)
 ( 38)
 ( 21)
 ( 24)
 —

 Over recovered regulatory clause revenues(e)

 ( 64)
 —
 ( 38)
 —
 ( 26)

 Other regulatory liabilities(v)

 ( 239)
 ( 40)
 ( 21)
 ( 3)
 ( 93)

 Total regulatory assets (liabilities), net
 $
 5,833
 $
 2,340
 $
 4,663
 $
 $
 ( 1,891)

 Unless otherwise noted, the following recovery and amortization periods for these regulatory assets and (liabilities) have been approved by the respective state PSC or regulatory agency:
 (a)AROs and other cost of removal obligations generally are recorded over the related property lives, which may range up to 64 years for Alabama Power, 56 years for Georgia Power, 55 years for Mississippi Power, and 85 years for Southern Company Gas. AROs and cost of removal obligations are settled and trued up following completion of the related activities. Alabama Power is recovering CCR ARO expenditures over a 38-year period ending in 2054 through Rate CNP Compliance. Effective January 1, 2023, Georgia Power is recovering CCR ARO expenditures over four-year periods through its ECCR tariff. Prior to 2023, expenditures were recovered over three-year periods. See "Georgia Power – Rate Plans" herein and Note 6 for additional information.
 (b)Recovered and amortized over the average remaining service period, which may range up to 13 years for Alabama Power and Mississippi Power and up to 14 years for Georgia Power and Southern Company Gas. Southern Company's balances also include amounts at SCS and Southern Nuclear that are allocated to the applicable regulated utilities. See Note 11 for additional information.
 (c)Alabama Power: Primarily represents the net book value of Plant Gorgas Unit 10 ($ 451 million at December 31, 2023) being amortized over 14 years (through 2037) and Plant Barry Unit 4 ($ 39 million at December 31, 2023) being amortized over 11 years (through 2034). See "Alabama Power – Environmental Accounting Order" herein for additional information.
 Georgia Power: Net book values of Plant Wansley Units 1 and 2, Plant Hammond Units 1 through 4, and Plant Branch Unit 4 (totaling $ 488 million, $ 339 million, and $ 8 million, respectively, at December 31, 2023) are being amortized over remaining periods between one and 12 years (between 2024 and 2035). Balance also includes unusable materials and supplies inventories, for which the Georgia PSC will determine a recovery period in a future base rate case.
 Mississippi Power: Represents net book value of certain environmental compliance assets at Plant Watson and Plant Greene County. The retail portion is being amortized over a 10-year period through 2030 and the wholesale portion is being amortized over a 14-year period through 2035. See "Mississippi Power – Environmental Compliance Overview Plan" herein for additional information.
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 (d)Deferred income tax charges are recovered and deferred income tax credits are primarily amortized over the related property lives, which may range up to 64 years for Alabama Power, 56 years for Georgia Power, 55 years for Mississippi Power, and 85 years for Southern Company Gas. See Note 10 for additional information. As a result of the Tax Reform Legislation, these accounts include certain deferred income tax assets and liabilities not subject to normalization, as described further below:
 Alabama Power: Related amounts at December 31, 2023 include excess federal deferred income tax liabilities that are available for the benefit of customers in 2024 and/or 2025, as discussed under "Alabama Power – Excess Accumulated Deferred Income Tax Accounting Order" herein. Remaining amounts are being recovered and amortized ratably over the related property lives.
 Georgia Power: Related amounts include $ 145 million of deferred income tax assets related to construction costs for Plant Vogtle Units 3 and 4 to be recovered over a 10-year period beginning the month after Unit 4 achieves commercial operation. See "Georgia Power – Nuclear Construction – Regulatory Matters" herein for additional information on recovery of costs related to Plant Vogtle Units 3 and 4.
 Mississippi Power: Related amounts include retail deferred income tax liabilities ($ 11 million at December 31, 2023) that are expected to be fully amortized through 2024.
 Southern Company Gas: Related amounts include deferred income tax liabilities ($ 1 million at December 31, 2023) being amortized through 2024. See "Southern Company Gas – Rate Proceedings" herein for additional information.
 (e)Alabama Power: Balances are recorded monthly and expected to be recovered over periods of up to seven years, with the majority expected to be recovered within one year. See "Alabama Power – Rate CNP PPA," " – Rate CNP Compliance," and " – Rate ECR" herein for additional information.
 Georgia Power: Balances are recorded monthly and expected to be recovered or returned within two years. See "Georgia Power – Rate Plans" herein for additional information.
 Mississippi Power: At December 31, 2023, $ 12 million is expected to be recovered through various rate recovery mechanisms over a period to be determined in future rate filings. See "Mississippi Power – Ad Valorem Tax Adjustment" herein for additional information.
 Southern Company Gas: Balances are recorded and recovered or amortized over periods generally not exceeding five years. In addition to natural gas cost recovery mechanisms, the natural gas distribution utilities have various other cost recovery mechanisms for the recovery of costs, including those related to infrastructure replacement programs.
 (f)Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts. Upon final settlement, actual costs incurred are recovered through the applicable traditional electric operating company's fuel cost recovery mechanism. Purchase contracts generally do not exceed three and a half years for Alabama Power, three years for Georgia Power, and four years for Mississippi Power.
 (g)Alabama Power: Represents deferred depreciation expense for Plant Barry Unit 5 ($ 57 million at December 31, 2023) and Plant Barry common coal assets ($ 24 million at December 31, 2023) to be amortized until 2036 beginning when Plant Barry Unit 5 is retired and Plant Gaston Unit 5 coal assets ($ 62 million at December 31, 2023) to be amortized until 2039 beginning when the assets are retired.
 Georgia Power: Represents deferred depreciation expense for Plant Scherer Units 1 through 3 ($ 70 million at December 31, 2023) to be amortized over six years beginning in 2029 and Plant Bowen Units 1 and 2 ($ 40 million at December 31, 2023) to be amortized over four years beginning in 2031, both as approved under Georgia Power's 2022 ARP, and Plant Vogtle Unit 3 and common facilities ($ 17 million at December 31, 2023) to be amortized over a 10-year period beginning the month after Plant Vogtle Unit 4 achieves commercial operation. See "Georgia Power – Nuclear Construction – Regulatory Matters" herein for additional information on recovery of costs related to Plant Vogtle Units 3 and 4.
 (h)Effective January 1, 2023, Georgia Power is recovering $ 5 million annually for environmental remediation under the 2022 ARP. Southern Company Gas' costs are recovered through environmental cost recovery mechanisms when the remediation work is performed. See Note 3 under "Environmental Remediation" for additional information.
 (i)Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue. At December 31, 2023, the remaining amortization periods do not exceed 24 years for Alabama Power, 29 years for Georgia Power, 18 years for Mississippi Power, and four years for Southern Company Gas.
 (j)Recorded as earned by employees and recovered as paid, generally within one year. Includes both vacation and banked holiday pay, if applicable.
 (k)Represents certain deferred operations and maintenance costs associated with software and cloud computing projects. For Alabama Power, costs are amortized ratably over the life of the related software, which ranges up to 10 years (through 2034). See "Alabama Power – Software Accounting Order" herein for additional information. For Georgia Power, costs incurred through 2022 are being amortized over five years (through 2027) and the recovery period for costs incurred after 2022 will be determined in its next base rate case. For Mississippi Power, the recovery period will be determined in Mississippi Power's annual PEP filing process. For Southern Company Gas, costs are being amortized ratably over the life of the related software, which ranges up to 10 years (through 2034).
 (l)Alabama Power: Effective January 1, 2023, balance is being amortized through Rate RSE over a five-year period ending in 2027.
 Southern Company Gas: Represents amounts related to Nicor Gas' volume balancing adjustment rider expected to be recovered over a period of less than two years.
 (m)See "Georgia Power – Storm Damage Recovery" herein and Note 1 under "Storm Damage and Reliability Reserves" for additional information. Mississippi Power's balance represents deferred storm costs associated with Hurricanes Ida and Zeta being recovered through PEP over a seven-year period through 2029.
 (n)Nuclear outage costs are deferred to a regulatory asset when incurred and amortized over a subsequent period of 18 months for Alabama Power and up to 24 months for Georgia Power. See Note 5 for additional information.
 (o)Recovered over the remaining lives of the original debt issuances at acquisition, which range up to 15 years at December 31, 2023.
 (p)Represents deferred costs of certain repairs at Atlanta Gas Light being amortized over 20 years.
 (q)Represents the difference between Mississippi Power's revenue requirement for Plant Daniel Units 3 and 4 under purchase accounting and operating lease accounting. At December 31, 2023, consists of the $ 17 million retail portion being amortized through 2039 over the remaining life of the related property and the $ 8 million wholesale portion being amortized through 2035.
 (r)At December 31, 2023, includes $ 9 million of regulatory assets (wholesale) expected to be fully amortized by 2035 and $ 2 million of regulatory liabilities (retail) expected to be fully amortized by 2024.
 (s)Comprised of numerous immaterial components with remaining amortization periods at December 31, 2023 generally not exceeding 20 years for Alabama Power, 10 years for Georgia Power, 14 years for Mississippi Power, and 15 years for Southern Company Gas.
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 (t)Utilized as related expenses are incurred. See "Alabama Power – Rate NDR" and " – Reliability Reserve Accounting Order," "Georgia Power – Storm Damage Recovery," and "Mississippi Power – System Restoration Rider" and " – Reliability Reserve Accounting Order" herein and Note 1 under "Storm Damage and Reliability Reserves" for additional information.
 (u)Primarily includes approximately $ 15 million and $ 62 million at December 31, 2023 and 2022, respectively, for Alabama Power and $ 119 million at December 31, 2022 for Georgia Power as a result of each company exceeding its allowed retail return range. Georgia Power's balances also include immaterial amounts related to refunds for transmission service customers. See "Alabama Power – Rate RSE" and "Georgia Power – Rate Plans" herein for additional information.
 (v)Comprised of numerous immaterial components with remaining amortization periods at December 31, 2023 generally not exceeding 11 years for Alabama Power, nine years for Georgia Power, four years for Mississippi Power, and 20 years for Southern Company Gas.
 (w)Generally not earning a return as they are excluded from rate base or are offset in rate base by a corresponding asset or liability.

 Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power.
 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.
 Rate RSE
 The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon Alabama Power's projected weighted common equity return (WCER) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate RSE adjustments for any two-year period, when averaged together, cannot exceed 4.0 % and any annual adjustment is limited to 5.0 %. When the projected WCER is under the allowed range, there is an adjusting point of 5.98 % and eligibility for a performance-based adder of seven basis points, or 0.07 %, to the WCER adjusting point if Alabama Power (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey.
 Alabama Power continues to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is to achieve an equity ratio of approximately 55 % by the end of 2025. At December 31, 2023 and 2022, Alabama Power's equity ratio was approximately 52.3 % and 52.2 %, respectively.
 Generally, during a year without a Rate RSE upward adjustment, if Alabama Power's actual WCER is between 6.15 % and 7.65 %, customers will receive 25 % of the amount between 6.15 % and 6.65 %, 40 % of the amount between 6.65 % and 7.15 %, and 75 % of the amount between 7.15 % and 7.65 %. Customers will receive all amounts in excess of an actual WCER of 7.65 %. During a year with a Rate RSE upward adjustment, if Alabama Power's actual WCER exceeds 6.15 %, customers receive 50 % of the amount between 6.15 % and 6.90 % and all amounts in excess of an actual WCER of 6.90 %. Alabama Power's ability to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range positions Alabama Power to address the pressure on its credit quality, without increasing retail rates under Rate RSE in the near term. There is no provision for additional customer billings should the actual retail return fall below the WCER range.
 Retail rates under Rate RSE did not change for 2022 or 2023.
 For the years ended December 31, 2021, 2022, and 2023, Alabama Power's WCER exceeded 6.15 %, resulting in Alabama Power establishing a current regulatory liability of $ 181 million, $ 62 million, and $ 15 million, respectively, for Rate RSE refunds. In accordance with an Alabama PSC order issued in February 2022, Alabama Power applied $ 126 million of the 2021 refund to reduce the Rate ECR under recovered balance and the remaining $ 55 million was refunded to customers through bill credits in July 2022. In accordance with an Alabama PSC order issued on February 7, 2023, Alabama Power refunded the 2022 amount to customers through bill credits in August 2023. The $ 15 million regulatory liability at December 31, 2023 will be refunded to customers through bill credits in April 2024.
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 On December 1, 2023, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2024. Projected earnings were within the specified range; therefore, retail rates under Rate RSE remain unchanged for 2024.
 Excess Accumulated Deferred Income Tax Accounting Order
 In December 2022, the Alabama PSC directed Alabama Power to accelerate the amortization of a regulatory liability associated with excess federal accumulated deferred income taxes. Under this order, in 2023, approximately $ 304 million was returned to customers through bill credits to offset the impact of the rate increase discussed under "Rate CNP Depreciation" herein.
 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. At December 31, 2023, the remaining balance was $ 81 million, of which approximately $ 67 million and $ 14 million will flow back in 2024 and 2025, respectively, for the benefit of customers.
 Rate CNP New Plant
 Rate CNP New Plant allows for recovery of Alabama Power's retail costs associated with newly developed or acquired certificated generating facilities placed into retail service. No adjustments to Rate CNP New Plant occurred during the period January 2021 through October 2022.
 In July 2022, the Alabama PSC approved a CCN authorizing Alabama Power to complete the acquisition of the Calhoun Generating Station. The transaction closed in September 2022 and, in October 2022, Alabama Power filed Rate CNP New Plant with the Alabama PSC to recover the related costs. The filing reflected an increase in annual revenues of $ 34 million, or 0.6 %, effective with November 2022 billings.
 In 2020, the Alabama PSC approved a CCN authorizing Alabama Power to complete the acquisition of the Central Alabama Generating Station, which occurred in August 2020. 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. Beginning in July 2022, fuel costs associated with Central Alabama Generating Station are being recovered through Rate ECR. 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, or 1.1 %, effective with June 2023 billings. On May 24, 2023, the Central Alabama Generating Station was placed into retail service.
 The Alabama PSC's 2020 CCN also authorized Alabama Power to construct an approximately 720 -MW combined cycle facility at Alabama Power's Plant Barry (Plant Barry Unit 8) and the recovery of estimated in-service costs. On November 1, 2023, the unit was placed in service. On December 1, 2023, Alabama Power filed Rate CNP New Plant with the Alabama PSC to recover the related costs. The filing reflected an annual increase in retail revenues of $ 91 million, or 1.4 %, effective with January 2024 billings.
 Rate CNP PPA
 Rate CNP PPA allows for the recovery of Alabama Power's retail costs associated with certificated PPAs. Revenues for Rate CNP PPA, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factors will have no significant effect on Southern Company's or Alabama Power's revenues or net income but will affect annual cash flow. No adjustments to Rate CNP PPA occurred during the period 2021 through 2023 and no adjustment is expected for 2024. At December 31, 2023 and 2022, Alabama Power had an under recovered Rate CNP PPA balance of $ 103 million and $ 120 million, respectively, of which $ 18 million and $ 18 million, respectively, is included in other regulatory assets, current and $ 85 million and $ 102 million, respectively, is included in other regulatory assets, deferred on the balance sheet.
 Rate CNP Compliance
 Rate CNP Compliance allows for the recovery of Alabama Power's retail costs associated with laws, regulations, and other such mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to factors that are calculated and submitted to the Alabama PSC by December 1 with rates effective for the following calendar year. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Revenues for Rate CNP Compliance, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factors will have no significant effect on Southern Company's or Alabama Power's revenues
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 or net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income.
 In November 2021, December 2022, and December 2023, Alabama Power submitted calculations to the Alabama PSC associated with its cost of complying with governmental mandates for the following calendar year, as provided under Rate CNP Compliance. The 2021 filing reflected a projected under recovered retail revenue requirement of approximately $ 59 million. In December 2021, the Alabama PSC issued a consent order that Alabama Power leave the 2021 Rate CNP Compliance factors in effect for 2022, with any prior year under collected amount deemed recovered before any current year amounts are recovered and any remaining under recovery reflected in the 2022 filing. The 2022 filing reflected a $ 255 million, or 3.7 %, annual increase effective with January 2023 billings, primarily due to updated depreciation rates. The 2023 filing reflected a $ 23 million, or 0.3 %, annual decrease effective with January 2024 billings.
 At December 31, 2023, Alabama Power had an under recovered Rate CNP Compliance balance of $ 33 million, of which $ 8 million is included in other regulatory assets, current and $ 25 million is included in other regulatory assets, deferred on the balances sheet, compared to an under recovered balance at December 31, 2022 of $ 47 million included in other regulatory assets, current on the balance sheet.
 Rate CNP Depreciation
 In December 2022, the Alabama PSC approved Rate CNP Depreciation, which allows Alabama Power to recover changes in depreciation resulting from updates to certain depreciation rates, excluding any depreciation recovered through Rate CNP New Plant, Rate CNP Compliance, or costs associated with the capitalization of asset retirement costs. Rate CNP Depreciation resulted in an annual revenue increase of approximately $ 318 million, or 4.6 %, effective with January 2023 billings. See "Excess Accumulated Deferred Income Tax Accounting Order" herein for information related to 2023 customer bill credits approved by the Alabama PSC.
 Rate ECR
 Rate ECR recovers Alabama Power's retail energy costs based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed gives rise to the over or under recovered amounts recorded as regulatory assets or liabilities. Alabama Power, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on Southern Company's or Alabama Power's net income but will impact the related operating cash flows. The Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH.
 The Alabama PSC approved adjustments to Rate ECR from 1.960 cents per KWH to 2.557 cents per KWH, or approximately $ 310 million annually, effective with August 2022 billings and from 2.557 cents per KWH to 3.510 cents per KWH, or approximately $ 500 million annually, effective with December 2022 billings. On November 9, 2023, the Alabama PSC approved a decrease to Rate ECR from 3.510 cents per KWH to 3.270 cents per KWH, or approximately $ 126 million annually, effective with December 2023 billings. The rate will adjust to 5.910 cents per KWH in January 2025 absent a further order from the Alabama PSC.
 At December 31, 2023 and 2022, Alabama Power's under recovered fuel costs totaled $ 246 million and $ 622 million, respectively, of which $ 246 million and $ 102 million, respectively, is included in regulatory assets – under recovered retail fuel clause revenues and $ 520 million of the December 31, 2022 balance is included in other regulatory assets, deferred on the balance sheets. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a significant impact on the timing of any recovery or return of fuel costs.
 Software Accounting Order
 The Alabama PSC authorizes Alabama Power to establish a regulatory asset for operations and maintenance costs associated with software implementation projects. The regulatory asset is amortized ratably over the life of the related software. At December 31, 2023 and 2022, the regulatory asset balance totaled $ 59 million and $ 46 million, respectively, and is included in other regulatory assets, deferred on the balance sheet.
 Plant Greene County
 Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 5 under "Joint Ownership Agreements" for additional information. In 2021, the Mississippi PSC concluded its review of Mississippi Power's 2021 IRP,
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 which included a schedule to retire Mississippi Power's 40 % ownership interest in Plant Greene County Units 1 and 2 in December 2025 and 2026, respectively, consistent with each unit's remaining useful life. Alabama Power and Mississippi Power have continued to evaluate operating conditions and business needs relevant to the anticipated retirement of Plant Greene County and now expect the units to remain in service beyond the previously indicated dates. The Plant Greene County unit retirements require the completion by Alabama Power of transmission and system reliability improvements, as well as agreement by Alabama Power. The ultimate outcome of this matter cannot be determined at this time. See "Mississippi Power – Integrated Resource Plan" herein for additional information.
 Rate NDR
 Based on an order from the Alabama PSC, Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. When the reserve balance falls below $ 50 million, a reserve establishment charge will be activated (and the on-going reserve maintenance charge concurrently suspended) until the reserve balance reaches $ 75 million.
 The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 48-month period ( 24-month period prior to modifications approved by the Alabama PSC in July 2022). The Alabama PSC order gives Alabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. The maximum total Rate NDR charge was limited to $ 10.00 per month per non-residential customer account and $ 5.00 per month per residential customer account through July 12, 2022. Subsequently, modifications approved by the Alabama PSC replaced the maximum total Rate NDR charge with a maximum charge to recover a deficit of $ 5 per month per non-residential customer account and $ 2.50 per month per residential customer account. Alabama Power has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant, which can be used to offset storm charges. Alabama Power made an additional accrual of $ 65 million in 2021.
 Alabama Power collected approximately $ 12 million, $ 14 million, and $ 6 million in 2023, 2022, and 2021, respectively, under Rate NDR. Beginning with August 2022 billings, the reserve establishment charge was suspended and the reserve maintenance charge was activated as a result of the NDR balance exceeding $ 75 million. Alabama Power expects to collect approximately $ 12 million annually under Rate NDR unless the NDR balance falls below $ 50 million. At December 31, 2023 and 2022, the NDR balance was $ 76 million and $ 97 million, respectively, and is included in other regulatory liabilities, deferred on the balance sheets.
 As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows.
 Reliability Reserve Accounting Order
 In July 2022, the Alabama PSC approved an accounting order authorizing Alabama Power to create a reliability reserve separate from the NDR and transition the previous Rate NDR authority related to reliability expenditures to the reliability reserve. Alabama Power may make accruals to the reliability reserve if the NDR balance exceeds $ 35 million. At December 31, 2023 and 2022, Alabama Power accrued $ 52 million and $ 166 million, respectively, to the reserve.
 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 reliability reserve balance in 2023. During the fourth quarter 2023, Alabama Power used $ 75 million of the reliability reserve for reliability-related transmission, distribution, and generation expenses and nuclear production-related expenses.
 At December 31, 2023 and 2022, Alabama Power's reliability reserve balance was $ 143 million and $ 166 million, respectively, and is included in other regulatory liabilities, deferred on the balance sheets.
 Environmental Accounting Order
 Based on an order from the Alabama PSC (Environmental Accounting Order), Alabama Power is authorized to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. The
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 regulatory asset is amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement, through Rate CNP Compliance.
 With the completion of the Calhoun Generating Station acquisition, Alabama Power expected to retire Plant Barry Unit 5 in late 2023 or early 2024, subject to certain operating conditions. In September 2022, Alabama Power reclassified approximately $ 600 million for Plant Barry Unit 5 from plant in service, net of depreciation to other utility plant, net and will continue to depreciate the asset according to the original depreciation rates. Alabama Power has continued to evaluate operating conditions relevant to the expected retirement of Plant Barry Unit 5 and now expects to retire the unit on or before December 31, 2028. At retirement, Alabama Power will reclassify the remaining net investment costs of the unit to a regulatory asset to be recovered over the unit's remaining useful life, as established prior to the decision to retire, through Rate CNP Compliance. See "Rate CNP New Plant" herein for additional information.
 In December 2022, in conjunction with Alabama Power's compliance plan for the EPA's final steam electric ELG reconsideration rule, Plant Barry Unit 4 ceased using coal and began operating solely on natural gas. As a result, approximately $ 42 million of plant in service, net of depreciation was reclassified to a regulatory asset to be recovered through Rate CNP Compliance through 2034, the unit's remaining useful life.

 Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power recovers its costs from the regulated retail business through traditional base tariffs, Demand-Side Management (DSM) tariffs, the ECCR tariff, and Municipal Franchise Fee (MFF) tariffs. These tariffs were set under the 2019 ARP for the years 2020 through 2022 and under the 2022 ARP for the years 2023 through 2025 as described herein. In addition, fuel costs are collected through a separate fuel cost recovery tariff.
 See "Nuclear Construction – Regulatory Matters" herein for information regarding the approved recovery through retail base rates of certain costs related to Plant Vogtle Unit 3 and the common facilities shared between Plant Vogtle Units 3 and 4 (Common Facilities) that became effective August 1, 2023 based on the in-service date of July 31, 2023 for Unit 3, as well as the base rate adjustments that will occur the first day of the month after Unit 4 achieves commercial operation. Financing costs on certified construction costs of Plant Vogtle Units 3 and 4 that are not included in rate base are being collected through Georgia Power's NCCR tariff. When the base rate adjustments occur following commercial operation of Unit 4, the NCCR tariff will cease to be collected and financing costs will be included in Georgia Power's general retail revenue requirements. See "Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.
 Rate Plans
 2022 ARP
 In December 2022, the Georgia PSC voted to approve the 2022 ARP, under which Georgia Power increased its rates on January 1, 2023. On November 16, 2023, the Georgia PSC approved tariff adjustments effective January 1, 2024. Details of tariff adjustments are provided in the following table:

 Tariff
 2023
 2024

 Traditional base
 $
 $

 ECCR
 ( 21)
 ( 99)

 DSM

 MFF

 Total
 $
 $

 Under the 2022 ARP, Georgia Power will adjust traditional base, ECCR, DSM, and MFF rates effective January 1, 2025, with the incremental revenue requirements related to DSM tariffs and CCR AROs subject to updates through annual compliance filings to be made at least 90 days prior to the effective date.
 In the 2022 ARP, the Georgia PSC approved recovery through the ECCR tariff of estimated CCR ARO compliance costs for 2023, 2024, and 2025 over four-year periods beginning January 1 of each respective year, with recovery of construction contingency beginning in the year following actual expenditures, resulting in $ 60 million and $ 20 million reductions in the related amortization expense for 2024 and 2023, respectively. Compliance costs incurred were $ 300 million in 2023 and are expected to be $ 305 million and $ 330 million in 2024 and 2025, respectively. The CCR ARO costs are expected to be revised for actual expenditures and updated estimates through future annual compliance filings.
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 Further, under the 2022 ARP, Georgia Power's retail ROE is set at 10.50 % and its equity ratio is set at 56 %. Earnings will be evaluated against a retail ROE range of 9.50 % to 11.90 %. Any retail earnings above 11.90 % will be shared, with 40 % being applied to reduce regulatory assets, 40 % directly refunded to customers, and the remaining 20 % retained by Georgia Power. There will be no recovery of any earnings shortfall below 9.50 % on an actual basis. However, if at any time during the term of the 2022 ARP, Georgia Power projects that its retail earnings will be below 9.50 % for any calendar year, it may petition the Georgia PSC for implementation of the Interim Cost Recovery (ICR) tariff to adjust Georgia Power's retail rates to achieve a 9.50 % ROE. The Georgia PSC would have 90 days to rule on Georgia Power's request. The ICR tariff would expire at the earlier of January 1, 2026 or the end of the calendar year in which the ICR tariff becomes effective. In lieu of requesting implementation of an ICR tariff, or if the Georgia PSC chooses not to implement the ICR tariff, Georgia Power may file a full rate case. In 2023, Georgia Power's retail ROE was within the allowed retail ROE range.
 Except as provided above, Georgia Power will not file for a general base rate increase while the 2022 ARP is in effect. Georgia Power is required to file a general base rate case by July 1, 2025, in response to which the Georgia PSC would be expected to determine whether the 2022 ARP should be continued, modified, or discontinued.
 2019 ARP
 The Georgia PSC approved the following tariff adjustments under the 2019 ARP effective January 1 2022:

 Tariff
 2022

 Traditional base
 $

 ECCR
 ( 12)

 DSM
 ( 25)

 MFF

 Total
 $

 In the 2019 ARP, the Georgia PSC approved recovery through the ECCR tariff of the estimated under recovered balance of CCR ARO compliance costs. Under the 2019 ARP, the under recovered balance at December 31, 2019 and compliance costs for 2020 were recovered over the three-year period ended December 31, 2022. Recovery of estimated compliance costs for 2021 and 2022 are being recovered over four-year periods beginning January 1 of each respective year, as authorized under the 2019 ARP and modified under the 2022 ARP, with recovery of construction contingency beginning in the year following actual expenditure. The CCR ARO costs recovered through the ECCR tariff are revised for actual expenditures and updated estimates through annual compliance filings, which resulted in an approximate $ 10 million increase effective January 1, 2022 in the related cost recovery.
 Georgia Power's retail ROE under the 2019 ARP was set at 10.50 % and earnings were evaluated against a retail ROE range of 9.50 % to 12.00 %. Any retail earnings above 12.00 % were shared, with 40 % applied to reduce regulatory assets, 40 % directly refunded to customers, and the remaining 20 % retained by Georgia Power. In 2020, Georgia Power's retail ROE was within the allowed retail ROE range. In 2021, Georgia Power's retail ROE exceeded 12.00 %, and Georgia Power reduced regulatory assets by approximately $ 5 million and accrued approximately $ 5 million which was refunded to customers in 2022. In 2022, Georgia Power's retail ROE exceeded 12.00 %, and Georgia Power reduced regulatory assets by $ 117 million and refunded $ 117 million to customers through bill credits in the first quarter 2023.
 Integrated Resource Plans
 In July 2022, the Georgia PSC approved Georgia Power's 2022 IRP, as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and as further modified by the Georgia PSC. In the 2022 IRP decision, the Georgia PSC approved, among other things, the certification of six PPAs (including five affiliate PPAs with Southern Power that are subject to approval by the FERC) with capacities of 1,567 MWs beginning in 2024, 380 MWs beginning in 2025, and 228 MWs beginning in 2028, procured through RFPs authorized in the 2019 IRP. See Note 9 for additional information.
 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.
 • Certification of an affiliate PPA with Mississippi Power for 750 MWs, which began January 1, 2024 and will continue through December 2028.
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 • 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 system facilities, including storage systems 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 2023 IRP Update assumes a retirement date at the end of 2035 for Plant Bowen Units 1 and 2 ( 1,400 MWs). Georgia Power expects to make a formal recommendation in the 2025 IRP on the retirement or continued operations for Plant Bowen Units 1 and 2, as well as evaluate extending the operation of Plant Scherer Unit 3 ( 614 MWs based on 75 % ownership) and Plant Gaston Units 1 through 4 ( 500 MWs based on 50 % ownership through SEGCO) beyond the retirement dates in 2028 that were approved in the 2022 IRP. See Note 7 under "SEGCO" for additional information.
 Georgia Power expects the Georgia PSC to render a final decision on the 2023 IRP Update on April 16, 2024.
 On January 12, 2024, Georgia Power entered into an Agreement for Engineering, Procurement, and Construction with Mitsubishi Power Americas, Inc. and Black & Veatch Construction, Inc. to construct three 442 -MW simple cycle combustion turbine units at Plant Yates (Plant Yates Units 8, 9, and 10), which are expected to be placed in service in the fourth quarter 2026, the second quarter 2027, and the third quarter 2027, respectively.
 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 challenged Georgia Power's plan to expend $ 115 million to modernize Plant Tugalo (a hydro facility), as approved in the 2019 IRP, and sought 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. This matter is now concluded.
 Fuel Cost Recovery
 Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. During the second half of 2021, the price of natural gas rose significantly and resulted in an under recovered fuel balance exceeding $ 200 million. Therefore, in November 2021, the Georgia PSC voted to approve Georgia Power's interim fuel rider, which increased fuel rates by 15 %, or approximately $ 252 million annually, effective January 1, 2022.
 During 2022, Georgia Power's under recovered fuel balance continued to increase significantly due to higher fuel and purchased power costs. 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.
 Georgia Power's under recovered fuel balance totaled $ 1.9 billion at December 31, 2023, of which $ 694 million is included in under recovered fuel clause revenues and under recovered retail fuel clause revenues on Southern Company's and Georgia Power's balance sheets, respectively, and $ 1.2 billion is included in deferred under recovered retail fuel clause revenues on Southern Company's and Georgia Power's balance sheets. The under recovered fuel balance totaled $ 2.1 billion at December 31, 2022 and is included in deferred under recovered retail fuel clause revenues on Southern Company's and Georgia Power's balance sheets.
 Georgia Power's fuel cost recovery mechanism includes costs associated with a natural gas hedging program, as revised and approved by the Georgia PSC, allowing the use of an array of derivative instruments within a 36 -month time horizon.
 Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's or Georgia Power's revenues or net income but will affect operating cash flows.
 Storm Damage Recovery
 Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. During 2021 and 2022, Georgia Power recovered $ 213 million annually under the 2019 ARP. Beginning January 1, 2023, Georgia Power is recovering $ 31 million annually under the 2022 ARP. At December 31, 2022, Georgia Power's storm damage reserve balance was $ 83 million and is included in other regulatory liabilities, deferred on Southern Company's balance sheet and other deferred credits and liabilities on Georgia Power's balance sheet. During 2023, significant storms caused damage to Georgia Power's
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 transmission and distribution facilities. The incremental restoration costs related to these storms exceeded the storm damage reserve and were deferred in the regulatory asset for storm damage. At December 31, 2023, Georgia Power's regulatory asset balance related to storm damage was $ 54 million, of which $ 31 million is included in other regulatory assets, current and $ 23 million is included in other regulatory assets, deferred on Southern Company's and Georgia Power's balance sheets. 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. See Note 1 under "Storm Damage and Reliability Reserves" for additional information.

 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.
 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.
 See Note 8 under "Long-term Debt – DOE Loan Guarantee Borrowings" for information on the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, and mandatory prepayment events.
 Cost and Schedule
 Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4, including contingency, through the second quarter 2024 is as follows:

 Base project capital cost forecast(a)(b)

 $
 10,717

 Construction contingency estimate

 Total project capital cost forecast(a)(b)

 10,753

 Net investment at December 31, 2023(b)

 ( 10,564)

 Remaining estimate to complete
 $

 (a)Includes approximately $ 610 million of costs that are not shared with the other Vogtle Owners, including $ 33 million of construction monitoring costs, 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 $ 440 million, of which $ 417 million had been accrued through December 31, 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 $ 3.53 billion, of which $ 3.50 billion had been incurred through December 31, 2023.
 Georgia Power placed Unit 3 in service on July 31, 2023. 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 and engineering support. As of December 31, 2023, based on completion of construction work and the assessment of start-up and pre-operational testing remaining, Southern Nuclear has an estimated $ 36 million for construction contingency remaining in the estimate to complete. This contingency is projected to be allocated in the future to address any further Unit 4 schedule extensions or remediation of other issues discovered during start-up testing.
 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
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 Unit 4 was completed on August 19, 2023. On October 6, 2023, Georgia Power announced that during start-up and pre-operational testing for Unit 4, Southern Nuclear identified a motor fault in one of four reactor coolant pumps (RCPs). This RCP was replaced with an on-site spare RCP from inventory.
 On February 1, 2024, Georgia Power announced that during start-up and pre-operational testing for Unit 4, Southern Nuclear identified, and has remediated, vibrations associated with certain piping within the cooling system. Considering the remaining pre-operational testing, Unit 4 is projected to be placed in service during the second quarter 2024. On February 14, 2024, Unit 4 achieved self-sustaining nuclear fission, commonly referred to as initial criticality.
 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 progression of start-up and pre-operational testing, which may be impacted by equipment or other operational failures. As Unit 4 progresses further through testing, ongoing and potential future challenges may also include the management of contractors and vendors; the availability of materials and parts, and/or related cost escalation; the availability of supervisory and technical support resources; and the timeframe and duration of 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 several years began initial operation in the global nuclear industry at this scale). These challenges may result in further schedule delays and/or cost increases.
 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 June 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 any additional related construction, support resources, or testing costs. Pursuant to the regulatory orders discussed below, any further changes to the capital cost forecast will not 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
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 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 Georgia Power's prudency 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 additional information on Georgia Power's prudency application filing below.
 In September 2022, Georgia Power and MEAG Power reached an agreement to resolve a dispute regarding 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.
 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 cost-sharing and tender provisions of 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.
 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 project capital cost forecast for Plant Vogtle Units 3 and 4 cannot be determined at this time.
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 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 December 31, 2023, Georgia Power had recovered approximately $ 3.0 billion of financing costs. Financing costs related to capital costs above $ 4.418 billion up to $ 7.562 billion approved for recovery as described below are being recognized through AFUDC and will 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 $ 7.562 billion. 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 for 2024 the NCCR tariff that was effective during 2023. The staff of the Georgia PSC accepted the proposal and no further approval from the Georgia PSC was required. See additional information below on AFUDC and the NCCR tariff following commercial operation of Unit 4.
 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 January 2018, the Georgia PSC issued an order approving Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 2018 order, resolved certain regulatory matters related to Plant Vogtle Units 3 and 4 including, but not limited to: (i) 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; (ii) confirmed that a prudence proceeding on cost recovery would occur following Unit 4 fuel load, consistent with applicable Georgia law; (iii) 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); and (iv) 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.
 The January 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 $ 310 million, $ 300 million, and $ 270 million in 2023, 2022, and 2021, respectively, and are estimated to have a negative earnings impact of approximately $ 90 million in 2024.
 In 2021, the Georgia PSC approved an order under which Georgia Power would include in rate base an allocation of $ 2.1 billion to Plant Vogtle Unit 3 and the Common Facilities from the $ 3.6 billion of Plant Vogtle Units 3 and 4 costs previously deemed prudent by the Georgia PSC and would recover the related depreciation expense through retail base rates effective the month after Unit 3 is placed in service. In compliance with the Georgia PSC order, 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 Unit 3. The related increase in annual retail base rates included recovery of all projected operations and maintenance expenses for Unit 3 and the Common Facilities and other related costs of operation, partially offset by the related PTCs. Financing costs (debt and equity) on the remaining portion of the total Unit 3 and the Common Facilities construction costs continue to be recovered through the NCCR tariff or deferred. Georgia Power is deferring as a regulatory asset the debt component of financing costs ($ 14 million at December 31, 2023) as well as the remaining depreciation expense ($ 17 million at December 31, 2023) until Unit 4 costs are placed in retail base rates. The equity component of financing costs ($ 23 million at December 31, 2023) represents an unrecognized ratemaking amount that is not reflected on Georgia Power's balance sheets. This amount will be recognized in Georgia Power's income statements in the periods it is billable to customers.
 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 (Application). On December 19, 2023, the Georgia PSC voted to approve the Application as modified by the related stipulated agreement (Prudency Stipulation) among Georgia Power, the staff of the Georgia PSC, and certain intervenors.
 While recognizing the Prudency Stipulation, the Application provided 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. Under the terms of the approved Prudency Stipulation, 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 will also recover projected operations and maintenance expenses, depreciation expense, nuclear decommissioning accruals, and property taxes, net of projected PTCs. After considering construction and capital costs already in
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 retail base rates of $ 2.1 billion and $ 362 million of associated retail rate base items (approved by the Georgia PSC in 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.
 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 retail revenue requirements. Further, as included in the approved Prudency Stipulation, 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 will result in an estimated negative impact to earnings of approximately $ 30 million per month until the month following the date commercial operation for Unit 4 is achieved. 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.
 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.
 The approval of the Application and the Prudency Stipulation resolves all issues for determination by the Georgia PSC regarding the reasonableness, prudence, and cost recovery for the remaining Plant Vogtle Units 3 and 4 construction and capital costs not already in retail base rates.
 As a result of the Georgia PSC's approval of the Prudency Stipulation, Georgia Power recorded a pre-tax credit to income of approximately $ 228 million ($ 170 million after tax) in the fourth quarter 2023 to recognize CWIP costs previously charged to income, which are now recoverable through retail rates. Associated AFUDC on these costs was also recognized.

 Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are expected to be recovered through Mississippi Power's base rates.
 Performance Evaluation Plan
 Mississippi Power's retail base rates generally are set under the PEP, a rate plan approved by the Mississippi PSC. In recognition that Mississippi Power's long-term financial success is dependent upon how well it satisfies its customers' needs, PEP includes performance indicators that directly tie customer service indicators to Mississippi Power's allowed ROE. PEP measures Mississippi Power's performance on a 10-point scale as a weighted average of results in three areas: average customer price, as compared to prices of other regional utilities (weighted at 40 %); service reliability, measured in percentage of time customers had electric service ( 40 %); and customer satisfaction, measured in a survey of residential customers ( 20 %). Typically, two PEP filings are made for each calendar year: the PEP projected filing in March of the current year and the PEP lookback filing in March of the subsequent year. The annual PEP projected filings utilize a historic test year adjusted for "known and measurable" changes and discounted cash flow and regression formulas to determine base ROE. The PEP lookback filing reflects the actual revenue requirement.
 In June 2021 and June 2022, the Mississippi PSC approved Mississippi Power's annual retail PEP filings, resulting in annual increases in revenues of approximately $ 16 million, or 1.8 %, and $ 18 million, or 1.9 %, respectively, effective with the first billing cycle of April 2021 and April 2022, respectively. On June 13, 2023, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2023 indicating no change in retail rates.
 Integrated Resource Plan
 In 2020, the Mississippi PSC issued an order requiring Mississippi Power to incorporate into its 2021 IRP a schedule of early or anticipated retirement of 950 MWs of fossil-steam generation by year-end 2027 to reduce the excess reserve margin Mississippi Power anticipated at that time. The order stated that Mississippi Power will be allowed to defer any retirement-related costs as regulatory assets for future recovery.
 In 2021, the Mississippi PSC concluded its review of Mississippi Power's 2021 IRP. The 2021 IRP included a schedule to retire Plant Watson Unit 4 ( 268 MWs) and Mississippi Power's 40 % ownership interest in Plant Greene County Units 1 and 2 ( 103
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 MWs each) in December 2023, 2025, and 2026, respectively, consistent with each unit's remaining useful life in the most recent approved depreciation studies. In addition, the schedule reflected the early retirement of Mississippi Power's 50 % undivided ownership interest in Plant Daniel Units 1 and 2 ( 502 MWs) by the end of 2027. The Plant Greene County unit retirements require the completion by Alabama Power of transmission and system reliability improvements, as well as agreement by Alabama Power.
 The remaining net book value of Plant Daniel Units 1 and 2 was approximately $ 489 million at December 31, 2023 and Mississippi Power is continuing to depreciate these units using the current approved rates. Mississippi Power expects to reclassify the net book value remaining at retirement to a regulatory asset to be amortized over a period to be determined by the Mississippi PSC in future proceedings, consistent with the 2020 order. The Plant Watson and Greene County units are expected to be fully depreciated upon retirement. See Note 3 under "Other Matters – Mississippi Power" for additional information on Plant Daniel Units 1 and 2.
 In October 2023, Mississippi Power signed an affiliate PPA with Georgia Power for 750 MWs of capacity, which began January 1, 2024 and will continue through December 2028. In order to fulfill this PPA and serve the interests of customers, Mississippi Power now expects electric generating units identified in its 2021 IRP to remain in service beyond the previously indicated dates. Mississippi Power is expected to file its next IRP in April 2024 in accordance with the rules and orders of the Mississippi PSC.
 Environmental Compliance Overview Plan
 In accordance with a 2011 accounting order from the Mississippi PSC, Mississippi Power has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations.
 In June 2021, April 2022, and April 2023, the Mississippi PSC approved Mississippi Power's annual ECO Plan filings, resulting in a decrease in revenues of approximately $ 9 million annually effective with the first billing cycle of July 2021, an increase in revenues of approximately $ 1 million annually effective with the first billing cycle of May 2022, and a $ 3 million annual increase in revenues effective with the first billing cycle of May 2023, respectively.
 On February 12, 2024, Mississippi Power submitted its annual ECO Plan filing to the Mississippi PSC, which requested a $ 9 million annual increase in revenues. The ultimate outcome of this matter cannot be determined at this time.
 Fuel Cost Recovery
 Mississippi Power annually establishes, and is required to file for an adjustment to, the retail fuel cost recovery factor that is approved by the Mississippi PSC. The Mississippi PSC approved increases of $ 2 million and $ 43 million effective in February 2021 and 2022, respectively. In November 2022, Mississippi Power filed a request with the Mississippi PSC to increase retail fuel revenues by $ 25 million annually effective with the first billing cycle of February 2023 and an additional $ 25 million annually effective with the first billing cycle of June 2023. On January 10, 2023, the Mississippi PSC voted to defer approval of the filing. Mississippi Power is allowed to maintain current billing rates and continue accruing its weighted-average cost of capital on any under or over fuel recovery balance. On February 6, 2024, the Mississippi PSC approved Mississippi Power's request to increase retail fuel revenues by $ 18 million annually effective with the first billing cycle of March 2024. The approved filing included the deferral of approximately $ 61 million of under recovered fuel costs as of October 2023, which is expected to be included in Mississippi Power's next fuel filing. Mississippi Power will continue to accrue its weighted-average cost of capital on any under or over fuel recovery balance.
 At December 31, 2023, Mississippi Power had $ 50 million of deferred under recovered retail fuel clause revenues and $ 27 million of over recovered retail fuel clause revenues primarily associated with its fuel-hedging program on its balance sheet. At December 31, 2022, under recovered retail fuel costs of approximately $ 1 million were included in other customer accounts receivable on Mississippi Power's balance sheet. See Note 1 under "Fuel Costs" for additional information.
 Mississippi Power has wholesale MRA and Market Based (MB) fuel cost recovery factors. Effective with the first billing cycles for January 2022, 2023, and 2024, annual revenues under the wholesale MRA fuel rate increased $ 11 million and $ 22 million and decreased $ 4 million, respectively. The wholesale MB fuel rate did not change materially in any period presented. At December 31, 2023 and 2022, wholesale fuel costs were over recovered $ 5 million and under recovered $ 6 million, respectively.
 Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel cost 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.
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 Ad Valorem Tax Adjustment
 Mississippi Power annually establishes an ad valorem tax adjustment factor that is approved by the Mississippi PSC. Effective with the first billing cycle of May 2021, July 2022, and June 2023, the Mississippi PSC approved changes in annual revenues collected through the ad valorem tax adjustment factor resulting in a $ 28 million increase, a $ 5 million increase, and a $ 7 million decrease, respectively. The 2021 increase included approximately $ 19 million of ad valorem taxes previously recovered through PEP in accordance with a 2019 rate case settlement agreement.
 System Restoration Rider
 Mississippi Power carries insurance for the cost of certain types of damage to generation plants and general property. However, Mississippi Power is self-insured for the cost of storm, fire, and other uninsured casualty damage to its property, including transmission and distribution facilities. As permitted by the Mississippi PSC and the FERC, Mississippi Power accrues for the cost of such damage through an annual expense accrual which is credited to regulatory liability accounts for the retail and wholesale jurisdictions. The cost of repairing actual damage resulting from such events that individually exceed $ 50,000 is charged to the reserve. Every year, the Mississippi PSC, the MPUS, and Mississippi Power agree on SRR revenue level(s).
 Mississippi Power's net retail SRR accrual, which includes carrying costs and previously included amortization of related excess deferred income tax benefits, was $ 11.7 million in 2023, $ 6.9 million in 2022, and $( 1.8) million in 2021. At December 31, 2023 and 2022, the retail property damage reserve balance was $ 45 million and $ 37 million, respectively.
 In 2021, the Mississippi PSC approved Mississippi Power's annual SRR filing, which requested an increase in retail revenues of approximately $ 9 million annually effective with the first billing cycle of March 2022. 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 $ 8.3 million to $ 11.7 million. In the event the expected annual charges exceed the annual accrual or the target balance has been met, Mississippi Power and the Mississippi PSC will determine the appropriate change to the annual accrual. Additionally, if PEP earnings are above a certain threshold, Mississippi Power has the ability to apply any required PEP refund as an additional accrual to the property damage reserve in lieu of customer refunds.
 On February 1, 2024, Mississippi Power submitted its annual SRR filing to the Mississippi PSC, which indicated no change in retail rates. The filing includes a request to increase the minimum annual SRR accrual from $ 11.7 million to $ 12.6 million.
 Reliability Reserve Accounting Order
 In December 2022, the Mississippi PSC approved an accounting order authorizing Mississippi Power to create a reliability reserve for the purpose of deferring generation, transmission, and distribution reliability-related expenditures for use in a future year. Mississippi Power may make accruals to the reliability reserve each year after meeting with the MPUS and Mississippi PSC staff. Mississippi Power will provide annually, through its capital plan, energy delivery plan, or PEP filing, any amounts to be charged against the reliability reserve during the current year. During 2023 and 2022, Mississippi Power accrued $ 11 million and $ 25 million, respectively, to the reliability reserve. At December 31, 2023 and 2022, the reliability reserve balance was $ 36 million and $ 25 million, respectively.

 Municipal and Rural Associations Tariff
 Mississippi Power provides wholesale electric service to Cooperative Energy, East Mississippi Electric Power Association, and the City of Collins, all located in southeastern Mississippi, under a long-term, cost-based, FERC-regulated MRA tariff.
 In 2017, Mississippi Power and Cooperative Energy executed, and the FERC accepted, a Shared Service Agreement (SSA), as part of the MRA tariff, under which Mississippi Power and Cooperative Energy share in providing electricity to the Cooperative Energy delivery points under the tariff. In August 2022, the FERC accepted an amended SSA between Mississippi Power and Cooperative Energy, effective July 1, 2022, under which Cooperative Energy will continue to decrease its use of Mississippi Power's generation services under the MRA tariff up to 2.5 % annually through 2035. At December 31, 2023, Mississippi Power is serving approximately 390 MWs of Cooperative Energy's annual demand. Beginning in 2036, Cooperative Energy will provide 100 % of its electricity requirements at the MRA delivery points under the tariff. Neither party has the option to cancel the amended SSA.
 On 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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 Utility Regulation and Rate Design
 The natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies. Rates charged to customers vary according to customer class (residential, commercial, or industrial) and rate jurisdiction. These agencies approve rates designed to provide the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable ROE.
 As a result of operating in a deregulated environment, Atlanta Gas Light earns revenue by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC and adjusted periodically. The Marketers add these fixed charges when billing their respective customers. This mechanism, called a straight-fixed-variable rate design, minimizes the seasonality of Atlanta Gas Light's revenues since the monthly fixed charge is not volumetric or directly weather dependent.
 With the exception of Atlanta Gas Light, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are largely a function of weather conditions and price levels for natural gas. Specifically, customer demand substantially increases during the Heating Season when natural gas is used for heating purposes. Southern Company Gas has various mechanisms, such as weather and revenue normalization mechanisms and weather derivative instruments, that limit exposure to weather changes within typical ranges in these utilities' respective service territories.
 In addition to natural gas cost recovery mechanisms, other cost recovery mechanisms and regulatory riders, which vary by utility, allow recovery of certain costs, such as those related to infrastructure replacement programs as well as environmental remediation, energy efficiency plans, and bad debts. In traditional rate designs, utilities recover a significant portion of the fixed customer service and pipeline infrastructure costs based on assumed natural gas volumes used by customers. With the exception of Chattanooga Gas, the natural gas distribution utilities have decoupled regulatory mechanisms that Southern Company Gas believes encourage conservation by separating the recoverable amount of these fixed costs from the amounts of natural gas used by customers. See "Rate Proceedings" herein for additional information. Also see "Infrastructure Replacement Programs and Capital Projects" herein for additional information regarding infrastructure replacement programs at certain of the natural gas distribution utilities.
 The following table provides regulatory information for Southern Company Gas' natural gas distribution utilities:

 Authorized ROE at December 31, 2023

 9.51 %
 10.25 %
 9.70 %
 9.80 %

 Weather normalization mechanisms(a)

 Decoupled, including straight-fixed-variable rates(b)

 Regulatory infrastructure program rate(c)

 Bad debt rider(d)

 Energy efficiency plan(e)

 Annual base rate adjustment mechanism(f)

 Year of last base rate case decision
 2023
 2019
 2023
 2018

 (a)Designed to help stabilize operating results by allowing recovery of costs in the event of unseasonal weather, but are not direct offsets to the potential impacts on earnings of weather and customer consumption.
 (b)Allows for recovery of fixed customer service costs separately from assumed natural gas volumes used by customers and provides a benchmark level of revenue for recovery.
 (c)See "Infrastructure Replacement Programs and Capital Projects" herein for additional information. Chattanooga Gas' pipeline replacement program costs are recovered through its annual base rate review mechanism.
 (d)The recovery (refund) of bad debt expense over (under) an established benchmark expense. The gas portion of bad debt expense is recovered through purchased gas adjustment mechanisms. Nicor Gas also has a rider to recover the non-gas portion of bad debt expense.
 (e)Recovery of costs associated with plans to achieve specified energy savings goals.
 (f)Regulatory mechanism allowing annual adjustments to base rates up or down based on authorized ROE and/or ROE range.
 Infrastructure Replacement Programs and Capital Projects
 In addition to capital expenditures recovered through base rates by each of the natural gas distribution utilities, Nicor Gas and Virginia Natural Gas have separate rate riders that provide timely recovery of capital expenditures for specific infrastructure replacement programs and Atlanta Gas Light has a separate rate rider that provides for the timely recovery of capital expenditures for a specific reinforcement capital program. Total capital expenditures incurred during 2023 for all gas distribution operations were $ 1.6 billion.
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 The following table and discussions provide updates on the infrastructure replacement programs and capital projects at the natural gas distribution utilities at December 31, 2023. These programs are risk-based and designed to update and replace cast iron, bare steel, and mid-vintage plastic materials or expand Southern Company Gas' distribution systems to improve reliability and meet operational flexibility and growth.

 Utility
 Program
 Recovery
 Capital Expenditures in 2023

 Capital Expenditures Since Project Inception

 Pipe
Installed Since
Project Inception
 Scope of
Program
 Program Duration
 Last
Year of Program

 (miles)
 (miles)
 (years)

 Investing in Illinois Qualifying Infrastructure Plant(*)

 Rider
 $
 $
 3,228
 1,367
 1,367
 2023

 SAVE

 Rider
 2024

 System Reinforcement Rider
 Rider
 N/A
 2024

 Pipeline Replacement Program
 Rate Base
 2027

 Total
 $
 $
 3,910
 1,969
 2,135

 (*)Included replacement of pipes, compressors, and transmission mains along with other improvements such as new meters. This program ended November 30, 2023 with all expenditures placed in service. Recovery of program costs is described under "Nicor Gas" herein.
 Illinois legislation allows Nicor Gas to provide more widespread safety and reliability enhancements to its distribution system through 2023 and stipulates that rate increases to customers as a result of any infrastructure investments shall not exceed a cumulative annual average of 4.0 % or, in any given year, 5.5 % of base rate revenues. In 2014, the Illinois Commission approved the nine-year regulatory infrastructure program, Investing in Illinois, which concluded in 2023 and is subject to annual review, as discussed further below. In accordance with orders from the Illinois Commission, Nicor Gas recovers program costs incurred through a separate rider and base rates. See "Rate Proceedings – Nicor Gas" herein for additional information.
 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 placed in service in 2019. The disallowance is reflected on the statement of income as an $ 8 million reduction to revenues and $ 30 million in estimated loss on regulatory disallowance. 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 following table provides a summary of QIP capital investments during the nine-year program:

 Year
 Status of QIP Annual Review Proceeding
 Capital Investments

 Disallowed
 Month of Disallowance

 2015 – 2018
 Complete
 $
 1,246
 $
 —

 2019
 Complete(a)

 June 2023

 2020
 Filed March 2021

 (b)

 2021
 Filed March 2022

 (b)

 2022
 Filed March 2023

 (b)

 (a)(c)

 November 2023

 2023
 To be filed by March 20, 2024

 (b)

 (a)(c)

 November 2023

 $
 3,228
 $

 (a)Appealed to the Illinois Appellate Court.
 (b)Capital investments are subject to the required QIP annual review proceeding; years 2020 through 2022 are pending with the Illinois Commission.
 (c)Disallowed in Nicor Gas' 2023 general base rate case proceeding. See "Rate Proceedings – Nicor Gas" herein for additional information regarding the Illinois Commission's disallowance of certain capital investments.
 Any further cost disallowances by the Illinois Commission in the pending cases could be material to the financial statements of Southern Company Gas. The ultimate outcome of these matters cannot be determined at this time.
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 The SAVE program, an accelerated infrastructure replacement program, allows Virginia Natural Gas to continue replacing aging pipeline infrastructure through 2024. The program includes authorized annual investments of $ 60 million in 2021 and $ 70 million in each year from 2022 through 2024, with a total potential variance of up to $ 5 million allowed for the program, for a maximum total investment over the six-year term (2019 through 2024) of $ 365 million.
 On February 9, 2024, Virginia Natural Gas filed with the Virginia Commission a request to extend the existing SAVE program through 2029. The request includes investments of $ 70 million in each year from 2025 through 2029, with a potential variance of up to $ 5 million allowed for the program, for a maximum total investment over the five-year extension (2025 through 2029) of $ 355 million. Virginia Natural Gas expects the Virginia Commission to issue a final order on this matter in the second quarter 2024. The ultimate outcome of this matter cannot be determined at this time.
 The SAVE program is subject to annual review by the Virginia Commission. In accordance with the base rate case approved by the Virginia Commission in 2023, Virginia Natural Gas is recovering program costs incurred prior to January 1, 2023 through base rates. Program costs incurred subsequent to January 1, 2023 are currently being recovered through a separate rider and are subject to future base rate case proceedings. See "Rate Proceedings – Virginia Natural Gas" herein for additional information.
 In 2019, the Georgia PSC approved the continuation of GRAM as part of Atlanta Gas Light's 2019 rate case order. Various infrastructure programs previously authorized by the Georgia PSC, including the Integrated Vintage Plastic Replacement Program to replace aging plastic pipe and the Integrated System Reinforcement Program to upgrade Atlanta Gas Light's distribution system and LNG facilities in Georgia, continue under GRAM and the recovery of and return on the infrastructure program investments are included in annual base rate adjustments. The amounts to be recovered through rates related to allowed, but not incurred, costs have been quantified as an unrecognized ratemaking amount that is not reflected on the balance sheets. These allowed costs are primarily the equity return on the capital investment under the infrastructure programs in place prior to GRAM and are being recovered through GRAM and base rates until the earlier of the full recovery of such amounts or December 31, 2025. The under recovered balance at December 31, 2023 was $ 44 million, including $ 23 million of unrecognized equity return, and is expected to be recovered by December 31, 2025. The Georgia PSC reviews Atlanta Gas Light's performance annually under GRAM. See "Unrecognized Ratemaking Amounts" herein for additional information.
 Atlanta Gas Light and the staff of the Georgia PSC previously agreed to a variation of the Integrated Customer Growth Program to extend pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. A separate tariff provides recovery of up to $ 15 million annually for strategic economic development projects approved by the Georgia PSC.
 See "Rate Proceedings – Atlanta Gas Light" herein for additional information regarding the Georgia PSC's 2021 approval of Atlanta Gas Light's GRAM filing and Integrated Capacity and Delivery Plan. The Georgia PSC also approved a new System Reinforcement Rider for authorized large pressure improvement and system reliability projects, which is expected to recover related capital investments totaling $ 286 million for the years 2022 through 2024, of which $ 104 million and $ 76 million was incurred in 2023 and 2022, respectively.
 In 2021, the Tennessee Public Utilities Commission approved Chattanooga Gas' pipeline replacement program to replace approximately 73 miles of distribution main over a seven-year period. The estimated total cost of the program is $ 118 million, which will be recovered through Chattanooga Gas' annual base rate review mechanism.
 Natural Gas Cost Recovery
 With the exception of Atlanta Gas Light, the natural gas distribution utilities are authorized by the relevant regulatory agencies in the states in which they serve to use natural gas cost recovery mechanisms that adjust rates to reflect changes in the wholesale cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. The natural gas distribution utilities defer or accrue the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred natural gas costs are reflected as regulatory assets and accrued natural gas costs are reflected as regulatory liabilities. Natural gas costs generally do not have a significant effect on Southern Company's or Southern Company Gas' net income, but could have a significant effect on cash flows. Since Atlanta Gas Light does not sell natural gas directly to its end-use customers, it does not utilize a traditional natural gas cost recovery mechanism. However, Atlanta Gas Light does maintain natural gas inventory for the Marketers in Georgia and recovers the cost through recovery mechanisms approved by the Georgia PSC. At December 31, 2023, the over recovered balance was $ 214 million, which was included in
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 natural gas cost over recovery on Southern Company's and Southern Company Gas' balance sheets. At December 31, 2022, the under recovered balance was $ 108 million, which was included in natural gas cost under recovery on Southern Company's and Southern Company Gas' balance sheets.
 Rate Proceedings
 In 2021, the Illinois Commission approved a $ 240 million annual base rate increase, which became effective November 24, 2021. The base rate increase included $ 94 million related to the recovery of program costs under the Investing in Illinois program and was based on a ROE of 9.75 % and an equity ratio of 54.5 %.
 On November 16, 2023, the Illinois Commission approved a $ 223 million annual base rate increase for Nicor Gas, which became effective December 1, 2023. The base rate increase was based on a return on equity of 9.51 % and an equity ratio of 50.00 %.
 In connection with Nicor Gas' general base rate case proceeding, the Illinois Commission disallowed $ 126.8 million of capital investments that have been completed or planned to be completed through December 31, 2024. This includes $ 31 million for capital investments placed in service in 2022 and 2023 under the Investing in Illinois program and $ 95.9 million for other transmission and distribution capital investments. Nicor Gas recorded a pre-tax charge to income in the fourth quarter 2023 of $ 58 million ($ 44 million after tax) associated with the disallowances, with the remaining $ 69 million related to prospective projects that will be postponed and/or reevaluated. The disallowance is reflected on the statement of income in estimated loss on regulatory disallowance. See "Infrastructure Replacement Programs and Capital Projects – Nicor Gas" herein for additional information regarding the Illinois Commission's disallowance of certain capital investments. On January 3, 2024, the Illinois Commission denied a request by Nicor Gas for rehearing on the base rate case disallowances associated with capital investment, as well as on other issues determined in the Illinois Commission's November 16, 2023 base rate case decision. On February 6, 2024, Nicor Gas filed a notice of appeal with the Illinois Appellate Court related to the Illinois Commission's rate case ruling. The ultimate outcome of this matter cannot be determined at this time.
 The Georgia PSC evaluates Atlanta Gas Light's earnings against a ROE range of 10.05 % to 10.45 %, with disposition of any earnings above 10.45 % to be determined by the Georgia PSC. Additionally, the Georgia PSC allows inclusion in base rates of the recovery of and return on the infrastructure program investments, including, but not limited to, GRAM adjustments. GRAM filing rate adjustments are based on an authorized ROE of 10.25 %. GRAM adjustments for 2021 could not exceed 5 % of 2020 base rates. The 5 % limitation does not set a precedent in any future rate proceedings by Atlanta Gas Light.
 In April 2021, Atlanta Gas Light filed its Integrated Capacity and Delivery Plan (i-CDP) with the Georgia PSC, which included a series of ongoing and proposed pipeline safety, reliability, and growth programs for the next 10 years (2022 through 2031), as well as the required capital investments and related costs to implement the programs. The i-CDP reflected capital investments totaling approximately $ 0.5 billion to $ 0.6 billion annually.
 In November 2021, the Georgia PSC approved a stipulation agreement between Atlanta Gas Light and the staff of the Georgia PSC, under which, for the years 2022 through 2024, Atlanta Gas Light will incrementally reduce its combined GRAM and System Reinforcement Rider request by 10 % through Atlanta Gas Light's GRAM mechanism, which resulted in a reduction of $ 5 million for 2022, $ 7 million for 2023, and $ 9 million for 2024. The stipulation agreement also provided for $ 1.7 billion of total capital investment for the years 2022 through 2024.
 In November 2021, December 2022, and December 2023, the Georgia PSC approved Atlanta Gas Light's annual GRAM filings, which resulted in an annual rate increase of $ 43 million effective January 1, 2022, an annual rate increase of $ 53 million effective January 1, 2023, and an annual rate increase of $ 53 million effective January 1, 2024, respectively.
 On February 1, 2024, Atlanta Gas Light filed its triennial i-CDP with the Georgia PSC, which included a series of ongoing and proposed pipeline safety, reliability, and growth programs for the next 10 years (2025 through 2034), as well as the required capital investments and related costs to implement the programs. The i-CDP reflected capital investments totaling approximately
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 $ 0.7 billion to $ 1.0 billion annually. Atlanta Gas Light expects the Georgia PSC to issue a final order on this matter in the third quarter 2024. The ultimate outcome of this matter cannot be determined at this time.
 In 2021, the Virginia Commission approved a stipulation agreement related to Virginia Natural Gas' 2020 general rate case filing, which allowed for a $ 43 million increase in annual base rate revenues, including $ 14 million related to the recovery of investments under the SAVE program, based on a ROE of 9.5 % and an equity ratio of 51.9 %. Interim rates became effective as of November 1, 2020, subject to refund, based on Virginia Natural Gas' original requested increase of approximately $ 50 million. Refunds to customers related to the difference between the approved rates effective October 1, 2021 and the interim rates were completed during the fourth quarter 2021.
 On August 28, 2023, the Virginia Commission approved a stipulation agreement related to Virginia Natural Gas' August 2022 general base rate case filing, which allowed for a $ 48 million increase in annual base rate revenues based on a ROE of 9.70 % and an equity ratio of 49.06 %. Interim rates became effective as of 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 were completed during the fourth quarter 2023.
 Unrecognized Ratemaking Amounts
 The following table illustrates Southern Company Gas' authorized ratemaking amounts that are not recognized on its balance sheets. These amounts are primarily comprised of an allowed equity rate of return on assets associated with certain regulatory infrastructure programs. These amounts will be recognized as revenues in Southern Company Gas' financial statements in the periods they are billable to customers, the majority of which will be recovered by 2025.

 December 31, 2022

 $
 $

 Total
 $
 $

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 3. CONTINGENCIES, COMMITMENTS, AND GUARANTEES

 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 intend to dispute the allegations raised in and vigorously defend against the pending legal challenges discussed below; 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.

 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 sought a declaratory judgment that the RCRA and regulations governing CCR were 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. In December 2022, Alabama Power filed a motion to dismiss the case. On January 4, 2024, the lawsuit was dismissed without prejudice by the U.S. District Court judge. On February 1, 2024, the plaintiff filed a motion to reconsider.
 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 this matter cannot be determined at this time but could have a material impact on Alabama Power's ARO estimates and cash flows.
 See Note 6 for a discussion of Alabama Power's ARO liabilities.

 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
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 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.

 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. On December 14, 2023, the U.S. Court of Appeals for the Fifth Circuit affirmed the district court's order dismissing the plaintiffs' complaint against Mississippi Power. On December 28, 2023, the plaintiffs filed a petition for panel rehearing, which was denied on January 10, 2024. The plaintiffs have until April 9, 2024 to file a petition for writ of certiorari with the U.S. Supreme Court. The ultimate outcome of this matter cannot be determined at this time.

 In July 2021, Southern Power and certain of its subsidiaries filed an arbitration demand with the American Arbitration Association against First Solar Electric, LLC (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 2023 statement 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 December 31, 2023 as restricted cash and a liability to fund future replacement costs. In November 2023, the final award was issued and Southern Power filed for confirmation of the final award in the Delaware Court of Chancery. In December 2023, First Solar filed a motion to dismiss the confirmation and, in February 2024, filed a petition to vacate the arbitration award in the Supreme Court of New York County, New York. The ultimate outcome of this matter cannot be determined at this time.
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 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 conduct studies to determine the extent of any required cleanup and have recognized the estimated costs to clean up known impacted sites in the financial statements. A liability for environmental remediation costs is recognized only when a loss is determined to be probable and reasonably estimable and is reduced as expenditures are incurred. 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. Any difference between the liabilities accrued and costs recovered through rates is deferred as a regulatory asset or liability. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.

 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. For 2023, 2022, and 2021, Georgia Power recovered approximately $ 5 million, $ 12 million, and $ 12 million, respectively, through the ECCR tariff for environmental remediation.
 Southern Company Gas is subject to environmental remediation liabilities associated with 40 former manufactured gas plant sites in four different states. Southern Company Gas' accrued environmental remediation liability at December 31, 2023 and 2022 was based on the estimated cost of environmental investigation and remediation associated with these sites.
 At December 31, 2023 and 2022, the environmental remediation liability and the balance of under recovered environmental remediation costs were reflected in the balance sheets of Southern Company, Georgia Power, and Southern Company Gas as shown in the table below. Alabama Power and Mississippi Power did not have environmental remediation liabilities at December 31, 2023 or 2022.

Power

 December 31, 2023:

 Environmental remediation liability:

 $
 $
 $

 Accrued environmental remediation
 —

 Under recovered environmental remediation costs:

 Other regulatory assets, current
 $
 $
 $

 December 31, 2022:

 Environmental remediation liability:

 $
 $
 $

 Accrued environmental remediation
 —

 Under recovered environmental remediation costs:

 Other regulatory assets, current
 $
 $
 $

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

 Nuclear Fuel Disposal Costs
 Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that required the DOE to take title to and dispose of spent nuclear fuel generated at Plants Farley, Hatch, and Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence performance of
 II-159

 its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and Georgia Power pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.
 In 2014, Alabama Power and Georgia Power filed their third round of lawsuits against the U.S. government in the Court of Federal Claims, seeking damages for the costs of continuing to store spent nuclear fuel at Plants Farley, Hatch, and Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. In 2019, the Court of Federal Claims granted Alabama Power's and Georgia Power's motion for summary judgment on damages not disputed by the U.S. government, awarding those undisputed damages to Alabama Power and Georgia Power. However, those undisputed damages are not collectible until the court enters final judgment on the remaining damages.
 In 2017, Alabama Power and Georgia Power filed their fourth round of lawsuits against the U.S. government in the Court of Federal Claims, seeking damages for the costs of continuing to store spent nuclear fuel at Plants Farley, Hatch, and Vogtle Units 1 and 2 for the period from January 1, 2015 through December 31, 2017. In 2020, Alabama Power and Georgia Power filed amended complaints in those fourth-round lawsuits adding damages incurred from January 1, 2018 to December 31, 2019 to the claim period.
 The outstanding claims for the period January 1, 2011 through December 31, 2019 total $ 106 million and $ 128 million for Alabama Power and Georgia Power (based on its ownership interests), respectively. Damages will continue to accumulate until the issue is resolved, the U.S. government disposes of Alabama Power's and Georgia Power's spent nuclear fuel pursuant to its contractual obligations, or alternative storage is otherwise provided. No amounts have been recognized in the financial statements as of December 31, 2023 for any potential recoveries from the pending lawsuits.
 The final outcome of these matters cannot be determined at this time. However, Alabama Power and Georgia Power expect to credit any recoveries for the benefit of customers in accordance with direction from their respective PSC; therefore, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.
 On-site dry spent fuel storage facilities are operational at all three plants and can be expanded to accommodate spent fuel through the expected life of each plant.

 Nuclear Insurance
 Under the Price-Anderson Amendments Act (Act), Alabama Power and Georgia Power maintain agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the companies' nuclear power plants. The Act provides funds up to $ 16.2 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $ 450 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. A company could be assessed up to $ 166 million per incident for each licensed reactor it operates but not more than an aggregate of $ 25 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for Alabama Power and Georgia Power, based on its ownership and buyback interests in all licensed reactors, is $ 332 million and $ 473 million, respectively, per incident, but not more than an aggregate of $ 49 million and $ 71 million, respectively, to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than November 1, 2028. See Note 5 under "Joint Ownership Agreements" for additional information on joint ownership agreements.
 Alabama Power and Georgia Power are members of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $ 1.5 billion for members' operating nuclear generating facilities. Additionally, both companies have NEIL policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $ 1.25 billion for nuclear losses and policies providing coverage up to $ 750 million for non-nuclear losses in excess of the $ 1.5 billion primary coverage.
 NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $ 490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted. Alabama Power and Georgia Power each purchase limits based on the projected full cost of replacement power, subject to ownership limitations, and have each elected a 12-week deductible waiting period for each nuclear plant.
 A builders' risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Unit 4. This policy provides the Vogtle Owners up to $ 2.75 billion for accidental property damage occurring during construction.
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 Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The maximum annual assessments for Alabama Power and Georgia Power as of December 31, 2023 under the NEIL policies would be $ 54 million and $ 89 million, respectively.
 Claims resulting from terrorist acts and cyber events are covered under both the ANI and NEIL policies (subject to normal policy limits). The maximum aggregate that NEIL will pay for all claims resulting from terrorist acts and cyber events in any 12-month period is $ 3.2 billion each, plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.
 For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the applicable company or to its debt trustees as may be appropriate under the policies and applicable trust indentures. In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered from customers, would be borne by Alabama Power or Georgia Power, as applicable, and could have a material effect on Southern Company's, Alabama Power's, and Georgia Power's financial condition and results of operations.
 All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.

 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 joint use agreement remains in effect. 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.

 Kemper County Energy Facility
 In 2021, 2022, and 2023, Mississippi Power recorded charges to income associated with abandonment and related closure costs and ongoing period costs, net of salvage proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. These charges, including related tax impacts, totaled $ 11 million pre-tax ($ 8 million after tax) in 2021, $ 15 million pre-tax ($ 12 million after tax) in 2022, and $ 17 million pre-tax ($ 12 million after tax) in 2023. The pre-tax charges are included in other operations and maintenance expenses on the statements of income.
 Dismantlement of the abandoned gasifier-related assets and site restoration activities are expected to be completed by 2026. Additional pre-tax period costs associated with dismantlement and site restoration activities, including related costs for compliance and safety, ARO accretion, and property taxes, net of salvage, are estimated to total approximately $ 15 million annually through 2025.
 Mississippi Power owns the lignite mine located around the Kemper County energy facility site. As a result of the abandonment of the Kemper IGCC, final mine reclamation began in 2018 and was substantially completed in 2020, with monitoring expected to continue through 2028.
 As the mining permit holder, Liberty Fuels Company, LLC, a wholly-owned subsidiary of The North American Coal Corporation, has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. See Note 6 for additional information.
 See "General Litigation Matters – Southern Company and Mississippi Power" herein for information regarding litigation associated with the Kemper County energy facility.

 Plant Daniel
 In conjunction with Southern Company's 2019 sale of Gulf Power, NextEra Energy held back $ 75 million of the purchase price pending Mississippi Power and NextEra Energy negotiating a mutually acceptable revised operating agreement for Plant Daniel. In July 2022, the co-owners executed a revised operating agreement and Southern Company subsequently received the remaining $ 75 million of the purchase price. The dispatch procedures in the revised operating agreement for the two jointly-owned coal units
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 at Plant Daniel resulted in Mississippi Power designating one of the two units as primary and the other as secondary in lieu of each company separately owning 100 % of a single generating unit. Mississippi Power did not exercise an option to purchase its co-owner's ownership interest for $ 1 on January 15, 2024. The revised operating agreement did not have a material impact on Mississippi Power's financial statements. See Note 2 under "Mississippi Power – Integrated Resource Plan" for additional information on Plant Daniel.

 Commitments
 To supply a portion of the fuel requirements of the Southern Company system's electric generating plants, the Southern Company system has entered into various long-term commitments not recognized on the balance sheets for the procurement and delivery of fossil fuel and, for Alabama Power and Georgia Power, nuclear fuel. The majority of the Registrants' fuel expense for the periods presented was purchased under long-term commitments. Each Registrant expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments.
 Georgia Power has commitments, in the form of capacity purchases, regarding a portion of a 5 % interest in the original cost of Plant Vogtle Units 1 and 2 owned by MEAG Power that are in effect until the later of the retirement of the plant or the latest stated maturity date of MEAG Power's bonds issued to finance such ownership interest. The payments for capacity are required whether or not any capacity is available. Portions of the capacity payments made to MEAG Power for its Plant Vogtle Units 1 and 2 investment relate to costs in excess of Georgia Power's allowed investment for ratemaking purposes. The present value of these portions at the time of the disallowance was written off. Generally, the cost of such capacity is included in purchased power in Southern Company's statements of income and in purchased power, non-affiliates in Georgia Power's statements of income. Georgia Power's capacity payments related to this commitment totaled $ 3 million, $ 4 million, and $ 6 million in 2023, 2022, and 2021, respectively. At December 31, 2023, Georgia Power's estimated long-term obligations related to this commitment totaled $ 39 million, consisting of $ 4 million annually for 2024 and 2025, $ 2 million annually for 2026 through 2028, and $ 25 million thereafter.
 See Note 9 for information regarding PPAs accounted for as leases.

 Southern Company Gas has commitments for pipeline charges, storage capacity, and gas supply, including charges recoverable through natural gas cost recovery mechanisms or, alternatively, billed to marketers selling retail natural gas. Gas supply commitments include amounts for gas commodity purchases associated with Nicor Gas and SouthStar of 38 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2023 and valued at $ 98 million. Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations. Southern Company Gas' expected future contractual obligations for pipeline charges, storage capacity, and gas supply that are not recognized on the balance sheets at December 31, 2023 were as follows:

 Pipeline Charges, Storage Capacity, and Gas Supply

 2024
 $

 2025

 2026

 2027

 2028

 Total
 $
 2,286

 Guarantees
 SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the traditional electric operating companies and Southern Power. Under these agreements, each of the traditional electric operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with each of the traditional electric operating companies to ensure they will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements.
 Alabama Power has guaranteed a $ 100 million principal amount long-term bank loan SEGCO entered into in 2018 and subsequently extended and amended. Georgia Power has agreed to reimburse Alabama Power for the portion of such obligation corresponding to Georgia Power's proportionate ownership of SEGCO's stock if Alabama Power is called upon to make such payment under its guarantee. At December 31, 2023, the capitalization of SEGCO consisted of $ 69 million of equity and $ 100
 II-162

 million of long-term debt that matures in November 2024, on which the annual interest requirement is derived from a variable rate index. SEGCO had no short-term debt outstanding at December 31, 2023. See Note 7 under "SEGCO" for additional information.
 As discussed in Note 9, Alabama Power and Georgia Power have entered into certain residual value guarantees related to railcar leases.

 4. 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 under "Revenues" for additional information on the revenue policies of the Registrants. See Notes 9 and 14 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 periods presented:

 2023

 Retail electric revenues

 $
 7,309
 $
 2,904
 $
 4,105
 $
 $
 —
 $
 —

 5,860
 1,928
 3,624
 —
 —

 3,613
 1,721
 1,558
 —
 —

 Other
 —
 —

 Total retail electric revenues
 16,894
 6,565
 9,378
 —
 —

 Natural gas distribution revenues

 1,981
 —
 —
 —
 —
 1,981

 —
 —
 —
 —

 Transportation
 1,184
 —
 —
 —
 —
 1,184

 —
 —
 —
 —

 Other
 —
 —
 —
 —

 Total natural gas distribution revenues
 4,039
 —
 —
 —
 —
 4,039

 PPA energy revenues
 1,107
 —

 PPA capacity revenues
 —

 Non-PPA revenues
 —

 Total wholesale electric revenues
 1,981
 1,575
 —

 —
 —
 —
 —

 —
 —
 —
 —

 Total natural gas revenues
 —
 —
 —
 —

 1,355
 —

 Total revenue from contracts with customers
 24,828
 7,233
 10,129
 1,462
 1,630
 4,598

 Other revenue sources(a)

 ( 183)
 ( 11)

 $
 25,253
 $
 7,050
 $
 10,118
 $
 1,474
 $
 2,189
 $
 4,702

 II-163

 2022

 Retail electric revenues

 $
 6,604
 $
 2,638
 $
 3,664
 $
 $
 —
 $
 —

 5,369
 1,685
 3,385
 —
 —

 3,764
 1,507
 1,921
 —
 —

 Other
 —
 —

 Total retail electric revenues
 15,839
 5,844
 9,049
 —
 —

 Natural gas distribution revenues

 2,843
 —
 —
 —
 —
 2,843

 —
 —
 —
 —

 Transportation
 1,186
 —
 —
 —
 —
 1,186

 —
 —
 —
 —

 Other
 —
 —
 —
 —

 Total natural gas distribution revenues
 5,218
 —
 —
 —
 —
 5,218

 PPA energy revenues
 2,274
 1,673
 —

 PPA capacity revenues
 —

 Non-PPA revenues
 —

 Total wholesale electric revenues
 3,120
 2,769
 —

 —
 —
 —
 —

 —
 —
 —
 —

 Total other natural gas revenues
 —
 —
 —
 —

 1,077
 —

 Total revenue from contracts with customers
 25,941
 6,921
 9,702
 1,703
 2,805
 5,905

 Other revenue sources(a)

 3,338
 1,882
 ( 9)

 $
 29,279
 $
 7,817
 $
 11,584
 $
 1,694
 $
 3,369
 $
 5,962

 II-164

 2021

 Retail electric revenues

 $
 6,207
 $
 2,467
 $
 3,471
 $
 $
 —
 $
 —

 4,877
 1,600
 3,010
 —
 —

 3,067
 1,386
 1,391
 —
 —

 Other
 —
 —

 Total retail electric revenues
 14,244
 5,470
 7,940
 —
 —

 Natural gas distribution revenues

 1,799
 —
 —
 —
 —
 1,799

 —
 —
 —
 —

 Transportation
 1,038
 —
 —
 —
 —
 1,038

 —
 —
 —
 —

 Other
 —
 —
 —
 —

 Total natural gas distribution revenues
 3,625
 —
 —
 —
 —
 3,625

 PPA energy revenues
 1,122
 —

 PPA capacity revenues
 —

 Non-PPA revenues
 —

 Total wholesale electric revenues
 1,851
 1,575
 —

 Wholesale gas services
 2,168
 —
 —
 —
 —
 2,168

 —
 —
 —
 —

 —
 —
 —
 —

 Total other natural gas revenues
 2,668
 —
 —
 —
 —
 2,668

 1,075
 —

 Total revenue from contracts with customers
 23,463
 6,141
 8,563
 1,282
 1,605
 6,293

 Other revenue sources(a)

 3,349
 1,786

 Other adjustments(b)

 ( 3,699)
 —
 —
 —
 —
 ( 3,699)

 $
 23,113
 $
 6,413
 $
 9,260
 $
 1,322
 $
 2,216
 $
 4,380

 (a)Other revenue sources relate to revenues from customers accounted for as derivatives and leases, alternative revenue programs at Southern Company Gas, and cost recovery mechanisms and revenues (including those related to fuel costs) that meet other scope exceptions for revenues from contracts with customers at the traditional electric operating companies.
 (b)Other adjustments relate to the cost of Southern Company Gas' energy and risk management activities. Wholesale gas services revenues are presented net of the related costs of those activities on the statement of income. See Notes 15 and 16 under "Southern Company Gas" for information on the sale of Sequent and components of wholesale gas services' operating revenues, respectively.
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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 December 31, 2023 and 2022:

 Accounts Receivable

 $
 2,820
 $
 $
 1,011
 $
 $
 $

 3,123
 1,107

 Contract Assets

 $
 $
 $
 $
 —
 $
 —
 $

 —
 —
 —

 Contract Liabilities

 $
 $
 —
 $
 $
 —
 $
 $
 —

 —
 —

 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. 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 $ 59 million had been received at December 31, 2023. These advances have been accounted for as long-term debt on the balance sheets. See Note 1 under "Affiliate Transactions" for additional information regarding the construction contract. At December 31, 2023 and 2022, Southern Company's unregulated distributed generation business had contract assets of $ 91 million and $ 65 million, respectively, and contract liabilities of $ 115 million and $ 32 million, respectively, for outstanding performance obligations.
 Revenues recognized in 2023 and 2022, which were included in contract liabilities at December 31, 2023 and 2022, respectively, were $ 36 million annually for Southern Company and immaterial for the other 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 the traditional electric operating companies and Southern Power, these contracts primarily relate to PPAs whereby electricity and generation capacity are provided to a customer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. For Southern Company Gas, these contracts 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 December 31, 2023 are expected to be recognized as follows:

 2024
 2025
 2026
 2027
 2028

 $
 $
 $
 $
 $
 $
 2,045

 —
 —
 —
 —

 —

 2,041

 —
 —
 —
 —
 —

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 5. PROPERTY, PLANT, AND EQUIPMENT
 Property, plant, and equipment is stated at original cost or fair value at acquisition, as appropriate, less any regulatory disallowances and impairments. Original cost may include: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of equity funds used during construction.
 The Registrants' property, plant, and equipment in service consisted of the following at December 31, 2023 and 2022:

 Electric utilities:

 Generation
 $
 57,325
 $
 16,584
 $
 22,587
 $
 2,909
 $
 14,649
 $
 —

 Transmission
 15,561
 6,152
 8,402
 —
 —

 Distribution
 26,482
 9,775
 15,380
 1,327
 —
 —

 General/other
 6,305
 2,918
 3,001
 —

 Electric utilities' plant in service
 105,673
 35,429
 49,370
 5,523
 14,690
 —

 Natural gas transportation and distribution

 17,798
 —
 —
 —
 —
 17,798

 Storage facilities
 1,565
 —
 —
 —
 —
 1,565

 Other
 1,477
 —
 —
 —
 —
 1,477

 Southern Company Gas plant in service
 20,840
 —
 —
 —
 —
 20,840

 Other plant in service
 1,915
 —
 —
 —
 —
 —

 Total plant in service
 $
 128,428
 $
 35,429
 $
 49,370
 $
 5,523
 $
 14,690
 $
 20,840

 Electric utilities:

 Generation
 $
 51,756
 $
 15,920
 $
 17,755
 $
 2,826
 $
 14,619
 $
 —

 Transmission
 14,201
 5,658
 7,576
 —
 —

 Distribution
 24,200
 9,154
 13,819
 1,228
 —
 —

 General/other
 5,806
 2,740
 2,729
 —

 Electric utilities' plant in service
 95,963
 33,472
 41,879
 5,254
 14,658
 —

 Natural gas transportation and distribution

 16,810
 —
 —
 —
 —
 16,810

 Storage facilities
 1,553
 —
 —
 —
 —
 1,553

 Other
 1,360
 —
 —
 —
 —
 1,360

 Southern Company Gas plant in service
 19,723
 —
 —
 —
 —
 19,723

 Other plant in service
 1,843
 —
 —
 —
 —
 —

 Total plant in service
 $
 117,529
 $
 33,472
 $
 41,879
 $
 5,254
 $
 14,658
 $
 19,723

 The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of nuclear refueling costs and certain maintenance costs including those described below.
 In accordance with orders from their respective state PSCs, Alabama Power and Georgia Power defer nuclear refueling outage operations and maintenance expenses to a regulatory asset when the charges are incurred. Alabama Power amortizes the costs over a subsequent 18 -month period with Plant Farley's fall outage cost amortization beginning in January of the following year and spring outage cost amortization beginning in July of the same year. Georgia Power amortizes its costs over each unit's
 II-167

 operating cycle, or 18 months for Plant Vogtle Units 1, 2, and 3 and 24 months for Plant Hatch Units 1 and 2. Georgia Power's amortization period begins the month the refueling outage starts.
 A portion of Mississippi Power's railway track maintenance costs is charged to fuel stock and recovered through Mississippi Power's fuel clause.
 The portion of Southern Company Gas' non-working gas used to maintain the structural integrity of natural gas storage facilities that is considered to be non-recoverable is depreciated, while the recoverable or retained portion is not depreciated.
 See Note 9 for information on finance lease right-of-use (ROU) assets, net, which are included in property, plant, and equipment.
 The Registrants have deferred certain implementation costs related to cloud hosting arrangements. At December 31, 2023 and 2022, deferred cloud implementation costs, net of amortization, which are generally included in other deferred charges and assets on the Registrants' balance sheets, are as follows:

 Deferred cloud implementation costs, net:

 $
 $
 $
 $
 $
 $

 Once a hosted software is placed into service, the related deferred costs are amortized on a straight-line basis over the remaining expected hosting arrangement term, including any renewal options that are reasonably certain of exercise. The amortization is reflected with the associated cloud hosting fees, which are generally reflected in other operations and maintenance expenses on the Registrants' statements of income. In 2023, amortization of deferred cloud implementation costs recognized was $ 46 million for Southern Company, $ 11 million for Alabama Power, $ 19 million for Georgia Power, $ 8 million for Southern Company Gas, and immaterial for the other Registrants. In 2022, amortization of deferred cloud implementation costs recognized was $ 29 million for Southern Company, $ 8 million for Alabama Power, $ 12 million for Georgia Power, and immaterial for the other Registrants. In 2021, amortization from deferred cloud implementation costs recognized was immaterial for all Registrants.
 See Note 2 under "Regulatory Assets and Liabilities" and "Alabama Power – Software Accounting Order" for information on deferrals of certain other operations and maintenance costs associated with software and cloud computing projects by the traditional electric operating companies and natural gas distribution utilities, as authorized by their respective state PSCs or applicable state regulatory agencies.
 The traditional electric operating companies' and Southern Company Gas' depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates. The approximate rates for 2023, 2022, and 2021 are as follows:

 2023
 2022
 2021

 4.1
 %
 2.7
 %
 2.7
 %

 3.8
 %
 3.3
 %
 3.3
 %

 3.4
 %
 3.4
 %
 3.6
 %

 2.7
 %
 2.7
 %
 2.8
 %

 Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC and/or other applicable state and federal regulatory agencies for the traditional electric operating companies and the natural gas distribution utilities. Effective January 1, 2023, Alabama Power's and Georgia Power's depreciation rates were revised. See Note 2 for additional information.
 When property, plant, and equipment subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the asset are retired when the related property unit is retired.
 II-168

 At December 31, 2023 and 2022, accumulated depreciation for Southern Company and Southern Company Gas consisted of utility plant in service totaling $ 36.6 billion and $ 34.3 billion, respectively, for Southern Company and $ 5.3 billion and $ 5.1 billion, respectively, for Southern Company Gas, as well as other plant in service totaling $ 1.1 billion and $ 1.0 billion, respectively, for Southern Company and $ 210 million and $ 184 million, respectively, for Southern Company Gas. Other plant in service includes the non-utility assets of Southern Company Gas, as well as, for Southern Company, certain other non-utility subsidiaries. Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives. Useful lives for Southern Company Gas's non-utility assets range from five to 12 years for transportation equipment, 30 to 75 years for storage facilities, and up to 75 years for other assets. Useful lives for the assets of Southern Company's other non-utility subsidiaries range up to 30 years.
 Southern Power applies component depreciation, where depreciation is computed principally by the straight-line method over the estimated useful life of the asset. Certain of Southern Power's generation assets related to natural gas-fired facilities are depreciated on a units-of-production basis, using hours or starts, to better match outage and maintenance costs to the usage of, and revenues from, these assets. The primary assets in Southern Power's property, plant, and equipment are generating facilities, which generally have estimated useful lives as follows:

 Southern Power Generating Facility
 Useful life

 Natural gas
 Up to 50 years

 Solar
 Up to 35 years

 Wind
 Up to 35 years

 When Southern Power's depreciable property, plant, and equipment is retired, or otherwise disposed of in the normal course of business, the applicable cost and accumulated depreciation is removed and a gain or loss is recognized in the statements of income. Southern Power reviews its estimated useful lives and salvage values on an ongoing basis. The results of these reviews could result in changes which could have a material impact on Southern Power's net income.
 II-169

 Joint Ownership Agreements
 At December 31, 2023, the Registrants' percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation were as follows:

 Facility (Type)
 Percent
Ownership
 Plant in Service
 Accumulated
Depreciation
 CWIP

 Greene County (natural gas) Units 1 and 2
 60.0
 %
 (a)

 $
 $
 $

 Plant Miller (coal) Units 1 and 2
 91.8
 (b)

 2,156

 Plant Hatch (nuclear) Units 1 and 2

 50.1
 %
 (c)

 $
 1,446
 $
 $

 Plant Vogtle (nuclear) Units 1 and 2
 45.7
 (c)

 3,664
 2,331

 Plant Vogtle (nuclear) Units 3 and 4

 45.7
 (c)(d)

 4,613
 3,232

 Plant Scherer (coal) Units 1 and 2
 8.4
 (c)

 Plant Scherer (coal) Unit 3
 75.0
 (c)

 1,310

 Rocky Mountain (pumped storage)
 25.4
 (e)

 —

 Greene County (natural gas) Units 1 and 2
 40.0
 %
 (a)

 $
 $
 $
 —

 Plant Daniel (coal) Units 1 and 2
 50.0
 (f)

 Dalton Pipeline (natural gas pipeline)
 50.0
 %
 (g)

 $
 $
 $
 —

 (a)Jointly owned by Alabama Power and Mississippi Power and operated and maintained by Alabama Power.
 (b)Jointly owned with PowerSouth and operated and maintained by Alabama Power.
 (c)Georgia Power owns undivided interests in Plants Hatch, Vogtle, and Scherer in varying amounts jointly with one or more of the following entities: OPC, MEAG Power, Dalton, FP&L, and JEA. Georgia Power has been contracted to operate and maintain the plants as agent for the co-owners and is jointly and severally liable for third party claims related to these plants.
 (d)Unit 4 remains under construction. See Note 2 under "Georgia Power – Nuclear Construction" for additional information.
 (e)Jointly owned with OPC, which is the operator of the plant.
 (f)Jointly owned by FP&L and Mississippi Power. In accordance with the operating agreement, Mississippi Power acts as FP&L's agent with respect to the operation and maintenance of these units. See Note 3 under "Other Matters – Mississippi Power – Plant Daniel" for additional information.
 (g)Jointly owned with The Williams Companies, Inc., the Dalton Pipeline is a 115 -mile natural gas pipeline that serves as an extension of the Transcontinental Gas Pipe Line Company, LLC pipeline system into northwest Georgia. Southern Company Gas leases its 50 % undivided ownership for approximately $ 26 million annually through 2042. The lessee is responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC-regulated tariff.
 The Registrants' proportionate share of their jointly-owned facility operating expenses is included in the corresponding operating expenses in the statements of income and each Registrant is responsible for providing its own financing.
 Assets Subject to Lien
 Mississippi Power provides retail service to its largest retail customer, Chevron Products Company (Chevron), at its refinery in Pascagoula, Mississippi through at least 2038 in accordance with agreements approved by the Mississippi PSC. The agreements grant Chevron a security interest in the co-generation assets located at the refinery and owned by Mississippi Power, with a lease receivable balance of $ 147 million at December 31, 2023, that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of Mississippi Power's credit rating to below investment grade by two of the three rating agencies. See Note 9 under "Lessor" for additional information.
 See Note 8 under "Long-term Debt" for information regarding debt secured by certain assets of Georgia Power and Southern Company Gas.
 II-170

 6. ASSET RETIREMENT OBLIGATIONS
 AROs are computed as the present value of the estimated costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The estimated costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. Each traditional electric operating company and natural gas distribution utility has received accounting guidance from its state PSC or applicable state regulatory agency allowing the continued accrual or recovery of other retirement costs for long-lived assets that it does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as regulatory liabilities and amounts to be recovered are reflected in the balance sheets as regulatory assets.
 The ARO liabilities for the traditional electric operating companies primarily relate to facilities that are subject to the CCR Rule and the related state rules, principally ash ponds. In addition, Alabama Power and Georgia Power have retirement obligations related to the decommissioning of nuclear facilities (Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 through 3). See "Nuclear Decommissioning" herein for additional information. Other significant AROs include various landfill sites and asbestos removal for Alabama Power, Georgia Power, and Mississippi Power and gypsum cells and mine reclamation for Mississippi Power. The ARO liability for Southern Power primarily relates to its solar and wind facilities, which are located on long-term land leases requiring the restoration of land at the end of the lease.
 The traditional electric operating companies and Southern Company Gas also have identified other retirement obligations, such as obligations related to certain electric transmission and distribution facilities, certain asbestos-containing material within long-term assets not subject to ongoing repair and maintenance activities, certain wireless communication towers, the disposal of polychlorinated biphenyls in certain transformers, leasehold improvements, equipment on customer property, and property associated with the Southern Company system's rail lines and natural gas pipelines. However, liabilities for the removal of these assets have not been recorded because the settlement timing for certain retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these retirement obligations will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
 Southern Company and the traditional electric operating companies will continue to recognize in their respective statements of income allowed removal costs in accordance with regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability in the balance sheets as ordered by the various state PSCs.
 Details of the AROs included in the balance sheets are as follows:

 Southern Power(*)

 $
 11,687
 $
 4,334
 $
 6,824
 $
 $

 Liabilities incurred
 —
 —
 —

 Liabilities settled
 ( 455)
 ( 205)
 ( 212)
 ( 20)
 —

 Accretion expense

 Cash flow revisions
 ( 834)
 —
 ( 844)

 $
 10,840
 $
 4,287
 $
 6,034
 $
 $

 Liabilities incurred
 —
 —
 —

 Liabilities settled
 ( 617)
 ( 270)
 ( 304)
 ( 18)
 —

 Accretion expense

 Cash flow revisions
 ( 399)
 ( 15)
 ( 385)
 —

 $
 10,317
 $
 4,158
 $
 5,665
 $
 $

 (*)Included in other deferred credits and liabilities on Southern Power's consolidated balance sheets.
 II-171

 In December 2022, Georgia Power recorded a net decrease of approximately $ 780 million to its AROs related to the CCR Rule and the related state rule resulting from changes in estimates, including lower future inflation rates, higher discount rates, and timing of closure activities, as well as a change in closure methodology for one ash pond as approved in Georgia Power's 2022 IRP.
 Following initial criticality for Plant Vogtle Unit 3 on March 6, 2023, Georgia Power recorded AROs of approximately $ 90 million. Subsequent to December 31, 2023, Plant Vogtle Unit 4 achieved initial criticality, which will result in Georgia Power recording AROs of approximately $ 118 million during the first quarter 2024. See Note 2 under "Georgia Power – Nuclear Construction" for additional information.
 In September 2023 and November 2023, Georgia Power recorded net decreases of approximately $ 175 million and $ 210 million, respectively, 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.
 The cost estimates for AROs related to the disposal of CCR are based on information at December 31, 2023 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule and the related 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 these assumptions becomes available. Some of these updates have been, and future updates may be, material. The cost estimates for Alabama Power are based on closure-in-place for all ash ponds. The cost estimates for Georgia Power and Mississippi Power are based on a combination of closure-in-place for some ash ponds and closure by removal for others. 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. The ultimate outcome of these matters cannot be determined at this time. See Note 3 under "General Litigation Matters – Alabama Power" for additional information.
 Nuclear Decommissioning
 The NRC requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (Funds) to comply with the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and state PSCs, as well as the IRS. While Alabama Power and Georgia Power are allowed to prescribe an overall investment policy to the Funds' managers, neither Southern Company nor its subsidiaries or affiliates are allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third-party managers with oversight by the management of Alabama Power and Georgia Power. The Funds' managers are authorized, within certain investment guidelines, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds' investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities.
 Alabama Power and Georgia Power record the investment securities held in the Funds at fair value, as disclosed in Note 13, as management believes that fair value best represents the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for AROs in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis.
 II-172

 Investment securities in the Funds for December 31, 2023 and 2022 were as follows:

Power
Power

 Equity securities
 $
 1,288
 $
 $

 Debt securities

 Other securities

 Total investment securities in the Funds
 $
 2,422
 $
 1,259
 $
 1,163

 Equity securities
 $
 1,095
 $
 $

 Debt securities

 Other securities

 Total investment securities in the Funds(*)

 $
 2,143
 $
 1,125
 $
 1,018

 (*)For Southern Company and Georgia Power, these amounts include investment securities pledged to creditors and collateral received and excludes payables related to a securities lending program Georgia Power's Funds previously participated in through the managers of the Funds. Under this program, Georgia Power's Funds' investment securities were loaned to institutional investors for a fee. Securities loaned were fully collateralized by cash, letters of credit, and/or securities issued or guaranteed by the U.S. government or its agencies or instrumentalities. At December 31, 2022, approximately $ 35 million of the fair market value of Georgia Power's Funds' securities were on loan and pledged to creditors under the Funds' managers' securities lending program. At December 31, 2022, the fair value of the collateral received was approximately $ 36 million and could only be sold by the borrower upon the return of the loaned securities. The collateral received was treated as a non-cash item in the statements of cash flows.
 These amounts exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases.
 The fair value increases (decreases) of the Funds, including unrealized gains (losses) and reinvested interest and dividends and excluding the Funds' expenses, for 2023, 2022, and 2021 are shown in the table below.

Power
Power

 Fair value increases (decreases)

 2023
 $
 $
 $

 2022
 ( 360)
 ( 171)
 ( 189)

 2021

 Unrealized gains (losses)

 $
 $
 $

 ( 391)
 ( 187)

 At December 31, 2021
 ( 27)
 ( 30)

 The investment securities held in the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired.
 For Alabama Power, approximately $ 13 million and $ 14 million at December 31, 2023 and 2022, respectively, previously recorded in internal reserves is being transferred into the Funds through 2040 as approved by the Alabama PSC.
 The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC.
 II-173

 At December 31, 2023 and 2022, the accumulated provisions for the external decommissioning trust funds were as follows:

 2023
 2022

 Plant Farley
 $
 1,259
 $
 1,125

 Plant Hatch
 $
 $

 Plant Vogtle Units 1 and 2

 Plant Vogtle Units 3 and 4

 Total
 $
 1,163
 $
 1,018

 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 at December 31, 2023 based on the most current studies were as follows:

 Plant
Farley
 Plant
 Hatch(*)

 Plant Vogtle
 Units 1 and 2(*)

 Plant Vogtle
 Unit 3(*)

 Most current study year

 2023
 2021
 2021
 2020

 Decommissioning periods:

 Beginning year
 2037
 2034
 2047
 2063

 Completion year
 2087
 2075
 2079
 2074

 Site study costs:

 Radiated structures
 $
 1,402
 $
 $
 $

 Spent fuel management

 Non-radiated structures

 Total site study costs
 $
 2,048
 $
 1,018
 $
 $

 (*)Based on Georgia Power's ownership interests.
 For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study and Georgia Power's decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities and the site study estimate for spent fuel management. Significant assumptions used to determine these costs for ratemaking were an estimated inflation rate of 4.5 % for Plant Farley, 2.5 % for Plants Hatch and Vogtle Units 1 and 2, and 2.4 % for Plant Vogtle Unit 3 and an estimated trust earnings rate of 7.0 % for Plant Farley, 4.5 % for Plants Hatch and Vogtle Units 1 and 2, and 4.4 % for Plant Vogtle Unit 3.
 Amounts previously contributed to the Funds for Plant Farley are currently projected to be adequate to meet the 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 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.
 Under the 2019 ARP, Georgia Power's annual decommissioning cost for ratemaking in 2021 and 2022 was a total of $ 4 million for Plant Hatch and Plant Vogtle Units 1 and 2. Effective January 1, 2023, as approved in the 2022 ARP, there is no annual decommissioning cost for ratemaking for Plant Hatch and Plant Vogtle Units 1 and 2. Any funding amount required by the NRC during the period covered by the 2022 ARP will be deferred to a regulatory asset and recovery is expected to be determined in Georgia Power's next base rate case. See Note 2 under "Georgia Power – Rate Plans – 2022 ARP" for additional information. Effective August 1, 2023, as approved under the Plant Vogtle Unit 3 and Common Facilities rate proceeding, Georgia Power's
 II-174

 annual decommissioning cost for ratemaking is $ 8 million for Plant Vogtle Unit 3. See Note 2 under "Georgia Power – Nuclear Construction – Regulatory Matters" for additional information.

 7. CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS
 The Registrants may hold ownership interests in a number of business ventures with varying ownership structures. Partnership interests and other variable interests are evaluated to determine if each entity is a VIE. If a venture is a VIE for which a Registrant is the primary beneficiary, the assets, liabilities, and results of operations of the entity are consolidated. The Registrants reassess the conclusion as to whether an entity is a VIE upon certain occurrences, which are deemed reconsideration events.
 For entities that are not determined to be VIEs, the Registrants evaluate whether they have control or significant influence over the investee to determine the appropriate consolidation and presentation. Generally, entities under the control of a Registrant are consolidated, and entities over which a Registrant can exert significant influence, but which a Registrant does not control, are accounted for under the equity method of accounting.
 Investments accounted for under the equity method are recorded within equity investments in unconsolidated subsidiaries in the balance sheets and, for Southern Company and Southern Company Gas, the equity income is recorded within earnings from equity method investments in the statements of income. See "SEGCO" and "Southern Company Gas" herein for additional information.
 At December 31, 2023 and 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.

 SEGCO
 Alabama Power and Georgia Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units at Plant Gaston with a total rated capacity of 1,020 MWs, as well as associated transmission facilities. Retirement of SEGCO's generating units is currently expected to occur by December 31, 2028. However, Alabama Power, in conjunction with Georgia Power, is evaluating extending the operation of Plant Gaston Units 1 through 4 beyond the indicated retirement date. See Note 2 under "Georgia Power – Integrated Resource Plans" for additional information. Alabama Power and Georgia Power account for SEGCO using the equity method; Southern Company consolidates SEGCO. The capacity of these units is sold equally to Alabama Power and Georgia Power. Alabama Power and Georgia Power make payments sufficient to provide for the operating expenses, taxes, interest expense, and a ROE. The share of purchased power included in purchased power, affiliates in the statements of income totaled $ 112 million in 2023, $ 124 million in 2022, and $ 75 million in 2021 for Alabama Power and $ 115 million in 2023, $ 127 million in 2022, and $ 77 million in 2021 for Georgia Power.
 SEGCO paid dividends of $ 25 million in 2023, $ 14 million in 2022, and $ 14 million in 2021, one half of which were paid to each of Alabama Power and Georgia Power. In addition, Alabama Power and Georgia Power each recognize 50 % of SEGCO's net income.
 Alabama Power, which owns and operates a generating unit adjacent to the SEGCO generating units, has a joint ownership agreement with SEGCO for the ownership of an associated gas pipeline. Alabama Power owns 14 % of the pipeline with the remaining 86 % owned by SEGCO.
 See Note 3 under "Guarantees" for additional information regarding guarantees of Alabama Power and Georgia Power related to SEGCO.

 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
 SP Solar is owned by Southern Power and a limited partner. A wholly-owned subsidiary of Southern Power is the general partner and holds a 1 % ownership interest, and another wholly-owned subsidiary of Southern Power owns a 66 % ownership interest. The limited partner holds the remaining 33 % noncontrolling interest. SP Solar qualifies as a VIE since the arrangement is structured as a limited partnership and the 33 % limited partner does not have substantive kick-out rights against the general partner.
 II-175

 At December 31, 2023 and 2022, SP Solar had total assets of $ 5.6 billion and $ 5.9 billion, respectively, total liabilities of $ 0.4 billion, and noncontrolling interests of $ 1.0 billion and $ 1.1 billion, respectively. 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.
 SP Wind is owned by Southern Power and three financial investors. A wholly-owned subsidiary of Southern Power owns 100 % of the Class B membership interests and the three financial investors own 100% of the Class A membership interests. SP Wind qualifies as a VIE since the structure of the arrangement is similar to a limited partnership and the Class A members do not have substantive kick-out rights against Southern Power.
 At December 31, 2023 and 2022, SP Wind had total assets of $ 2.1 billion and $ 2.2 billion, respectively, total liabilities of $ 187 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 December 31, 2023 and 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
 During 2023 and 2022, Southern Power sold its remaining equity method investments in wind projects and received proceeds totaling $ 50 million and $ 38 million, respectively. Earnings (loss) from these investments, including the gains associated with the sales, were immaterial for all periods presented.
 II-176

 Equity Method Investments
 The carrying amounts of Southern Company Gas' equity method investments at December 31, 2023 and 2022 and related earnings (loss) from those investments for the years ended December 31, 2023, 2022, and 2021 were as follows:

 Investment Balance
 December 31, 2022

 SNG
 $
 1,202
 $
 1,243

 Other

 Total
 $
 1,235
 $
 1,276

 Earnings (Loss) from Equity Method Investments
 2023
 2022
 2021

 SNG
 $
 $
 $

 PennEast Pipeline(*)

 —
 —
 ( 81)

 Other

 Total
 $
 $
 $

 (*)For 2021, includes pre-tax impairment charges totaling $ 84 million. See "PennEast Pipeline Project" herein for additional information, including the September 2021 cancellation of the project.
 PennEast Pipeline Project
 In 2014, Southern Company Gas entered into a partnership in which it holds a 20 % ownership interest in the PennEast Pipeline, an interstate pipeline company formed to develop and operate an approximate 118 -mile natural gas pipeline between New Jersey and Pennsylvania. In 2019, an appellate court ruled that the PennEast Pipeline does not have federal eminent domain authority over lands in which a state has property rights interests. In June 2021, the U.S. Supreme Court ruled in favor of PennEast Pipeline following a review of the appellate court decision. Southern Company Gas assesses its equity method investments for impairment whenever events or changes in circumstances indicate that the investment may be impaired. Following the U.S. Supreme Court ruling, during the second quarter 2021, Southern Company Gas management reassessed the project construction timing, including the anticipated timing for receipt of a FERC certificate and all remaining state and local permits, as well as potential challenges thereto, and performed an impairment analysis. The outcome of the analysis resulted in a pre-tax impairment charge of $ 82 million ($ 58 million after tax). In September 2021, PennEast Pipeline announced that further development of the project was no longer supported, and, as a result, all further development of the project ceased. During the third quarter 2021, Southern Company Gas recorded an additional pre-tax charge of $ 2 million ($ 2 million after tax) related to its share of the project level impairment, as well as $ 7 million of additional tax expense, resulting in total pre-tax charges of $ 84 million ($ 67 million after tax) during 2021 related to the project.
 II-177

 8. FINANCING

 Long-term Debt
 Details of long-term debt at December 31, 2023 and 2022 are provided in the following table:

 Balance Outstanding at
December 31,

 Maturity
 2023
 2022

 Senior notes(a)

 2024-2073
 4.16 %
 $
 40,235
 $
 35,683

 Junior subordinated notes
 2024-2081
 4.33 %
 8,333
 8,836

 FFB loans(b)

 2024-2044
 2.88 %
 4,788
 4,874

 Revenue bonds(c)

 2024-2063
 3.77 %
 3,400
 2,844

 First mortgage bonds(d)

 2025-2063
 3.64 %
 2,500
 2,275

 Medium-term notes
 2026-2027
 7.03 %

 2024-2045
 5.44 %

 Finance lease obligations(e)

 Unamortized fair value adjustment

 ( 193)

 ( 290)
 ( 273)

 59,686
 54,941

 2,476
 4,285

 $
 57,210
 $
 50,656

 2025-2073
 3.95 %
 $
 9,875
 $
 9,675

 Revenue bonds(c)

 2024-2063
 3.94 %
 1,321

 2026-2030
 7.04 %

 Finance lease obligations(e)

 ( 20)
 ( 18)

 ( 73)
 ( 72)

 11,183
 10,630

 $
 10,960
 $
 10,329

 2024-2052
 4.34 %
 $
 9,575
 $
 7,925

 Junior subordinated notes
 2077
 5.00 %

 FFB loans(b)

 2024-2044
 2.88 %
 4,788
 4,874

 Revenue bonds(c)

 2025-2062
 3.64 %
 1,968
 1,738

 Finance lease obligations(e)

 ( 19)
 ( 18)

 ( 122)
 ( 117)

 16,700
 14,910

 $
 16,198
 $
 14,009

 II-178

 Balance Outstanding at
December 31,

 Maturity
 2023
 2022

 2024-2051
 4.27 %
 $
 1,525
 $
 1,425

 Revenue bonds(c)

 2025-2052
 4.08 %

 Finance lease obligations(e)

 ( 9)
 ( 10)

 1,644
 1,545

 $
 1,443
 $
 1,544

 Senior notes(a)

 2025-2046
 4.05 %
 $
 2,728
 $
 2,998

 ( 4)
 ( 5)

 ( 13)
 ( 14)

 2,711
 2,979

 —

 $
 2,711
 $
 2,689

 2025-2051
 4.36 %
 $
 4,930
 $
 4,769

 First mortgage bonds(d)

 2025-2063
 3.64 %
 2,500
 2,275

 Medium-term notes
 2026-2027
 7.03 %

 2024-2045
 3.81 %

 Unamortized fair value adjustment

 ( 8)
 ( 8)

 ( 34)
 ( 30)

 7,833
 7,442

 —

 $
 7,833
 $
 7,042

 (a)Includes a fair value gain (loss) of $( 12) million and $( 31) million at December 31, 2023 and 2022, respectively, related to Southern Power's foreign currency hedge on its euro-denominated senior notes.
 (b)Secured by a first priority lien on (i) Georgia Power's undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. See "DOE Loan Guarantee Borrowings" herein for additional information.
 (c)Revenue bond obligations represent loans to the traditional electric operating companies from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal and wastewater facilities. In some cases, the revenue bond obligations represent obligations under installment sales agreements with respect to facilities constructed with the proceeds of revenue bonds issued by public authorities. The traditional electric operating companies are required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. Proceeds from certain issuances are restricted until qualifying expenditures are incurred.
 (d)Secured by substantially all of Nicor Gas' properties.
 (e)Secured by the underlying lease ROU asset. See Note 9 for additional information.
 II-179

 Maturities of long-term debt for the next five years are as follows:

 Southern Company(a)

 Alabama Power(b)

 Power(c)

 Southern Power(d)

Gas

 2024
 $
 2,480
 $
 $
 $
 $
 —
 $
 —

 2025
 4,124

 2026
 3,791

 2027
 2,075
 —

 2028
 2,612
 —

 (a)See notes (b) and (c) below.
 (b)Alabama Power's 2024 maturities include $ 200 million aggregate principal amount of Series 2023A Floating Rate Senior Notes due May 15, 2073 that are repayable at the option of the holders at certain dates beginning in 2024. As a result, the senior notes are classified as securities due within one year on the balance sheets of Southern Company and Alabama Power at December 31, 2023.
 (c)Amounts include principal amortization related to the FFB borrowings; however, the final maturity date is February 20, 2044. See "DOE Loan Guarantee Borrowings" herein for additional information.
 (d)Southern Power's 2026 maturities include $ 564 million of euro-denominated debt at the U.S. dollar denominated hedge settlement amount.

 DOE Loan Guarantee Borrowings
 Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), Georgia Power and the DOE entered into a loan guarantee agreement in 2014 and the Amended and Restated Loan Guarantee Agreement in 2019. Under the Amended and Restated Loan Guarantee Agreement, the DOE agreed to guarantee the obligations of Georgia Power under the FFB Credit Facilities. Under the FFB Credit Facilities, Georgia Power was authorized to make term loan borrowings through the FFB in an amount up to approximately $ 5.130 billion, provided that total aggregate borrowings under the FFB Credit Facilities could not exceed 70 % of (i) Eligible Project Costs minus (ii) approximately $ 1.492 billion (reflecting the amounts received by Georgia Power under the Guarantee Settlement Agreement less the related customer refunds).
 In 2021, Georgia Power made the final borrowings under the FFB Credit Facilities and no further borrowings are permitted. During 2023, Georgia Power made principal amortization payments of $ 86 million under the FFB Credit Facilities. At December 31, 2023 and 2022, Georgia Power had $ 4.8 billion and $ 4.9 billion of borrowings outstanding under the FFB Credit Facilities, respectively.
 All borrowings under the FFB Credit Facilities are full recourse to Georgia Power, and Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under its guarantee. Georgia Power's reimbursement obligations to the DOE are full recourse and secured by a first priority lien on (i) Georgia Power's undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on Georgia Power's ability to grant liens on other property.
 The final maturity date for each advance under the FFB Credit Facilities is February 20, 2044. Interest is payable quarterly and principal payments began in 2020. Each borrowing under the FFB Credit Facilities bears interest at a fixed rate equal to the applicable U.S. Treasury rate at the time of the borrowing plus a spread equal to 0.375 %.
 Under the Amended and Restated Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default.
 In the event certain mandatory prepayment events occur, Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facilities over a period of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle Services Agreement or rejection of the Vogtle Services Agreement in any Westinghouse bankruptcy if Georgia Power does not maintain access to intellectual property rights under the related intellectual property licenses; (ii) termination of the Bechtel Agreement by Bechtel or in connection with a cancellation of Plant Vogtle Units 3 and 4, unless the Vogtle Owners enter into a replacement agreement; (iii) cancellation of Plant Vogtle Unit 4 by the Georgia PSC or by Georgia Power; (iv) failure of the holders of 90 % of the ownership interests in Plant Vogtle Units 3 and 4 to vote to continue construction following certain schedule extensions; (v) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Unit 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facilities; or (vi) loss of or failure to receive necessary regulatory approvals.
 II-180

 Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facilities. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facilities. Under the FFB Credit Facilities, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.
 In connection with any cancellation of Plant Vogtle Unit 4, the DOE may elect to continue construction of Plant Vogtle Unit 4. In such an event, the DOE will have the right to assume Georgia Power's rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of Georgia Power's ownership interest in Plant Vogtle Units 3 and 4.
 See Note 2 under "Georgia Power – Nuclear Construction" for additional information.

 Secured Debt
 Each of Southern Company's subsidiaries is organized as a legal entity, separate and apart from Southern Company and its other subsidiaries. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its other subsidiaries.
 As discussed under "Long-term Debt" herein, the Registrants had secured debt outstanding at December 31, 2023 and 2022. Each Registrant's senior notes, junior subordinated notes, revenue bond obligations, bank term loans, credit facility borrowings, and notes payable are effectively subordinated to all secured debt of each respective Registrant.

 Equity Units
 In May 2022, Southern Company remarketed $ 862.5 million aggregate principal amount of its Series 2019A Remarketable Junior Subordinated Notes due August 1, 2024 (2019A RSNs) and $ 862.5 million aggregate principal amount of its Series 2019B Remarketable Junior Subordinated Notes due August 1, 2027 (2019B RSNs), pursuant to the terms of its 2019 Series A Equity Units (Equity Units). In connection with the remarketing, the interest rates on the 2019A RSNs and the 2019B RSNs were reset to 4.475 % and 5.113 %, respectively, payable on a semi-annual basis. In August 2022, the proceeds were ultimately used to settle the purchase contracts entered into as part of the Equity Units and Southern Company issued approximately 25.2 million shares of common stock and received proceeds of $ 1.725 billion. At December 31, 2023 and 2022, the 2019A RSNs and the 2019B RSNs are included on Southern Company's consolidated balance sheets in long-term debt or, as applicable, securities due within one year.
 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.
 II-181

 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.

 Bank Credit Arrangements
 At December 31, 2023, committed credit arrangements with banks were as follows:

 Expires

 2024
 2025
 2026
 2028
 Total
 Unused
 Expires within
 One Year

 Southern Company parent(a)

 $
 $
 —
 $
 —
 $
 1,850
 $
 2,000
 $
 1,998
 $

 —
 —
 1,350
 1,350
 —

 —
 —
 —
 1,750
 1,750
 1,726
 —

 —
 —
 —

 Southern Power(a)(b)

 —
 —
 —
 —

 Southern Company Gas(c)

 —
 —
 1,500
 1,600
 1,598

 SEGCO
 —
 —
 —

 $
 $
 $
 $
 6,400
 $
 7,605
 $
 7,566
 $

 (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 $ 8 million and $ 7 million, respectively, was unused at December 31, 2023. 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. See "Structural Considerations" herein for additional information.
 The bank credit arrangements require payment of commitment fees based on the unused portion of the commitments. Commitment fees average less than 1/4 of 1% for the Registrants and Nicor Gas. 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
 II-182

 accelerated. Southern Company's, certain of Mississippi Power's, Southern Company Gas', and Nicor Gas' credit arrangements contain covenants that limit debt levels to 70 % of total capitalization, as defined in the agreements, and the other subsidiaries' bank credit arrangements contain covenants that limit debt levels to 65 % of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes junior subordinated notes and, in certain arrangements, other hybrid securities. Additionally, for Southern Company and Southern Power, for purposes of these definitions, debt excludes any project debt incurred by certain subsidiaries of Southern Power to the extent such debt is non-recourse to Southern Power and capitalization excludes the capital stock or other equity attributable to such subsidiaries. At December 31, 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 December 31, 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 December 31, 2023, Georgia Power had approximately $ 325 million 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.
 At both December 31, 2023 and 2022, Southern Power had $ 106 million of cash collateral posted related to PPA requirements, which is included in other deferred charges and assets on Southern Power's consolidated balance sheets.

 Notes Payable
 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 under "Bank Credit Arrangements." Southern Power's subsidiaries are not parties or obligors to its commercial paper program. Southern Company Gas maintains commercial paper programs at Southern Company Gas Capital and at Nicor Gas. Nicor Gas' commercial paper program supports working capital needs at Nicor Gas as Nicor Gas is not permitted to make money pool loans to affiliates. All of Southern Company Gas' other subsidiaries benefit from Southern Company Gas Capital's commercial paper program. See "Structural Considerations" herein for additional information.
 In addition, Southern Company and certain of its subsidiaries have entered into various bank term loan agreements. Unless otherwise stated, the proceeds of these loans were used to repay existing indebtedness and for general corporate purposes, including working capital and, for the subsidiaries, their continuous construction programs.
 II-183

 Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. Details of short-term borrowings for the applicable Registrants were as follows:

 Notes Payable at December 31, 2023

 Notes Payable at December 31, 2022

 Amount
Outstanding
 Amount
Outstanding

 Commercial paper
 $
 1,794
 5.6
 %
 $
 4.7
 %

 Short-term bank debt
 6.4
 %
 1,800
 5.0
 %

 Total
 $
 2,314
 5.7
 %
 $
 2,609
 4.9
 %

 Commercial paper

 $
 5.5
 %
 $
 —
 —
 %

 Commercial paper
 $
 5.6
 %
 $
 —
 —
 %

 Short-term bank debt
 6.4
 %
 1,600
 5.0
 %

 Total
 $
 1,329
 5.9
 %
 $
 1,600
 5.0
 %

 Commercial paper
 $
 5.5
 %
 $
 4.7
 %

 Commercial paper:

 Southern Company Gas Capital
 $
 5.5
 %
 $
 4.8
 %

 5.5
 %
 4.6
 %

 Short-term bank debt:

 —
 —
 %
 4.9
 %

 Total
 $
 5.5
 %
 $
 4.7
 %

 See "Bank Credit Arrangements" herein for information on bank term loan covenants that limit debt levels and cross-acceleration or cross-default provisions.

 Outstanding Classes of Capital Stock

 Stock Issued
 During 2023, Southern Company issued approximately 2.1 million shares of common stock primarily through equity compensation plans and received proceeds of approximately $ 36 million.
 Shares Reserved
 At December 31, 2023, a total of 131 million shares were reserved for issuance pursuant to the Southern Investment Plan, employee savings plans, the Equity and Incentive Compensation Plan (which includes stock options and performance share units as discussed in Note 12), an at-the-market program, and the Series 2023A Convertible Senior Notes (as discussed under "Convertible Senior Notes" herein). Of the shares reserved, 26.9 million shares are available for awards under the Equity and Incentive Compensation Plan at December 31, 2023.
 Diluted 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
 II-184

 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 and "Convertible Senior Notes" herein for additional information. Shares used to compute diluted EPS were as follows:

 Average Common Stock Shares

 2023
 2022
 2021

 As reported shares
 1,092
 1,075
 1,061

 Effect of stock-based compensation

 Diluted shares
 1,098
 1,081
 1,068

 For 2023, there were no anti-dilutive shares. For 2022 and 2021, 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.
 Preferred Stock of Subsidiaries
 As discussed further under "Alabama Power" herein, during 2022, Alabama Power redeemed all of its preferred stock and Class A preferred stock.

 Alabama Power has preferred stock, Class A preferred stock, preference stock, and common stock authorized, but only common stock outstanding at December 31, 2023.
 During 2022, Alabama Power redeemed all of its preferred stock and Class A preferred stock at the redemption prices per share provided in the table below, plus accrued and unpaid dividends to the redemption date.

 Preferred Stock Redeemed During 2022
 Par Value/Stated Capital Per Share
 Shares
 Redemption
Price Per Share

 4.92 % Preferred Stock

 $ 100
 80,000
 $ 103.23

 4.72 % Preferred Stock

 $ 100
 50,000
 $ 102.18

 4.64 % Preferred Stock

 $ 100
 60,000
 $ 103.14

 4.60 % Preferred Stock

 $ 100
 100,000
 $ 104.20

 4.52 % Preferred Stock

 $ 100
 50,000
 $ 102.93

 4.20 % Preferred Stock

 $ 100
 135,115
 $ 105.00

 5.00 % Class A Preferred Stock

 $ 25
 10,000,000
 $ 25.00

 Georgia Power has preferred stock, Class A preferred stock, preference stock, and common stock authorized, but only common stock outstanding.

 Mississippi Power has preferred stock and common stock authorized, but only common stock outstanding.

 Dividend Restrictions
 The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2023, consolidated retained earnings included $ 5.5 billion of undistributed retained earnings of the subsidiaries.
 The traditional electric operating companies and Southern Power can only pay dividends to Southern Company out of retained earnings or paid-in-capital.
 See Note 7 under "Southern Power" for information regarding the distribution requirements for certain Southern Power subsidiaries.
 II-185

 By regulation, Nicor Gas is restricted, up to 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 December 31, 2023, the amount of Southern Company Gas' subsidiary retained earnings available for dividend payment totaled $ 1.7 billion.
 Structural Considerations
 Since Southern Company and Southern Company Gas are holding companies, the right of Southern Company and Southern Company Gas and, hence, the right of creditors of Southern Company or Southern Company Gas to participate in any distribution of the assets of any respective subsidiary of Southern Company or Southern Company Gas, whether upon liquidation, reorganization or otherwise, is subject to prior claims of creditors and preferred stockholders of such subsidiary.
 Southern Company Gas' 100 %-owned subsidiary, Southern Company Gas Capital, was established to provide for certain of Southern Company Gas' ongoing financing needs through a commercial paper program, the issuance of various debt, hybrid securities, and other financing arrangements. Southern Company Gas fully and unconditionally guarantees all debt issued by Southern Company Gas Capital. Nicor Gas is not permitted by regulation to make loans to affiliates or utilize Southern Company Gas Capital for its financing needs.
 Southern Power Company's senior notes, bank term loan, commercial paper, and bank credit arrangement are unsecured senior indebtedness, which rank equally with all other unsecured and unsubordinated debt of Southern Power Company. Southern Power's subsidiaries are not issuers, borrowers, or obligors, as applicable, under any of these unsecured senior debt arrangements, which are effectively subordinated to any future secured debt of Southern Power Company and any potential claims of creditors of Southern Power's subsidiaries.
 II-186

 9. LEASES
 Lessee
 The Registrants recognize leases with a term of greater than 12 months on the balance sheet as lease obligations, representing the discounted future fixed payments due, along with ROU assets that will be amortized over the term of each lease.
 As lessee, the Registrants lease certain electric generating units (including renewable energy facilities), real estate/land, communication towers, railcars, and other equipment and vehicles. The major categories of lease obligations are as follows:

Power
Power
Power

 Electric generating units(*)

 $
 $
 $
 1,028
 $
 —
 $
 —
 $
 —

 Real estate/land

 Communication towers
 —
 —

 Railcars
 —
 —

 Other
 —
 —

 Total
 $
 1,788
 $
 $
 1,115
 $
 $
 $

 Electric generating units(*)

 $
 $
 $
 1,163
 $
 —
 $
 —
 $
 —

 Real estate/land

 Communication towers
 —
 —

 Railcars
 —
 —

 Other
 —

 Total
 $
 1,899
 $
 $
 1,240
 $
 $
 $

 (*)Amounts related to affiliate leases are eliminated in consolidation for Southern Company. See "Contracts that Contain a Lease" herein for additional information.
 Real estate/land leases primarily consist of commercial real estate leases at Southern Company, Georgia Power, and Southern Company Gas and various land leases primarily associated with renewable energy facilities at Southern Power. The commercial real estate leases have remaining terms of up to 27 years while the land leases have remaining terms of up to 44 years, including renewal periods.
 Communication towers are leased for the installation of equipment to provide cellular phone service to customers and to support the automated meter infrastructure programs at the traditional electric operating companies and Nicor Gas. Communication tower leases have remaining terms of up to 17 years.
 Renewal options exist in many of the leases. The expected term used in calculating the lease obligation generally reflects only the noncancelable period of the lease unless it is considered reasonably certain that the lease will be extended. Land leases associated with renewable energy facilities at Southern Power and communication tower leases for automated meter infrastructure at Nicor Gas include renewal periods reasonably certain of exercise resulting in an expected lease term at least equal to the expected life of the renewable energy facilities and the automated meter infrastructure, respectively.
 Contracts that Contain a Lease
 While not specifically structured as a lease, some of the PPAs at Alabama Power and Georgia Power are deemed to represent a lease of the underlying electric generating units when the terms of the PPA convey the right to control the use of the underlying assets. Amounts recorded for leases of electric generating units are generally based on the amount of scheduled capacity payments due over the remaining term of the PPA, which varies between one and 16 years. Georgia Power has several PPAs with Southern Power that Georgia Power accounts for as leases with a lease obligation of $ 416 million and $ 461 million at December 31, 2023 and 2022, respectively. The amount paid for energy under these affiliate PPAs reflects a price that would be paid in an arm's-length transaction as reviewed and approved by the Georgia PSC. Amounts related to the affiliate PPAs are eliminated in consolidation for Southern Company.
 II-187

 Short-term Leases
 Leases with an initial term of 12 months or less are not recorded on the balance sheet; the Registrants generally recognize lease expense for these leases on a straight-line basis over the lease term.
 Residual Value Guarantees
 Residual value guarantees exist primarily in railcar leases at Alabama Power and Georgia Power and the amounts probable of being paid under those guarantees are included in the lease payments. All such amounts are immaterial at December 31, 2023 and 2022.
 Lease and Nonlease Components
 For all asset categories, with the exception of electric generating units, gas pipelines, and real estate leases, the Registrants combine lease payments and any nonlease components, such as asset maintenance, for purposes of calculating the lease obligation and the right-of-use asset.
 Balance sheet amounts recorded for operating and finance leases are as follows:

Power
Power
Power

 Operating Leases

 Operating lease ROU assets, net
 $
 1,432
 $
 $
 $
 $
 $

 Operating lease obligations - current
 $
 $
 $
 $
 $
 $

 Operating lease obligations - non-current
 1,307

 Total operating lease obligations(*)

 $
 1,490
 $
 $
 $
 $
 $

 Finance Leases

 Finance lease ROU assets, net
 $
 $
 $
 $
 $
 —
 $
 —

 Finance lease obligations - current
 $
 $
 $
 $
 $
 —
 $
 —

 Finance lease obligations - non-current
 —
 —

 Total finance lease obligations
 $
 $
 $
 $
 $
 —
 $
 —

 Operating Leases

 Operating lease ROU assets, net
 $
 1,531
 $
 $
 1,007
 $
 $
 $

 Operating lease obligations - current
 $
 $
 $
 $
 $
 $

 Operating lease obligations - non-current
 1,388

 Total operating lease obligations(*)

 $
 1,585
 $
 $
 1,002
 $
 $
 $

 Finance Leases

 Finance lease ROU assets, net
 $
 $
 $
 $
 $
 —
 $
 —

 Finance lease obligations - current
 $
 $
 $
 $
 $
 —
 $
 —

 Finance lease obligations - non-current
 —
 —

 Total finance lease obligations
 $
 $
 $
 $
 $
 —
 $
 —

 (*)Includes operating lease obligations related to PPAs at Southern Company, Alabama Power, and Georgia Power totaling $ 566 million, $ 58 million, and $ 813 million, respectively, at December 31, 2023 and $ 652 million, $ 59 million, and $ 952 million, respectively, at December 31, 2022.
 If not presented separately on the Registrants' balance sheets, amounts related to leases are presented as follows: operating lease ROU assets, net are included in "other deferred charges and assets"; operating lease obligations are included in "other current liabilities" and "other deferred credits and liabilities," as applicable; finance lease ROU assets, net are included in "plant in service"; and finance lease obligations are included in "securities due within one year" and "long-term debt," as applicable.
 II-188

 Lease costs for 2023, 2022, and 2021, which includes both amounts recognized as operations and maintenance expense and amounts capitalized as part of the cost of another asset, are as follows:

Power
Power
Power

 2023

 Lease cost

 Operating lease cost(*)

 $
 $
 $
 $
 $
 $

 Finance lease cost:

 Amortization of ROU assets
 —
 —

 Interest on lease obligations
 —
 —
 —
 —

 Total finance lease cost
 —
 —

 Short-term lease costs
 —
 —
 —

 Variable lease cost
 —
 —
 —

 Sublease income
 —
 —
 —
 —
 —
 —

 Total lease cost
 $
 $
 $
 $
 $
 $

 2022

 Lease cost

 Operating lease cost(*)

 $
 $
 $
 $
 $
 $

 Finance lease cost:

 Amortization of ROU assets
 —
 —

 Interest on lease obligations
 —
 —
 —

 Total finance lease cost
 —
 —

 Short-term lease costs
 —
 —
 —

 Variable lease cost
 —
 —

 Sublease income
 ( 1)
 —
 —
 —
 —
 —

 Total lease cost
 $
 $
 $
 $
 $
 $

 2021

 Lease cost

 Operating lease cost(*)

 $
 $
 $
 $
 $
 $

 Finance lease cost:

 Amortization of ROU assets
 —
 —

 Interest on lease obligations
 —
 —
 —

 Total finance lease cost
 —
 —

 Short-term lease costs
 —
 —
 —

 Variable lease cost
 —
 —

 Sublease income
 —
 —
 —
 —
 —

 Total lease cost
 $
 $
 $
 $
 $
 $

 (*)Includes operating lease costs related to PPAs at Southern Company, Alabama Power, and Georgia Power totaling $ 112 million, $ 4 million, and $ 174 million, respectively, in 2023, $ 162 million, $ 48 million, and $ 180 million, respectively, in 2022, and $ 165 million, $ 47 million, and $ 184 million, respectively, in 2021.
 II-189

 Georgia Power has variable lease payments that are based on the amount of energy produced by certain renewable generating facilities subject to PPAs, including $ 42 million, $ 45 million, and $ 41 million in 2023, 2022, and 2021, respectively, from finance leases which are included in purchased power on Georgia Power's statements of income, of which $ 21 million, $ 21 million, and $ 20 million was included in purchased power, affiliates in 2023, 2022, and 2021, respectively.
 Other information with respect to cash and noncash activities related to leases, as well as weighted-average lease terms and discount rates, is as follows:

Power
Power
Power

 2023

 Other information

 Cash paid for amounts included in the measurements of lease obligations:

 Operating cash flows from operating leases
 $
 $
 $
 $
 $
 $

 Operating cash flows from finance leases
 —
 —
 —
 —

 Financing cash flows from finance leases
 —
 —

 ROU assets obtained under operating leases

 ROU assets obtained under finance leases
 —
 —
 —

 2022

 Other information

 Cash paid for amounts included in the measurements of lease obligations:

 Operating cash flows from operating leases
 $
 $
 $
 $
 $
 $

 Operating cash flows from finance leases
 —
 —
 —

 Financing cash flows from finance leases
 —
 —

 ROU assets obtained under operating leases
 —

 Reassessment of ROU assets under operating leases
 —
 —
 —
 —

 ROU assets obtained under finance leases
 —
 —
 —

 2021

 Other information

 Cash paid for amounts included in the measurements of lease obligations:

 Operating cash flows from operating leases
 $
 $
 $
 $
 $
 $

 Operating cash flows from finance leases
 —
 —
 —

 Financing cash flows from finance leases
 —
 —

 ROU assets obtained under operating leases
 —

 ROU assets obtained under finance leases
 —
 —
 —
 —
 —

 II-190

Power
Power
Power

 Weighted-average remaining lease term in years:

 Operating leases
 17.2
 11.1
 7.5
 4.6
 33.1
 7.0

 Finance leases
 16.7
 4.3
 10.6
 11.9
 N/A
 N/A

 Weighted-average discount rate:

 Operating leases
 4.68
 %
 5.02
 %
 4.58
 %
 3.67
 %
 4.89
 %
 3.80
 %

 Finance leases
 4.85
 %
 3.93
 %
 5.95
 %
 2.74
 %
 N/A
 N/A

 Weighted-average remaining lease term in years:

 Operating leases
 17.3
 13.0
 8.1
 4.7
 34.0
 11.0

 Finance leases
 17.4
 6.4
 11.8
 12.9
 N/A
 N/A

 Weighted-average discount rate:

 Operating leases
 4.51
 %
 4.87
 %
 4.52
 %
 3.49
 %
 4.86
 %
 3.79
 %

 Finance leases
 4.87
 %
 3.00
 %
 8.06
 %
 2.74
 %
 N/A
 N/A

 Maturities of lease liabilities are as follows:

Power
Power
Power

 Maturity Analysis

 Operating leases:

 2024
 $
 $
 $
 $
 $
 $

 2025

 2026

 2027
 —

 2028
 —

 1,378
 1,000

 Total
 2,293
 1,040
 1,153

 Less: Present value discount

 $
 1,490
 $
 $
 $
 $
 $

 Finance leases:

 2024
 $
 $
 $
 $
 $
 —
 $
 —

 2025
 —
 —

 2026
 —
 —

 2027
 —
 —

 2028
 —
 —

 —
 —
 —

 Total
 —
 —

 Less: Present value discount
 —
 —

 Finance lease obligations
 $
 $
 $
 $
 $
 —
 $
 —

 II-191

 Payments made under PPAs at Georgia Power for energy generated from certain renewable energy facilities accounted for as operating and finance leases are considered variable lease costs and are therefore not reflected in the above maturity analysis.
 Lessor
 The Registrants are each considered lessors in various arrangements that have been determined to contain a lease due to the customer's ability to control the use of the underlying asset owned by the applicable Registrant. For the traditional electric operating companies, these arrangements consist of outdoor lighting contracts accounted for as operating leases with initial terms of up to 10 years, after which the contracts renew on a month-to-month basis at the customer's option. For Mississippi Power, these arrangements also include a tolling arrangement related to an electric generating unit accounted for as a sales-type lease with a remaining term of 15 years. For Southern Power, these arrangements consist of PPAs related to electric generating units accounted for as operating leases with remaining terms of up to 23 years and PPAs related to battery energy storage facilities accounted for as sales-type leases with remaining terms of up to 18 years. Southern Company Gas is the lessor in operating leases related to gas pipelines with remaining terms of up to 19 years. For Southern Company, these arrangements also include PPAs related to fuel cells accounted for as operating leases with remaining terms of up to 10 years.
 Lease income for 2023, 2022, and 2021, is as follows:

Power

 2023

 Lease income - interest income on sales-type leases
 $
 $
 —
 $
 —
 $
 $
 $
 —

 Lease income - operating leases

 Variable lease income
 —
 —
 —

 Total lease income
 $
 $
 $
 $
 $
 $

 2022

 Lease income - interest income on sales-type leases
 $
 $
 —
 $
 —
 $
 $
 $
 —

 Lease income - operating leases

 Variable lease income
 —
 —
 —

 Total lease income
 $
 $
 $
 $
 $
 $

 2021

 Lease income - interest income on sales-type leases
 $
 $
 —
 $
 —
 $
 $
 $
 —

 Lease income - operating leases

 Variable lease income
 —
 —
 —
 —

 Total lease income
 $
 $
 $
 $
 $
 $

 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 related to PPAs for Alabama Power and Southern Power is included in wholesale revenues. Scheduled payments to be received under outdoor lighting contracts, tolling arrangements, and PPAs accounted for as leases are presented in the following maturity analyses.
 II-192

 Mississippi Power has a tolling arrangement accounted for as a sales-type lease. During 2021, Mississippi Power completed construction of additional leased assets under the lease and, upon completion, the book value of $ 39 million was transferred from CWIP to lease receivables. The transfer represented a non-cash investing transaction for purposes of the statements of cash flows.
 During 2021, Southern Power completed construction of a portion of the Garland and Tranquillity battery energy storage facilities' assets and recorded losses totaling $ 40 million upon commencement of the related PPAs, which Southern Power accounts for as sales-type leases. The losses were due to ITCs retained and expected to be realized by Southern Power and its partners in these projects, and no estimated residual asset value was assumed in calculating the losses. Each lease had an initial term of 20 years. Upon commencement of the leases, the book values of the related assets totaling $ 210 million were derecognized from CWIP and lease receivables were recorded. The transfers represented noncash investing transactions for purposes of the statement of cash flows. See Note 15 under "Southern Power" for additional information.
 The undiscounted cash flows expected to be received for in-service leased assets under the leases are as follows:

Power

 2024
 $
 $
 $

 2025

 2026

 2027

 2028

 Total undiscounted cash flows
 $
 $
 $

 Net investment in sales-type lease(*)

 Difference between undiscounted cash flows and discounted cash flows
 $
 $
 $

 (*)For Mississippi Power, included in other current assets and other property and investments on the balance sheets. For Southern Power, included in other current assets ($ 15 million and $ 15 million at December 31, 2023 and 2022, respectively) and net investment in sales-type leases ($ 148 million and $ 154 million at December 31, 2023 and 2022, respectively) on the balance sheet.
 The undiscounted cash flows to be received under operating leases and contracts accounted for as operating leases are as follows:

Power
Power

 2024
 $
 $
 $
 $

 2025

 2026

 2027

 2028

 Total
 $
 1,246
 $
 $
 $

 Southern Power receives payments for renewable energy under PPAs accounted for as operating leases that are considered contingent rents and are therefore not reflected in the table above. Alabama Power and Southern Power allocate revenue to the nonlease components of PPAs based on the stand-alone selling price of capacity and energy. The undiscounted cash flows to be received under outdoor lighting contracts accounted for as operating leases at Georgia Power and Mississippi Power are immaterial.

 Southern Company Leveraged Lease
 At December 31, 2020, a subsidiary of Southern Holdings had four leveraged lease agreements related to energy generation, distribution, and transportation assets, including two domestic and two international projects. During 2021, one of the domestic
 II-193

 projects was sold and the agreements for both international projects were terminated. At December 31, 2023, the one remaining leveraged lease agreement, which relates to energy generation, had an expected remaining term of eight years. Southern Company continues to receive federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to this investment. Southern Company wrote off the related investment balance in 2020 following an evaluation of the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease.
 The following table provides a summary of the components of income related to leveraged lease investments. Income was impacted in 2021 by the impairment charges discussed below and in Note 15 under "Southern Company." Income in 2021 does not include the impacts of the sale and terminations of leveraged lease projects discussed in Note 15 under "Southern Company."

 2021

 Pretax leveraged lease income

 $

 Income tax expense

 ( 5)

 Net leveraged lease income

 $

 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.

 10. INCOME TAXES
 Southern Company files a consolidated federal income tax return and the Registrants file various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis, and each subsidiary is allocated an amount of tax similar to that which would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.
 Current and Deferred Income Taxes
 Details of income tax provisions are as follows:

 2023

Power

 Federal —

 $
 $
 $
 $
 $
 ( 320)
 $

 ( 26)

 Total federal

 ( 15)

 State —

 ( 1)

 ( 1)

 Total state

 ( 2)

 Total
 $
 $
 $
 $
 $
 $

 II-194

 2022

Power

 Federal —

 $
 $
 $
 $
 $
 ( 43)
 $

 ( 16)
 ( 3)

 Total federal

 State —

 ( 21)
 —

 Total state

 Total
 $
 $
 $
 $
 $
 $

 2021

Power
Power

 Federal —

 $
 $
 $
 $
 $
 ( 340)
 $

 ( 449)
 ( 15)

 Total federal

 ( 138)

 State —

 ( 25)
 —
 ( 16)
 ( 68)

 ( 101)
 —

 Total state

 ( 30)
 ( 16)

 Total
 $
 $
 $
 ( 168)
 $
 $
 ( 13)
 $

 Southern Company's and Southern Power's ITCs and PTCs generated in the current tax year and carried forward from prior tax years that cannot be utilized in the current tax year are reclassified from current to deferred taxes in federal income tax expense in the tables above. Southern Power's ITCs and PTCs reclassified in this manner include $ 5 million for 2023, $ 17 million for 2022, and $ 6 million for 2021. Southern Power received $ 332 million, $ 49 million, and $ 289 million of cash related to federal ITCs under renewable energy initiatives in 2023, 2022, and 2021, respectively. See "Deferred Tax Assets and Liabilities" herein for additional information.
 In accordance with regulatory requirements, deferred federal ITCs for the traditional electric operating companies are amortized over the average life of the related property, with such amortization normally applied as a credit to reduce depreciation and amortization in the statements of income. Southern Power's and the natural gas distribution utilities' deferred federal ITCs, as well as certain state ITCs for Nicor Gas, are amortized to income tax expense over the life of the respective asset. ITCs amortized in 2023, 2022, and 2021 were immaterial for the traditional electric operating companies and Southern Company Gas and were as follows for Southern Company and Southern Power:

 2023
 $
 $

 2022

 2021

 When Southern Power recognizes tax credits, the tax basis of the asset is reduced by 50 % of the ITCs received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation.
 II-195

 State ITCs and other state credits, which are recognized in the period in which the credits are generated, reduced Georgia Power's income tax expense by $ 49 million in 2023, $ 53 million in 2022, and $ 66 million in 2021.
 Southern Power's federal and state PTCs, which are recognized in the period in which the credits are generated, reduced Southern Power's income tax expense by $ 26 million in 2023, $ 27 million in 2022, and $ 16 million in 2021.
 During the fourth quarter 2023, Southern Power executed an agreement to transfer certain PTCs generated in 2023 and received cash of $ 12 million. The discount recognized was booked through income tax expense and was immaterial.
 Pursuant to the Global Amendments to the Vogtle Joint Ownership Agreements (as defined in Note 2 under "Georgia Power – Nuclear Construction – Joint Owner Contracts"), Georgia Power paid $ 39 million to the other Vogtle Owners for advanced nuclear PTCs for Plant Vogtle Unit 3. The gain recognized in 2023 was booked through income tax benefit and was immaterial.
 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.
 In July 2021, Southern Company Gas affiliates completed the sale of Sequent. As a result of the sale, changes in state apportionment rates resulted in $ 85 million of additional net state tax expense. See Note 15 under "Southern Company Gas" for additional information.
 A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:

 2023

Power

 Federal statutory rate
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %

 State income tax, net of federal deduction
 2.6
 5.2
 1.5
 4.9
 ( 0.7)
 7.8

 Employee stock plans' dividend deduction
 ( 0.5)
 —
 —
 —
 —
 —

 Non-deductible book depreciation
 0.7
 0.7
 0.8
 0.4
 —
 —

 Flowback of excess deferred income taxes
 ( 9.2)
 ( 19.8)
 ( 2.6)
 ( 10.2)
 —
 ( 2.6)

 AFUDC-Equity
 ( 1.1)
 ( 1.2)
 ( 1.2)
 —
 —
 —

 Federal PTCs
 ( 1.2)
 —
 ( 1.4)
 —
 ( 7.4)
 —

 ITC amortization
 ( 1.3)
 —
 ( 19.0)
 —

 Noncontrolling interests
 0.6
 —
 —
 —
 11.1
 —

 Other
 ( 0.2)
 ( 0.2)
 ( 0.3)
 0.1
 0.1
 ( 0.6)

 Effective income tax (benefit) rate
 11.4
 %
 5.6
 %
 17.7
 %
 16.2
 %
 5.1
 %
 25.6
 %

 II-196

 2022

Power

 Federal statutory rate
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %

 State income tax, net of federal deduction
 6.2
 4.8
 6.5
 4.4
 1.9
 6.4

 Employee stock plans' dividend deduction
 ( 0.5)
 —
 —
 —
 —
 —

 Non-deductible book depreciation
 0.6
 0.5
 0.6
 0.3
 —
 —

 Flowback of excess deferred income taxes
 ( 6.6)
 ( 1.9)
 ( 9.6)
 ( 7.8)
 —
 ( 2.5)

 AFUDC-Equity
 ( 1.1)
 ( 0.8)
 ( 1.5)
 —
 —
 —

 Federal PTCs
 —
 —
 —
 —
 ( 6.6)
 —

 ITC amortization
 ( 1.3)
 —
 ( 17.2)

 Noncontrolling interests
 0.5
 —
 —
 —
 8.4
 —

 Other
 —
 0.3
 —
 0.3
 ( 0.9)

 Effective income tax (benefit) rate
 18.8
 %
 23.8
 %
 16.9
 %
 18.2
 %
 7.4
 %
 23.9
 %

 2021

Power

 Federal statutory rate
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %
 21.0
 %

 State income tax, net of federal deduction
 5.5
 4.6
 ( 5.7)
 4.9
 ( 8.0)
 15.1

 Employee stock plans' dividend deduction
 ( 0.9)
 —
 —
 —
 —
 —

 Non-deductible book depreciation
 0.9
 0.5
 3.1
 0.4
 —
 —

 Flowback of excess deferred income taxes
 ( 11.7)
 ( 2.6)
 ( 49.9)
 ( 15.2)
 —
 ( 2.8)

 AFUDC-Equity
 ( 1.5)
 ( 0.7)
 ( 6.4)
 —
 —
 —

 Federal PTCs
 —
 —
 —
 —
 ( 4.6)
 —

 ITC amortization
 ( 2.2)
 ( 0.4)
 —
 ( 29.7)

 Noncontrolling interests
 0.8
 —
 —
 —
 13.4
 —

 Leveraged lease impairments and dispositions

 ( 1.4)
 —
 —
 —
 —
 —

 Other
 0.2
 ( 1.9)
 0.6
 ( 0.4)
 0.6

 Effective income tax (benefit) rate
 10.4
 %
 22.9
 %
 ( 40.2)
 %
 11.7
 %
 ( 8.3)
 %
 33.8
 %

 II-197

 Deferred Tax Assets and Liabilities
 The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements of the Registrants and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:

Power

 Deferred tax liabilities —

 Accelerated depreciation
 $
 9,683
 $
 2,566
 $
 3,628
 $
 $
 1,346
 $
 1,576

 Property basis differences
 2,647
 1,444
 —

 AROs
 —
 —
 —

 Under recovered fuel and natural gas costs
 —
 —

 Regulatory assets –

 AROs
 1,902
 1,196
 —
 —

 —

 Remaining book value of retired assets
 —
 —

 Premium on reacquired debt
 —
 —

 Other

 Total deferred income tax liabilities
 18,574
 6,101
 7,661
 1,360
 2,041

 Deferred tax assets —

 AROs
 2,735
 1,143
 1,510
 —
 —

 ITC and PTC carryforwards
 1,387
 —
 —

 Estimated loss on plants under construction
 —
 —
 —
 —

 —
 —
 —
 —

 Other state deferred tax attributes
 —

 Federal effect of net state deferred tax liabilities
 —

 Other property basis differences
 —
 —
 —

 State effect of federal deferred taxes
 —
 —
 —
 —

 Other partnership basis differences
 —
 —
 —
 —

 Regulatory liability associated with the Tax Reform Legislation (not subject to normalization)
 —
 —
 —

 Long-term debt fair value adjustment
 —
 —
 —
 —

 Other comprehensive losses
 —
 —

 Other

 Total deferred income tax assets
 7,886
 1,931
 3,718

 Valuation allowance
 ( 206)
 —
 ( 75)
 ( 41)
 ( 27)
 ( 7)

 Net deferred income tax assets
 7,680
 1,931
 3,643

 Net deferred income taxes (assets)/liabilities
 $
 10,894
 $
 4,170
 $
 4,018
 $
 $
 $
 1,671

 Recognized in the balance sheets:

 Accumulated deferred income taxes – assets
 $
 ( 96)
 $
 —
 $
 —
 $
 ( 96)
 $
 —
 $
 —

 Accumulated deferred income taxes – liabilities
 $
 10,990
 $
 4,170
 $
 4,018
 $
 $
 $
 1,671

 II-198

 December 31, 2022

Power

 Deferred tax liabilities —

 Accelerated depreciation
 $
 9,443
 $
 2,564
 $
 3,447
 $
 $
 1,351
 $
 1,505

 Property basis differences
 2,350
 1,303
 —

 AROs
 —
 —
 —

 Under recovered fuel and natural gas costs
 —

 Regulatory assets –

 AROs
 2,006
 1,285
 —
 —

 —

 Remaining book value of retired assets
 —
 —

 Premium on reacquired debt
 —
 —
 —

 Other

 Total deferred income tax liabilities
 18,066
 6,024
 7,426
 1,376
 1,852

 Deferred tax assets —

 AROs
 2,882
 1,178
 1,609
 —
 —

 ITC and PTC carryforwards
 1,685
 —
 —

 Estimated loss on plants under construction
 —
 —
 —
 —

 Other state deferred tax attributes
 —

 Federal effect of net state deferred tax liabilities
 —

 Other property basis differences
 —
 —
 —

 State effect of federal deferred taxes
 —
 —
 —
 —

 Other partnership basis differences
 —
 —
 —
 —

 Regulatory liability associated with the Tax Reform Legislation (not subject to normalization)
 —
 —
 —

 Long-term debt fair value adjustment
 —
 —
 —
 —

 Other comprehensive losses
 —
 —

 Other

 Total deferred income tax assets
 8,398
 2,043
 3,844
 1,124

 Valuation allowance
 —
 ( 125)
 ( 41)
 ( 27)
 ( 9)

 Net deferred income tax assets
 8,141
 2,043
 3,719
 1,097

 Net deferred income taxes (assets)/liabilities
 $
 9,925
 $
 3,981
 $
 3,707
 $
 $
 $
 1,560

 Recognized in the balance sheets:

 Accumulated deferred income taxes – assets
 $
 ( 111)
 $
 —
 $
 —
 $
 $
 —
 $
 —

 Accumulated deferred income taxes – liabilities
 $
 10,036
 $
 3,981
 $
 3,707
 $
 $
 $
 1,560

 The traditional electric operating companies and the natural gas distribution utilities have tax-related regulatory assets (deferred income tax charges) and regulatory liabilities (deferred income tax credits). The regulatory assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and taxes applicable to capitalized interest. The regulatory liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized ITCs. See Note 2 for each Registrant's related balances at December 31, 2023 and 2022.
 II-199

 Tax Credit Carryforwards
 Federal ITC/PTC carryforwards at December 31, 2023 were as follows:

Power
Power
Power

 Federal ITC/PTC carryforwards
 $
 $
 $
 $

 Tax year in which federal ITC/PTC carryforwards begin expiring
 2031

 2032

 2031

 2035

 Year by which federal ITC/PTC carryforwards are expected to be utilized
 2029

 2028

 2028

 2029

 The estimated tax credit utilization reflects the various transactions described in Note 15 and could be impacted by numerous factors, including the acquisition of additional renewable projects, changes in taxable income projections, transfer of eligible credits, potential income tax rate changes, and the ultimate implementation of the natural gas safe harbor method for repairs. 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 2 under "Georgia Power – Nuclear Construction – Joint Owner Contracts"), Georgia Power is purchasing advanced nuclear PTCs for Plant Vogtle Unit 3 from the other Vogtle Owners. See Note 2 under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.
 At December 31, 2023, Georgia Power also had approximately $ 452 million in net state investment and other net state tax credit carryforwards for the State of Georgia that will expire between tax years 2023 and 2032 and are not expected to be fully utilized. Georgia Power has a net state valuation allowance of $ 60 million associated with these carryforwards.
 Net Operating Loss Carryforwards
 At December 31, 2023, the net state income tax benefit of state and local NOL carryforwards for Southern Company's subsidiaries were as follows:

 Company/Jurisdiction
 Approximate Net State Income Tax Benefit of NOL Carryforwards
 Tax Year NOL
Begins Expiring

 $
 2032

 Oklahoma
 2035

 Florida
 2034

 Other states
 Various

 Southern Power Total
 $

 Other(*)

 New York
 2036

 New York City
 2036

 Other states
 Various

 Southern Company Total
 $

 (*)Represents other non-registrant Southern Company subsidiaries. Alabama Power, Georgia Power, and Southern Company Gas did not have material state or local NOL carryforwards at December 31, 2023.
 II-200

 State NOLs for Mississippi, Oklahoma, and Florida are not expected to be fully utilized prior to expiration. At December 31, 2023, Mississippi Power had a net state valuation allowance of $ 32 million for the Mississippi NOL, Southern Power had net state valuation allowances of $ 11 million for the Oklahoma NOL and $ 10 million for the Florida NOL, and Southern Company had a net valuation allowance of $ 25 million for the New York and New York City NOLs.
 Unrecognized Tax Benefits
 Changes in unrecognized tax benefits for the periods presented were as follows:

 Power

Company Gas

 Unrecognized tax benefits at December 31, 2020
 $
 $
 —
 $
 —

 Tax positions changes –

 Increase from prior periods
 —
 —

 Unrecognized tax benefits at December 31, 2021
 —
 —

 Tax positions changes –

 Increase from prior periods
 —

 Unrecognized tax benefits at December 31, 2022
 —

 Tax positions changes –

 Increase from prior periods

 Statute of limitations expiration
 ( 52)
 ( 9)
 —

 Unrecognized tax benefits at December 31, 2023

 $
 $
 $

 The unrecognized tax positions increase from prior periods for 2022 is primarily related to the amendment of certain 2018 state tax filing positions related to Southern Company Gas dispositions. If accepted by the states, these positions would decrease Southern Company's and Southern Company Gas' annual effective tax rates. The ultimate outcome of these unrecognized tax benefits is dependent on acceptance by each state and is not expected to be resolved within the next 12 months.
 The unrecognized tax positions increase from prior periods for 2023 are primarily related to the amendment of certain 2019 through 2021 state tax filing positions related to tax credit utilization, a portion of which decreased in the fourth quarter 2023 due to a statute of limitations expiration. If effective settlement of the positions is favorable, these positions would decrease Southern Company's and Georgia Power's annual 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.
 The unrecognized tax positions reductions due to statute of limitations expiration for 2023 primarily relates to a 2019 state tax filing position to exclude certain gains from 2019 dispositions from taxation in a certain unitary state. This tax position and related interest was recognized in the fourth quarter 2023 and decreased Southern Company's annual effective tax rate.
 All of the Registrants classify interest on tax uncertainties as interest expense. Accrued interest for all tax positions was immaterial for all years presented. None of the Registrants accrued any penalties on uncertain tax positions.
 The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2022. Southern Company is a participant in the Compliance Assurance Process of the IRS. The IRS has selected six Southern Power partnership returns for exam for the 2020 and 2021 tax years. The ultimate outcome of this matter cannot be determined at this time. The audits for the Registrants' state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2015.

 11. RETIREMENT BENEFITS
 The Southern Company system has a qualified defined benefit, trusteed pension plan covering substantially all employees, with the exception of PowerSecure employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan were made for the year ended December 31, 2023 and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2024. 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
 II-201

 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. For the year ending December 31, 2024, no contributions to any other postretirement trusts are expected.

 Actuarial Assumptions
 The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below.

 2023

 Assumptions used to determine net
periodic costs:
Power

 5.25
 %
 5.26
 %
 5.25
 %
 5.25
 %
 5.31
 %
 5.24
 %

 5.13
 5.14
 5.12
 5.12
 5.19
 5.12

 5.36
 5.38
 5.38
 5.37
 5.37
 5.31

 8.40
 8.40
 8.40
 8.40
 8.40
 8.40

 4.80
 4.80
 4.80
 4.80
 4.80
 4.80

 5.18
 %
 5.20
 %
 5.17
 %
 5.17
 %
 5.24
 %
 5.16
 %

 5.08
 5.09
 5.07
 5.08
 5.12
 5.07

 5.34
 5.35
 5.34
 5.33
 5.33
 5.33

 7.67
 7.95
 7.49
 7.43
 —
 6.59

 4.80
 4.80
 4.80
 4.80
 4.80
 4.80

 2022

 Assumptions used to determine net
periodic costs:
Power
Power

 3.09
 %
 3.12
 %
 3.07
 %
 3.07
 %
 3.21
 %
 3.04
 %

 2.55
 2.58
 2.51
 2.54
 2.79
 2.53

 3.34
 3.36
 3.37
 3.35
 3.36
 3.21

 8.25
 8.25
 8.25
 8.25
 8.25
 8.25

 4.80
 4.80
 4.80
 4.80
 4.80
 4.80

 2.90
 %
 2.95
 %
 2.87
 %
 2.88
 %
 3.07
 %
 2.82
 %

 2.32
 2.38
 2.30
 2.27
 2.55
 2.17

 3.26
 3.30
 3.27
 3.26
 3.25
 3.22

 7.21
 7.54
 6.88
 7.22
 —
 6.08

 4.80
 4.80
 4.80
 4.80
 4.80
 4.80

 II-202

 2021

 Assumptions used to determine net periodic costs:
Power
Power

 2.81
 %
 2.85
 %
 2.79
 %
 2.80
 %
 2.99
 %
 2.75
 %

 2.13
 2.17
 2.09
 2.12
 2.46
 2.10

 3.18
 3.23
 3.21
 3.20
 3.22
 2.97

 8.25
 8.25
 8.25
 8.25
 8.25
 8.25

 4.80
 4.80
 4.80
 4.80
 4.80
 4.80

 2.56
 %
 2.63
 %
 2.52
 %
 2.53
 %
 2.78
 %
 2.46
 %

 1.84
 1.91
 1.82
 1.78
 2.12
 1.64

 3.07
 3.13
 3.08
 3.06
 3.05
 3.01

 7.09
 7.18
 6.84
 6.98
 —
 6.54

 4.80
 4.80
 4.80
 4.80
 4.80
 4.80

 2023

 Assumptions used to determine benefit obligations:

 Discount rate
 5.07
 %
 5.08
 %
 5.06
 %
 5.06
 %
 5.14
 %
 5.05
 %

 4.60
 4.60
 4.60
 4.60
 4.60
 4.60

 Discount rate
 4.99
 %
 5.01
 %
 4.98
 %
 4.98
 %
 5.06
 %
 4.98
 %

 4.60
 4.60
 4.60
 4.60
 4.60
 4.60

 2022

 Assumptions used to determine benefit obligations:

 Discount rate
 5.25
 %
 5.26
 %
 5.25
 %
 5.25
 %
 5.31
 %
 5.24
 %

 4.80
 4.80
 4.80
 4.80
 4.80
 4.80

 Discount rate
 5.18
 %
 5.20
 %
 5.17
 %
 5.17
 %
 5.24
 %
 5.16
 %

 4.80
 4.80
 4.80
 4.80
 4.80
 4.80

 The Registrants estimate the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of the different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio. The Registrants set the expected rate of return assumption using an arithmetic mean which represents the expected simple average return to be earned by the pension plan assets over any one year. The Registrants believe the use of the arithmetic mean is more compatible with the expected rate of return's function of estimating a single year's investment return.
 II-203

 An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO for the Registrants at December 31, 2023 were as follows:

 Initial Cost Trend Rate
 Ultimate Cost Trend Rate
 Year That Ultimate Rate is Reached

 Pre-65
 7.00
 %
 4.50
 %
 2032

 Post-65 medical
 5.50
 4.50
 2032

 Post-65 prescription
 8.50
 4.50
 2032

 Pension Plans
 The total accumulated benefit obligation for the pension plans at December 31, 2023 and 2022 was as follows:

 $
 11,991
 $
 2,746
 $
 3,674
 $
 $
 $

 December 31, 2022
 11,422
 2,601
 3,534

 An actuarial loss of $ 0.5 billion and an actuarial gain of $ 3.9 billion were recorded for the annual remeasurement of the Southern Company system pension plans at December 31, 2023 and 2022, respectively, primarily due to a decrease of 18 basis points and an increase of 216 basis points, respectively, in the overall discount rate used to calculate the benefit obligation as a result of higher market interest rates.
 Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2023 and 2022 were as follows:

 2023

Power

 Change in benefit obligation

 Benefit obligation at beginning of year
 $
 12,602
 $
 2,906
 $
 3,851
 $
 $
 $

 ( 744)
 ( 155)
 ( 224)
 ( 32)
 ( 6)

 Actuarial loss

 Balance at end of year
 13,252
 3,076
 4,009

 Change in plan assets

 Fair value of plan assets at beginning of year
 14,218
 3,427
 4,456
 1,002

 Actual return on plan assets
 1,092

 Employer contributions

 ( 744)
 ( 154)
 ( 225)
 ( 32)
 ( 7)

 Fair value of plan assets at end of year
 14,618
 3,544
 4,571

 Accrued asset
 $
 1,366
 $
 $
 $
 $
 $

 II-204

 2022

Power

 Change in benefit obligation

 Benefit obligation at beginning of year
 $
 16,382
 $
 3,806
 $
 5,012
 $
 $
 $
 1,134

 ( 692)
 ( 144)
 ( 226)
 ( 30)
 ( 5)
 ( 75)

 Actuarial gain
 ( 3,908)
 ( 951)
 ( 1,161)
 ( 179)
 ( 69)
 ( 253)

 Balance at end of year
 12,602
 2,906
 3,851

 Change in plan assets

 Fair value of plan assets at beginning of year
 17,225
 4,141
 5,415
 1,241

 Actual loss on plan assets
 ( 2,376)
 ( 579)
 ( 753)
 ( 110)
 ( 31)
 ( 167)

 Employer contributions

 ( 692)
 ( 144)
 ( 226)
 ( 30)
 ( 5)
 ( 75)

 Fair value of plan assets at end of year
 14,218
 3,427
 4,456
 1,002

 Accrued asset
 $
 1,616
 $
 $
 $
 $
 $

 The projected benefit obligations for the qualified and non-qualified pension plans at December 31, 2023 are shown in the following table. All pension plan assets are related to the qualified pension plan.

 Projected benefit obligations:

 Qualified pension plan
 $
 12,540
 $
 2,959
 $
 3,865
 $
 $
 $

 Non-qualified pension plan

 II-205

 Amounts recognized in the balance sheets at December 31, 2023 and 2022 related to the Registrants' pension plans consist of the following:

Power

 December 31, 2023:

 Prepaid pension costs(a)

 $
 2,079
 $
 $
 $
 $
 $

 Other regulatory assets, deferred(b)

 2,960
 1,051
 —

 ( 64)
 ( 11)
 ( 13)
 ( 2)
 ( 2)
 ( 3)

 Employee benefit obligations(c)

 ( 649)
 ( 131)
 ( 27)
 ( 21)
 ( 58)

 ( 47)
 —
 —
 —
 —
 —

 AOCI
 —
 —
 —
 ( 45)

 December 31, 2022:

 Prepaid pension costs(a)

 $
 2,290
 $
 $
 $
 $
 $

 Other regulatory assets, deferred(b)

 2,455
 —

 ( 56)
 ( 10)
 ( 12)
 ( 2)
 ( 2)
 ( 3)

 Employee benefit obligations(c)

 ( 618)
 ( 98)
 ( 121)
 ( 26)
 ( 20)
 ( 42)

 ( 85)
 —
 —
 —
 —
 —

 AOCI
 —
 —
 —
 ( 75)

 (a)Included in prepaid pension and other postretirement benefit costs on Alabama Power's balance sheet and other deferred charges and assets on Southern Power's consolidated balance sheet.
 (b)Amounts for Southern Company exclude regulatory assets of $ 173 million and $ 190 million at December 31, 2023 and 2022, respectively, associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company.
 (c)Included in other deferred credits and liabilities on Southern Power's consolidated balance sheets.
 Presented below are the amounts included in regulatory assets at December 31, 2023 and 2022 related to the portion of the defined benefit pension plan attributable to Southern Company, the traditional electric operating companies, and Southern Company Gas that had not yet been recognized in net periodic pension cost.

Power

 Regulatory assets:

 $
 $
 $
 $
 $
 ( 7)

 2,904
 1,045

 Regulatory amortization
 —
 —
 —
 —

 Total regulatory assets(*)

 $
 2,913
 $
 $
 1,051
 $
 $

 Regulatory assets:

 $
 $
 $
 $
 $
 ( 9)

 2,361

 Regulatory amortization
 —
 —
 —
 —

 Total regulatory assets(*)

 $
 2,371
 $
 $
 $
 $

 (*)Amounts for Southern Company exclude regulatory assets of $ 173 million and $ 190 million at December 31, 2023 and 2022, respectively, associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company.
 II-206

 The changes in the balance of regulatory assets related to the portion of the defined benefit pension plan attributable to Southern Company, the traditional electric operating companies, and Southern Company Gas for the years ended December 31, 2023 and 2022 are presented in the following table:

Power

 Regulatory assets (liabilities):(*)

 $
 2,801
 $
 $
 $
 $

 ( 183)
 ( 67)
 ( 9)
 ( 12)

 ( 1)
 ( 1)
 ( 1)
 —

 ( 246)
 ( 62)
 ( 74)
 ( 11)

 Amortization of regulatory assets(*)

 —
 —
 —
 —
 ( 10)

 ( 247)
 ( 63)
 ( 75)
 ( 11)
 ( 7)

 ( 430)
 ( 130)
 ( 84)
 ( 23)

 $
 2,371
 $
 $
 $
 $

 ( 1)
 ( 1)
 ( 1)
 —

 Amortization of net loss
 ( 33)
 ( 10)
 ( 13)
 ( 2)
 —

 Amortization of regulatory assets(*)

 —
 —
 —
 —
 ( 4)

 ( 34)
 ( 11)
 ( 14)
 ( 2)
 ( 2)

 $
 2,913
 $
 $
 1,051
 $
 $

 (*)Amounts for Southern Company exclude regulatory assets of $ 173 million and $ 190 million at December 31, 2023 and 2022, respectively, associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company.
 Presented below are the amounts included in AOCI at December 31, 2023 and 2022 related to the portion of the defined benefit pension plan attributable to Southern Company, Southern Power, and Southern Company Gas that had not yet been recognized in net periodic pension cost.

Power
Gas

 AOCI:

 $
 ( 1)
 $
 —
 $
 ( 2)

 ( 43)

 Total AOCI
 $
 $
 $
 ( 45)

 AOCI:

 $
 ( 2)
 $
 —
 $
 ( 3)

 ( 72)

 Total AOCI
 $
 $
 $
 ( 75)

 II-207

 The components of OCI related to the portion of the defined benefit pension plan attributable to Southern Company, Southern Power, and Southern Company Gas for the years ended December 31, 2023 and 2022 are presented in the following table:

Power
Gas

 AOCI:

 $
 $
 $
 ( 45)

 ( 82)
 ( 22)
 ( 30)

 ( 2)
 —

 ( 76)
 ( 24)
 ( 30)

 $
 $
 $
 ( 75)

 —

 Amortization of net loss
 ( 8)
 —
 —

 ( 7)
 —

 $
 $
 $
 ( 45)

 II-208

 Components of net periodic pension cost for the Registrants were as follows:

Power

 2023

 $
 $
 $
 $
 $
 $

 ( 1,229)
 ( 297)
 ( 385)
 ( 56)
 ( 15)
 ( 85)

 Recognized net (gain) loss
 —
 ( 5)

 —
 —
 —

 —
 —
 —
 —
 —
 ( 3)

 Net periodic pension cost (income)
 $
 ( 296)
 $
 ( 78)
 $
 ( 112)
 $
 ( 15)
 $
 ( 1)
 $
 ( 12)

 2022

 $
 $
 $
 $
 $
 $

 ( 1,265)
 ( 306)
 ( 399)
 ( 57)
 ( 15)
 ( 91)

 Recognized net loss

 —
 —
 —

 —
 —
 —
 —
 —
 ( 3)

 Net periodic pension cost (income)
 $
 ( 205)
 $
 ( 48)
 $
 ( 97)
 $
 ( 11)
 $
 $
 ( 9)

 2021

 $
 $
 $
 $
 $
 $

 ( 1,191)
 ( 287)
 ( 375)
 ( 55)
 ( 14)
 ( 86)

 Recognized net loss

 —
 —

 —
 —
 —
 —
 —
 ( 3)

 Net periodic pension cost (income)
 $
 ( 96)
 $
 ( 20)
 $
 ( 58)
 $
 ( 6)
 $
 $
 —

 The service cost component of net periodic pension cost is included in operations and maintenance expenses and all other components of net periodic pension cost are included in other income (expense), net in the Registrants' statements of income.
 Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Registrants have elected to amortize changes in the market value of return-seeking plan assets over five years and to recognize the changes in the market value of liability-hedging plan assets immediately. Given the significant concentration in return-seeking plan assets, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.
 II-209

 Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2023, estimated benefit payments were as follows:

Power

 Benefit Payments:

 2024
 $
 $
 $
 $
 $
 $

 2025

 2026

 2027

 2028

 2029 to 2033
 4,417
 1,337

 Other Postretirement Benefits
 Changes in the APBO and the fair value of the Registrants' plan assets during the plan years ended December 31, 2023 and 2022 were as follows:

 2023

Power

 Change in benefit obligation

 Benefit obligation at beginning of year
 $
 1,441
 $
 $
 $
 $
 $

 —

 —

 ( 24)
 ( 36)
 ( 4)
 ( 1)
 ( 18)

 Actuarial (gain) loss
 ( 33)
 ( 12)
 ( 18)
 ( 2)

 Balance at end of year
 1,386

 Change in plan assets

 Fair value of plan assets at beginning of year
 —

 Actual return on plan assets
 —

 Employer contributions

 ( 24)
 ( 36)
 ( 4)
 ( 1)
 ( 18)

 Fair value of plan assets at end of year
 1,095
 —

 Accrued asset (liability)
 $
 ( 291)
 $
 $
 ( 79)
 $
 ( 32)
 $
 ( 9)
 $
 ( 44)

 II-210

 2022

Power

 Change in benefit obligation

 Benefit obligation at beginning of year
 $
 1,849
 $
 $
 $
 $
 $

 —

 —

 ( 109)
 ( 23)
 ( 38)
 ( 4)
 ( 1)
 ( 18)

 Actuarial gain
 ( 365)
 ( 89)
 ( 125)
 ( 16)
 ( 1)
 ( 46)

 Retiree drug subsidy
 —
 —
 —
 —
 —

 Balance at end of year
 1,441

 Change in plan assets

 Fair value of plan assets at beginning of year
 1,251
 —

 Actual loss on plan assets
 ( 218)
 ( 98)
 ( 71)
 ( 4)
 —
 ( 25)

 Employer contributions

 ( 108)
 ( 23)
 ( 38)
 ( 4)
 ( 1)
 ( 18)

 Fair value of plan assets at end of year
 —

 Accrued asset (liability)
 $
 ( 443)
 $
 $
 ( 146)
 $
 ( 35)
 $
 ( 9)
 $
 ( 66)

 Amounts recognized in the balance sheets at December 31, 2023 and 2022 related to the Registrants' other postretirement benefit plans consist of the following:

Power
Power

 December 31, 2023:

 Prepaid other postretirement benefit costs(a)

 $
 —
 $
 $
 —
 $
 —
 $
 —
 $
 —

 Other regulatory assets, deferred(b)

 —
 —
 —
 —

 ( 6)
 —
 —
 —
 ( 1)
 —

 Employee benefit obligations(c)

 ( 285)
 —
 ( 79)
 ( 32)
 ( 8)
 ( 44)

 ( 231)
 ( 48)
 ( 85)
 ( 10)
 —
 ( 68)

 AOCI
 ( 9)
 —
 —
 —
 ( 10)

 December 31, 2022:

 Prepaid other postretirement benefit costs(a)

 $
 —
 $
 $
 —
 $
 —
 $
 —
 $
 —

 Other regulatory assets, deferred(b)

 —
 —
 —
 —

 ( 6)
 —
 —
 —
 ( 1)
 —

 Employee benefit obligations(c)

 ( 437)
 —
 ( 146)
 ( 35)
 ( 8)
 ( 66)

 ( 170)
 ( 21)
 ( 58)
 ( 9)
 —
 ( 58)

 AOCI
 ( 4)
 —
 —
 —
 —
 ( 2)

 (a)Included in prepaid pension and other postretirement benefit costs on Alabama Power's balance sheet.
 (b)Amounts for Southern Company exclude regulatory assets of $ 24 million and $ 32 million at December 31, 2023 and 2022, respectively, associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company.
 (c)Included in other deferred credits and liabilities on Southern Power's consolidated balance sheets.
 II-211

 Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2023 and 2022 related to the other postretirement benefit plans of Southern Company, the traditional electric operating companies, and Southern Company Gas that had not yet been recognized in net periodic other postretirement benefit cost.

Power

 Balance at December 31, 2023:

 Regulatory assets (liabilities):

 $
 $
 $
 $
 $
 —

 ( 216)
 ( 52)
 ( 79)
 ( 11)
 ( 64)

 Regulatory amortization
 —
 —
 —
 —
 ( 4)

 Total regulatory assets (liabilities)(*)

 $
 ( 203)
 $
 ( 48)
 $
 ( 74)
 $
 ( 10)
 $
 ( 68)

 Balance at December 31, 2022:

 Regulatory assets (liabilities):

 $
 $
 $
 $
 $

 ( 150)
 ( 25)
 ( 45)
 ( 10)
 ( 64)

 Regulatory amortization
 —
 —
 —
 —

 Total regulatory assets (liabilities)(*)

 $
 ( 136)
 $
 ( 21)
 $
 ( 39)
 $
 ( 9)
 $
 ( 58)

 (*)Amounts for Southern Company exclude regulatory assets of $ 24 million and $ 32 million at December 31, 2023 and 2022, respectively, associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company.
 The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2023 and 2022 are presented in the following table:

Power

 Net regulatory assets (liabilities):(*)

 $
 ( 74)
 $
 ( 62)
 $
 ( 10)
 $
 $
 ( 34)

 ( 64)
 ( 27)
 ( 10)
 ( 13)

 —
 —
 —
 —

 —
 ( 2)
 —
 —

 Amortization of regulatory assets(*)

 —
 —
 —
 —
 ( 11)

 —
 ( 2)
 —
 ( 11)

 ( 62)
 ( 29)
 ( 10)
 ( 24)

 $
 ( 136)
 $
 ( 21)
 $
 ( 39)
 $
 ( 9)
 $
 ( 58)

 ( 77)
 ( 30)
 ( 38)
 ( 1)
 —

 ( 1)
 —
 ( 1)
 —
 —

 Amortization of net gain
 —
 —

 Amortization of regulatory assets(*)

 —
 —
 —
 —
 ( 10)

 —
 ( 10)

 ( 72)
 ( 27)
 ( 35)
 ( 1)
 ( 10)

 $
 ( 208)
 $
 ( 48)
 $
 ( 74)
 $
 ( 10)
 $
 ( 68)

 (*)Amounts for Southern Company exclude regulatory assets of $ 24 million and $ 32 million at December 31, 2023 and 2022, respectively, associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company.
 II-212

 Presented below are the amounts included in AOCI at December 31, 2023 and 2022 related to the other postretirement benefit plans of Southern Company, Southern Power, and Southern Company Gas that had not yet been recognized in net periodic other postretirement benefit cost.

Power
Gas

 AOCI:

 $
 $
 —
 $
 —

 ( 10)
 ( 10)

 Total AOCI
 $
 ( 9)
 $
 $
 ( 10)

 AOCI:

 $
 $
 —
 $
 —

 ( 5)
 —
 ( 2)

 Total AOCI
 $
 ( 4)
 $
 —
 $
 ( 2)

 The components of OCI related to the other postretirement benefit plans for the plan years ended December 31, 2023 and 2022 are presented in the following table:

Power

 AOCI:

 $
 —
 $
 $
 ( 5)

 ( 3)
 ( 2)
 —

 ( 1)
 —

 ( 4)
 ( 2)

 $
 ( 4)
 $
 —
 $
 ( 2)

 ( 12)
 —

 —
 ( 8)

 ( 5)
 ( 8)

 $
 ( 9)
 $
 $
 ( 10)

 II-213

 Components of the other postretirement benefit plans' net periodic cost for the Registrants were as follows:

Power

 2023

 $
 $
 $
 $
 $
 —
 $

 —

 ( 83)
 ( 33)
 ( 29)
 ( 3)
 ( 10)

 ( 11)
 ( 3)
 ( 3)
 —
 —

 Net periodic postretirement benefit cost (income)
 $
 ( 9)
 $
 ( 15)
 $
 ( 3)
 $
 $
 $

 2022

 $
 $
 $
 $
 $
 —
 $

 —

 ( 80)
 ( 32)
 ( 28)
 ( 2)
 ( 9)

 ( 1)
 —
 —
 —

 Net periodic postretirement benefit cost (income)
 $
 ( 16)
 $
 ( 16)
 $
 ( 5)
 $
 $
 $

 2021

 $
 $
 $
 $
 $
 —
 $

 —

 ( 76)
 ( 30)
 ( 26)
 ( 1)
 ( 10)

 —
 —
 —

 Net periodic postretirement benefit cost (income)
 $
 ( 15)
 $
 ( 15)
 $
 ( 5)
 $
 $
 $

 The service cost component of net periodic postretirement benefit cost is included in operations and maintenance expenses and all other components of net periodic postretirement benefit cost are included in other income (expense), net in the Registrants' statements of income.
 The Registrants' future benefit payments, including prescription drug benefits, are provided in the table below. These amounts reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans.

Power

 Benefit payments:

 2024
 $
 $
 $
 $
 $
 $

 2025

 2026

 2027

 2028

 2029 to 2033

 II-214

 Benefit Plan Assets
 Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code. The Registrants' investment policies for both the pension plans and the other postretirement benefit plans cover a diversified mix of assets as described below. Derivative instruments may be used to gain efficient exposure to the various asset classes and as hedging tools. Additionally, the Registrants minimize the risk of large losses primarily through diversification but also monitor and manage other aspects of risk.
 The investment strategy for plan assets related to the Southern Company system's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Southern Company system employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Management believes the portfolio is well-diversified with no significant concentrations of risk.
 II-215

 Investment Strategies and Benefit Plan Asset Fair Values
 A description of the major asset classes that the pension and other postretirement benefit plans are comprised of, along with the valuation methods used for fair value measurement, is provided below:

 Description
 Valuation Methodology

 Domestic equity: A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.

 International equity: A mix of large and small capitalization growth and value stocks with developed and emerging markets exposure, managed both actively and through fundamental indexing approaches.

 Domestic and international equities such as common stocks, American depositary receipts, and real estate investment trusts that trade on public exchanges are classified as Level 1 investments and are valued at the closing price in the active market. Equity funds with unpublished prices that are comprised of publicly traded securities (such as commingled/pooled funds) are also valued at the closing price in the active market, but are classified as Level 2.

 Fixed income: A mix of domestic and international bonds.

 Investments in fixed income securities, including fixed income pooled funds, are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.

 Trust-owned life insurance (TOLI): Investments of taxable trusts aimed at minimizing the impact of taxes on the portfolio.

 Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate accounts. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities.

 Real estate: Investments in equity or debt of real properties and in publicly traded real estate securities.

 Special situations: Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as investments in promising new strategies of a longer-term nature.

 Private equity: Investments in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.

 Private credit: Investments focused on debt instruments, of which returns are driven by income rather than capital appreciation.

 Infrastructure: Investments in real assets, typically with long-term, predictable, and stable cash flows and a meaningful income component.

 Investments in real estate, special situations, private equity, private credit, and infrastructure are typically invested in private partnerships and/or other pooled vehicles (Funds) which are generally classified as Net Asset Value as a Practical Expedient, since the Funds and underlying assets are not publicly traded and/or often have liquidity restrictions. The managers of the Funds value the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The total market value of each of the Funds is determined by aggregating the value of the underlying assets less liabilities.

 For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. The fair values presented herein exclude cash, receivables related to investment income and pending investment sales, and payables related to pending investment purchases.
 The fair values, and actual allocations relative to the target allocations, of the Southern Company system's pension plans at December 31, 2023 and 2022 are presented below.
 II-216

Other

 (NAV)
 Total

 %
 %

 $
 1,959
 $
 $
 —
 $
 —
 $
 2,730

 1,947
 1,052
 —
 —
 2,999

 —
 1,973
 —
 —
 1,973

 —
 —
 —

 —
 1,724
 —
 —
 1,724

 —
 —
 —

 —
 —

 —
 —
 1,684
 2,053

 —
 —
 —

 —
 —
 —
 1,761
 1,761

 —
 —
 —
 —

 —
 —
 —
 —
 —
 —

 Total
 $
 4,646
 $
 6,399
 $
 —
 $
 3,715
 $
 14,760
 %
 %

 %
 %

 $
 $
 $
 —
 $
 —
 $

 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —

 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —
 —

 —
 —
 —
 —
 —
 —

 Total
 $
 1,127
 $
 1,552
 $
 —
 $
 $
 3,579
 %
 %

 II-217

Other

 (NAV)
 Total

 %
 %

 $
 $
 $
 —
 $
 —
 $

 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —

 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —
 —

 —
 —
 —
 —
 —
 —

 Total
 $
 1,451
 $
 2,001
 $
 —
 $
 1,163
 $
 4,615
 %
 %

 %
 %

 $
 $
 $
 —
 $
 —
 $

 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —

 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —
 —

 —
 —
 —
 —
 —
 —

 Total
 $
 $
 $
 —
 $
 $
 %
 %

 II-218

Other

 (NAV)
 Total

 %
 %

 $
 $
 $
 —
 $
 —
 $

 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —

 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —
 —
 —
 —

 —
 —
 —
 —
 —
 —

 Total
 $
 $
 $
 —
 $
 $
 100 %
 %

 %
 %

 $
 $
 $
 —
 $
 —
 $

 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —

 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —
 —

 —
 —
 —
 —
 —
 —

 Total
 $
 $
 $
 —
 $
 $
 %
 %

 II-219

Other

 (NAV)
 Total

 %
 %

 $
 2,078
 $
 $
 —
 $
 —
 $
 2,769

 2,166
 1,090
 —
 —
 3,256

 —
 1,469
 —
 —
 1,469

 —
 —
 —

 —
 1,494
 —
 —
 1,494

 —
 —
 —

 —
 —

 —
 —
 1,887
 2,263

 —
 —
 —

 —
 —
 —
 1,717
 1,717

 Total
 $
 5,019
 $
 5,387
 $
 —
 $
 3,791
 $
 14,197
 %
 %

 Derivatives
 ( 4)
 —
 —
 —
 ( 4)

 Total
 $
 5,015
 $
 5,387
 $
 —
 $
 3,791
 $
 14,193
 %
 %

 %
 %

 $
 $
 $
 —
 $
 —
 $

 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —

 —
 —

 —
 —
 —

 —
 —
 —

 Total
 $
 1,209
 $
 1,299
 $
 —
 $
 $
 3,422
 %
 %

 Derivatives
 ( 1)
 —
 —
 —
 ( 1)

 Total
 $
 1,208
 $
 1,299
 $
 —
 $
 $
 3,421
 %
 %

 II-220

Other

 (NAV)
 Total

 %
 %

 $
 $
 $
 —
 $
 —
 $

 —
 —
 1,020

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —

 —
 —

 —
 —
 —

 —
 —
 —

 Total
 $
 1,572
 $
 1,688
 $
 —
 $
 1,188
 $
 4,448
 %
 %

 Derivatives
 ( 1)
 —
 —
 —
 ( 1)

 Total
 $
 1,571
 $
 1,688
 $
 —
 $
 1,188
 $
 4,447
 %
 %

 %
 %

 $
 $
 $
 —
 $
 —
 $

 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —

 —
 —
 —

 —
 —
 —

 Total
 $
 $
 $
 —
 $
 $
 %
 %

 II-221

Other

 (NAV)
 Total

 %
 %

 $
 $
 $
 —
 $
 —
 $

 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —

 —
 —
 —

 —
 —
 —

 Total
 $
 $
 $
 —
 $
 $
 %
 %

 %
 %

 $
 $
 $
 —
 $
 —
 $

 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —

 —
 —

 —
 —
 —

 —
 —
 —

 Total
 $
 $
 $
 —
 $
 $
 1,001
 %
 %

 II-222

 The fair values, and actual allocations relative to the target allocations, of the applicable Registrants' other postretirement benefit plan assets at December 31, 2023 and 2022 are presented below.

Other
 Total

 (NAV)

 %
 %

 $
 $
 $
 —
 $

 —

 —
 —

 —
 —

 —
 —

 —
 —

 —

 —
 —

 —

 —
 —

 —
 —

 —
 —
 —

 —
 —
 —
 —
 —

 Total
 $
 $
 $
 $
 1,096
 %
 %

 %
 %

 $
 $
 $
 —
 $

 —

 —
 —

 —
 —

 —
 —

 —
 —

 —
 —

 —

 —
 —

 —
 —

 —
 —
 —
 —
 —

 —
 —
 —
 —
 —

 Total
 $
 $
 $
 $
 %
 %

 II-223

Other
 Total

 (NAV)

 %
 %

 $
 $
 $
 —
 $

 —

 —
 —

 —
 —

 —
 —

 —
 —

 —
 —

 —

 —
 —

 —
 —

 —
 —
 —
 —
 —

 —
 —
 —
 —
 —
 —

 Total
 $
 $
 $
 $
 %
 %

 %
 %

 $
 $
 $
 —
 $

 —

 —
 —

 —
 —

 —
 —

 —
 —

 —

 —
 —
 —
 —

 —
 —

 —
 —
 —
 —
 —

 —
 —
 —
 —
 —

 Total
 $
 $
 $
 $
 %
 %

 II-224

Other
 Total

 (NAV)

 %
 %

 $
 $
 $
 —
 $

 —

 —
 —

 —
 —

 —
 —

 —
 —

 —
 —
 —
 —

 —
 —

 —
 —

 Total
 $
 $
 $
 $
 %
 %

 II-225

Other

 (NAV)
 Total

 %
 %

 $
 $
 $
 —
 $

 —

 —
 —

 —
 —

 —
 —

 —
 —

 —
 —

 —
 —

 —

 —
 —

 —
 —

 Total
 $
 $
 $
 $
 %
 %

 %
 %

 $
 $
 $
 —
 $

 —

 —
 —

 —
 —

 —
 —

 —
 —

 —
 —

 —

 —
 —

 —
 —

 Total
 $
 $
 $
 $
 %
 %

 II-226

Other

 (NAV)
 Total

 %
 %

 $
 $
 $
 —
 $

 —

 —
 —

 —
 —

 —
 —

 —
 —

 —
 —

 —

 —
 —

 —
 —

 Total
 $
 $
 $
 $
 %
 %

 %
 %

 $
 $
 $
 —
 $

 —

 —
 —

 —
 —

 —
 —

 —
 —

 —

 —
 —
 —
 —

 —
 —

 Total
 $
 $
 $
 $
 %
 %

 II-227

Other

 (NAV)
 Total

 %
 %

 $
 $
 $
 —
 $

 —

 —
 —

 —
 —

 —
 —

 —
 —

 —
 —

 —
 —

 Total
 $
 $
 $
 $
 %
 %

 Employee Savings Plan
 Southern Company and its subsidiaries also sponsor 401(k) defined contribution plans covering substantially all employees and provide matching contributions up to specified percentages of an employee's eligible pay. Total matching contributions made to the plans for 2023, 2022, and 2021 were as follows:

Power
Power
Power
Power

 2023
 $
 $
 $
 $
 $
 $

 2022

 2021

 12. STOCK COMPENSATION
 Stock-based compensation primarily in the form of Southern Company performance share units (PSU) and restricted stock units (RSU) may be granted through the Equity and Incentive Compensation Plan to Southern Company system employees ranging from line management to executives.
 At December 31, 2023, the number of current and former employees participating in stock-based compensation programs for the Registrants was as follows:

 Number of employees
 1,401

 The majority of PSUs and RSUs awarded contain terms where employees become immediately vested in PSUs and RSUs upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately, while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. In addition, the Registrants recognize forfeitures as they occur.
 II-228

 All unvested PSUs and RSUs vest immediately upon a change in control where Southern Company is not the surviving corporation.
 Performance Share Units
 PSUs granted to employees vest at the end of a three-year performance period. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0 % to 200 % of the target number of PSUs granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors.
 Southern Company has issued two types of PSUs, each with a unique performance goal. These types of PSUs include total shareholder return (TSR) awards based on the TSR for Southern Company common stock during the three -year performance period as compared to a group of industry peers and ROE awards based on Southern Company's equity-weighted return over the performance period.
 The fair value of TSR awards is determined as of the grant date using a Monte Carlo simulation model. In determining the fair value of the TSR awards issued to employees, the expected volatility is based on the historical volatility of Southern Company's stock over a period equal to the performance period. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the awards. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of TSR awards granted:

 Year Ended December 31
 2023
 2022
 2021

 Expected volatility
 30.0 %
 29.6 %
 30.0 %

 Expected term (in years)

 Interest rate
 3.8 %
 1.7 %
 0.2 %

 Weighted average grant-date fair value
 $ 76.83
 $ 79.69
 $ 69.06

 The Registrants recognize TSR award compensation expense on a straight-line basis over the three-year performance period without remeasurement.
 The fair values of ROE awards are based on the closing stock price of Southern Company common stock on the date of the grant. The weighted average grant-date fair value of the ROE awards granted during 2023, 2022, and 2021 was $ 68.93, $ 66.87, and $ 59.49, respectively. Compensation expense for ROE awards is generally recognized ratably over the three-year performance period adjusted for expected changes in ROE performance. Total compensation cost recognized for vested ROE awards reflects final performance metrics.
 Southern Company had 2.4 million unvested PSUs outstanding at December 31, 2022. In February 2023, the PSUs that vested for the three-year performance period ended December 31, 2022 were converted into 1.8 million shares outstanding at a share price of $ 67.13. During 2023, Southern Company granted 1.3 million PSUs and 1.3 million PSUs were vested or forfeited, resulting in 2.4 million unvested PSUs outstanding at December 31, 2023. In February 2024, the PSUs that vested for the three-year performance period ended December 31, 2023 were converted into 2.3 million shares outstanding at a weighted average share price of $ 66.95.
 Total PSU compensation cost, and the related tax benefit recognized in income, for the years ended December 31, 2023, 2022, and 2021 are as follows:

 2023
 2022
 2021

 Compensation cost recognized in income
 $
 $
 $

 Tax benefit of compensation cost recognized in income

 Compensation cost recognized in income
 $
 $
 $

 Tax benefit of compensation cost recognized in income

 Total PSU compensation cost and the related tax benefit recognized in income were immaterial for all periods presented for all other Registrants. The compensation cost related to the grant of Southern Company PSUs to the employees of each Subsidiary Registrant is recognized in each Subsidiary Registrant's financial statements with a corresponding credit to equity representing a capital contribution from Southern Company.
 II-229

 At December 31, 2023, Southern Company's total unrecognized compensation cost related to PSUs was $ 32 million and is expected to be recognized over a weighted-average period of approximately 19 months. The total unrecognized compensation cost related to PSUs at December 31, 2023 was immaterial for all other Registrants.
 Restricted Stock Units
 The fair value of RSUs is based on the closing stock price of Southern Company common stock on the date of the grant. The weighted average grant-date fair values of RSUs granted during 2023, 2022, and 2021 were $ 68.95, $ 67.20, and $ 59.56, respectively. For most RSU awards, one-third of the RSUs vest each year throughout a three-year service period and compensation cost for RSUs is generally recognized over the corresponding one -, two -, or three-year vesting period. Shares of Southern Company common stock are delivered to employees at the end of each vesting period.
 Southern Company had 0.9 million RSUs outstanding at December 31, 2022. During 2023, Southern Company granted 0.5 million RSUs and 0.5 million RSUs were vested or forfeited, resulting in 0.9 million unvested RSUs outstanding at December 31, 2023, including RSUs related to employee retention agreements.
 For the years ended December 31, 2023, 2022, and 2021, Southern Company's total compensation cost for RSUs recognized in income was $ 30 million, $ 26 million, and $ 32 million, respectively. The related tax benefit also recognized in income was $ 8 million, $ 7 million, and $ 8 million for the years ended December 31, 2023, 2022, and 2021, respectively. Total unrecognized compensation cost related to RSUs at December 31, 2023, which is being recognized over a weighted-average period of approximately 17 months, is immaterial for Southern Company.
 Total RSUs outstanding and total compensation cost and related tax benefit for the RSUs recognized in income for the years ended December 31, 2023, 2022, and 2021, as well as the total unrecognized compensation cost at December 31, 2023, were immaterial for all other Registrants. The compensation cost related to the grant of Southern Company RSUs to the employees of each Subsidiary Registrant is recognized in such Subsidiary Registrant's financial statements with a corresponding credit to equity representing a capital contribution from Southern Company.
 Stock Options
 In 2015, Southern Company discontinued granting stock options. As of December 31, 2017, all stock option awards were vested and compensation cost fully recognized. Stock options expire no later than 10 years after the grant date and the latest possible exercise will occur by November 2024. At December 31, 2023, the weighted average remaining contractual term for the options outstanding and exercisable was approximately 2 months.
 Southern Company's activity in the stock option program for 2023 is summarized below:

 Shares Subject to Option
 Weighted Average Exercise Price

 Outstanding at December 31, 2022

 1.0
 $
 42.22

 Exercised
 0.7
 42.54

 Outstanding and Exercisable at December 31, 2023

 0.3
 $
 41.58

 Southern Company's cash receipts from issuances related to stock options exercised under the share-based payment arrangements for the years ended December 31, 2023, 2022, and 2021 were $ 28 million, $ 75 million, and $ 66 million, respectively.
 At December 31, 2023, the aggregate intrinsic value for options outstanding and exercisable was immaterial for all Registrants.
 Total intrinsic value of options exercised, and the related tax benefit, for the years ended December 31, 2023, 2022, and 2021 are presented below for Southern Company and were immaterial for all other Registrants:

 Year Ended December 31
 2023
 2022
 2021

 Intrinsic value of options exercised
 $
 $
 $

 Tax benefit of options exercised

 II-230

 13. FAIR VALUE MEASUREMENTS
 Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.
 • Level 1 consists of observable market data in an active market for identical assets or liabilities.
 • Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.
 • Level 3 consists of unobservable market data. The input may reflect the assumptions of each Registrant of what a market participant would use in pricing an asset or liability. If there is little available market data, then each Registrant's own assumptions are the best available information.
 In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.
 Net asset value as a practical expedient is the classification used for assets that do not have readily determined fair values. Fund managers value the assets using various inputs and techniques depending on the nature of the underlying investments.

 II-231

 At December 31, 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:

 (NAV)
 Total

 $
 $
 $
 —
 $
 —
 $

 Investments in trusts:(b)

 —
 —

 —
 —

 —
 —
 —

 —
 —
 —

 Pooled funds – fixed income
 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 Other
 —

 Cash equivalents and restricted cash

 —
 —

 Other investments
 —

 Total
 $
 1,238
 $
 1,382
 $
 $
 $
 2,806

 $
 $
 $
 —
 $
 —
 $

 —
 —
 —

 —
 —
 —

 Contingent consideration
 —
 —

 Other
 —
 —
 —

 Total
 $
 $
 $
 $
 —
 $

 II-232

 (NAV)
 Total

 $
 —
 $
 $
 —
 $
 —
 $

 Nuclear decommissioning trusts:(b)

 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 Other
 —
 —

 Cash equivalents and restricted cash

 —
 —

 Other investments
 —
 —
 —

 Total
 $
 $
 $
 —
 $
 $
 1,435

 $
 —
 $
 $
 —
 $
 —
 $

 $
 —
 $
 $
 —
 $
 —
 $

 Nuclear decommissioning trusts:(b)

 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 Other
 —
 —

 Total
 $
 $
 $
 —
 $
 —
 $
 1,176

 $
 —
 $
 $
 —
 $
 —
 $

 II-233

 (NAV)
 Total

 $
 —
 $
 $
 —
 $
 —
 $

 —
 —
 —

 Total
 $
 $
 $
 —
 $
 —
 $

 $
 —
 $
 $
 —
 $
 —
 $

 $
 —
 $
 $
 —
 $
 —
 $

 $
 —
 $
 $
 —
 $
 —
 $

 —
 —
 —

 Contingent consideration
 —
 —

 Other
 —
 —
 —

 Total
 $
 $
 $
 $
 —
 $

 $
 $
 $
 —
 $
 —
 $

 Non-qualified deferred compensation trusts:

 —
 —
 —

 —
 —
 —

 Pooled funds - fixed income
 —
 —
 —

 —
 —
 —

 Total
 $
 $
 $
 —
 $
 —
 $

 Energy-related derivatives(a)(b)

 $
 $
 $
 —
 $
 —
 $

 —
 —
 —

 Total
 $
 $
 $
 —
 $
 —
 $

 (a)Excludes cash collateral of $ 62 million.
 (b)Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 under "Nuclear Decommissioning" for additional information.
 II-234

 At December 31, 2022, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

 (NAV)
 Total

 $
 $
 $
 —
 $
 —
 $

 —
 —
 —

 Investments in trusts:(b)(c)

 —
 —

 —
 —

 —
 —
 —

 —
 —
 —

 Pooled funds – fixed income
 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 Other
 —
 —

 1,427
 —
 —
 1,447

 Other investments
 —
 —

 Total
 $
 2,271
 $
 1,424
 $
 —
 $
 $
 3,856

 $
 $
 $
 —
 $
 —
 $

 —
 —
 —

 —
 —
 —

 Contingent consideration
 —
 —
 —

 Other
 —
 —
 —

 Total
 $
 $
 $
 $
 —
 $

 II-235

 (NAV)
 Total

 $
 —
 $
 $
 —
 $
 —
 $

 Nuclear decommissioning trusts:(b)

 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 Other
 —
 —
 —

 —
 —

 Other investments
 —
 —
 —

 Total
 $
 $
 $
 —
 $
 $
 1,671

 $
 —
 $
 $
 —
 $
 —
 $

 $
 —
 $
 $
 —
 $
 —
 $

 Nuclear decommissioning trusts:(b)(c)

 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 —
 —
 —

 Other
 —
 —

 —
 —
 —

 Total
 $
 $
 $
 —
 $
 —
 $
 1,415

 $
 —
 $
 $
 —
 $
 —
 $

 II-236

 (NAV)
 Total

 $
 —
 $
 $
 —
 $
 —
 $

 —
 —
 —

 Total
 $
 $
 $
 —
 $
 —
 $

 $
 —
 $
 $
 —
 $
 —
 $

 $
 —
 $
 $
 —
 $
 —
 $

 $
 —
 $
 $
 —
 $
 —
 $

 —
 —
 —

 Contingent consideration
 —
 —
 —

 Other
 —
 —
 —

 Total
 $
 —
 $
 $
 $
 —
 $

 $
 $
 $
 —
 $
 —
 $

 Non-qualified deferred compensation trusts:

 —
 —
 —

 —
 —
 —

 Pooled funds - fixed income
 —
 —
 —

 —
 —
 —

 —
 —
 —

 Total
 $
 $
 $
 —
 $
 —
 $

 Energy-related derivatives(a)(b)

 $
 $
 $
 —
 $
 —
 $

 —
 —
 —

 Total
 $
 $
 $
 —
 $
 —
 $

 (a)Excludes cash collateral of $41 million.
 (b)Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 under "Nuclear Decommissioning" for additional information.
 (c)Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. See Note 6 under "Nuclear Decommissioning" for additional information.
 II-237

 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 14 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 under "Nuclear Decommissioning" 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.
 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 $ 178 million and $ 161 million at December 31, 2023 and 2022, respectively. Unfunded commitments related to the private market investments totaled $ 87 million and $ 78 million at December 31, 2023 and 2022, respectively. 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.
 II-238

 At December 31, 2023 and 2022, other financial instruments for which the carrying amount did not equal fair value were as follows:

 Company(*)

 Gas(*)

 Long-term debt, including securities due within one year:

 Carrying amount
 $
 59.4
 $
 11.2
 $
 16.5
 $
 1.6
 $
 2.7
 $
 7.8

 Fair value
 55.0
 10.1
 15.1
 1.4
 2.6
 6.8

 Long-term debt, including securities due within one year:

 Carrying amount
 $
 54.6
 $
 10.6
 $
 14.7
 $
 1.5
 $
 3.0
 $
 7.4

 Fair value
 48.6
 9.2
 13.0
 1.3
 2.8
 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.

 14. 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 13 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 under "Financial Instruments" for additional information. See Note 15 under "Southern Company Gas" for additional information regarding the sale of Sequent.
 Energy-Related Derivatives
 The Subsidiary Registrants enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which are expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.
 Southern Company Gas also enters into weather derivative contracts as economic hedges in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.
 II-239

 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 AOCI 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 December 31, 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

 2030
 2028

 2026
 —

 2026
 —

 2028
 —

 2030
 2024

 Southern Company Gas(*)

 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 long natural gas positions of 112 million mmBtu and short natural gas positions of 10 million mmBtu at December 31, 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 12 million mmBtu for Southern Company, which includes 3 million mmBtu for Alabama Power, 4 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 gains (losses) expected to be reclassified from AOCI to earnings for the year ending December 31, 2024 are $( 37) million for Southern Company, $( 4) million for Southern Power, and $( 33) million for Southern Company Gas.
 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.
 II-240

 At December 31, 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) December 31, 2023

 Cash Flow Hedges of Forecasted Debt

 $
 4.01 %
 N/A
 April 2024
 $
 —

 3.84 %
 N/A
 June 2024
 —

 4.04 %
 N/A
 June 2024
 —

 Fair Value Hedges of Existing Debt

 Southern Company parent
 1-month SOFR + 0.80 %

 1.75 %
 March 2028
 ( 46)

 Southern Company parent
 1,000
 1-month SOFR + 2.48 %

 3.70 %
 April 2030
 ( 139)

 1-month SOFR + 0.49 %

 1.75 %
 January 2031
 ( 79)

 $
 2,200
 $
 ( 264)

 For cash flow hedges of interest rate derivatives, the estimated pre-tax losses expected to be reclassified from AOCI to interest expense for the year ending December 31, 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 2054 for Southern Company, Georgia Power, and Mississippi Power, 2052 for Alabama 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 December 31, 2023, the following foreign currency derivatives were outstanding:

 Pay Notional
 Pay Rate
 Receive Notional
 Receive Rate
 Hedge
Maturity Date
 Fair Value
Gain (Loss) December 31, 2023

 Cash Flow Hedges of Existing Debt

 $
 3.78 %

 1.85 %
 June 2026
 $
 ( 22)

 Fair Value Hedges of Existing Debt

 Southern Company parent
 1,476
 3.39 %
 1,250
 1.88 %
 September 2027
 ( 100)

 $
 2,040

 1,750
 $
 ( 122)

 For cash flow hedges of foreign currency derivatives, the estimated pre-tax losses expected to be reclassified from AOCI to earnings for the year ending December 31, 2024 are $ 11 million for Southern Power.
 II-241

 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:

 2023
 2022

 Derivative Category and Balance Sheet Location

 Energy-related derivatives designated as hedging instruments for regulatory purposes

 Assets from risk management activities/Liabilities from risk management activities
 $
 $
 $
 $

 Total derivatives designated as hedging instruments for regulatory purposes

 Derivatives designated as hedging instruments in cash flow and fair value hedges

 Assets from risk management activities/Liabilities from risk management activities
 —

 Interest rate derivatives:

 Assets from risk management activities/Liabilities from risk management activities
 —

 —
 —

 Foreign currency derivatives:

 Assets from risk management activities/Liabilities from risk management activities
 —
 —

 —
 —

 Total derivatives designated as hedging instruments in cash flow and fair value hedges

 Energy-related derivatives not designated as hedging instruments

 Assets from risk management activities/Liabilities from risk management activities

 Total derivatives not designated as hedging instruments

 Gross amounts recognized

 Gross amounts offset(a)

 ( 23)
 ( 85)
 ( 70)
 ( 111)

 Net amounts recognized in the Balance Sheets(b)

 $
 $
 $
 $

 II-242

 2023
 2022

 Derivative Category and Balance Sheet Location

 Alabama Power(c)

 Energy-related derivatives designated as hedging instruments for regulatory purposes

 $
 $
 $
 $

 Total derivatives designated as hedging instruments for regulatory purposes

 Gross amounts offset
 ( 10)
 ( 10)
 ( 24)
 ( 24)

 Net amounts recognized in the Balance Sheets
 $
 $
 $
 $

 Energy-related derivatives designated as hedging instruments for regulatory purposes

 $
 $
 $
 $

 Total derivatives designated as hedging instruments for regulatory purposes

 Energy-related derivatives not designated as hedging instruments

 —
 —

 Gross amounts recognized

 Gross amounts offset
 ( 11)
 ( 11)
 ( 21)
 ( 21)

 Net amounts recognized in the Balance Sheets
 $
 $
 $
 $

 Mississippi Power(c)

 Energy-related derivatives designated as hedging instruments for regulatory purposes

 $
 $
 $
 $

 Total derivatives designated as hedging instruments for regulatory purposes

 Gross amounts offset
 ( 14)
 ( 14)
 ( 17)
 ( 17)

 Net amounts recognized in the Balance Sheets
 $
 $
 $
 $

 II-243

 2023
 2022

 Derivative Category and Balance Sheet Location

 Derivatives designated as hedging instruments in cash flow and fair value hedges

 $
 —
 $
 $
 —
 $

 —
 —

 Foreign currency derivatives:

 —
 —

 —
 —

 Total derivatives designated as hedging instruments in cash flow and fair value hedges

 Energy-related derivatives not designated as hedging instruments

 —
 —
 —

 —
 —
 —

 Total derivatives not designated as hedging instruments
 —
 —
 —

 Net amounts recognized in the Balance Sheets
 $
 $
 $
 $

 Energy-related derivatives designated as hedging instruments for regulatory purposes

 $
 $
 $
 $

 Derivatives designated as hedging instruments in cash flow and fair value hedges

 —

 —

 Interest rate derivatives:

 —
 —

 —
 —

 Total derivatives designated as hedging instruments in cash flow and fair value hedges
 —

 Energy-related derivatives not designated as hedging instruments

 Total derivatives not designated as hedging instruments

 Gross amounts recognized

 Gross amounts offset(a)

 ( 50)
 —
 ( 41)

 Net amounts recognized in the Balance Sheets(b)

 $
 $
 $
 $

 (a)Gross amounts offset includes cash collateral held on deposit in broker margin accounts of $ 62 million and $ 41 million at December 31, 2023 and 2022, respectively.
 (b)Net amounts of derivative instruments outstanding exclude immaterial premium and intrinsic value associated with weather derivatives for all periods presented.
 (c)Energy-related derivatives not designated as hedging instruments were immaterial at December 31, 2022. There were no such instruments at December 31, 2023.
 II-244

 At December 31, 2023 and 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 Sheets

 Derivative Category and Balance Sheet
Power
Power
Power

 Other regulatory assets, current
 $
 ( 180)
 $
 ( 67)
 $
 ( 80)
 $
 ( 25)
 $
 ( 8)

 ( 87)
 ( 32)
 ( 33)
 ( 22)
 —

 Other regulatory liabilities, current
 —

 —
 —
 —

 Total energy-related derivative gains (losses)
 $
 $
 ( 95)
 $
 ( 112)
 $
 ( 46)
 $
 ( 4)

 Other regulatory assets, current
 $
 ( 71)
 $
 ( 8)
 $
 ( 26)
 $
 ( 13)
 $
 ( 24)

 ( 23)
 ( 7)
 ( 14)
 ( 2)
 —

 Other regulatory liabilities, current

 —

 Total energy-related derivative gains (losses)
 $
 $
 $
 ( 19)
 $
 $
 ( 22)

 For the years ended December 31, 2023, 2022, and 2021, the pre-tax effects of cash flow and fair value hedge accounting on AOCI for the applicable Registrants were as follows:

 Gain (Loss) From Derivatives Recognized in OCI
 2023
 2022
 2021

 Cash flow hedges:

 $
 ( 81)
 $
 $

 ( 12)

 ( 105)
 ( 103)

 Fair value hedges(*):

 ( 24)
 ( 3)

 Total
 $
 ( 58)
 $
 ( 80)
 $
 ( 67)

 Cash flow hedges:

 $
 ( 2)
 $
 $
 —

 Cash flow hedges:

 $
 ( 18)
 $
 ( 15)
 $

 ( 105)
 ( 103)

 Total
 $
 ( 4)
 $
 ( 120)
 $
 ( 91)

 Cash flow hedges:

 $
 ( 63)
 $
 $

 (*)Represents amounts excluded from the assessment of effectiveness for which the difference between changes in fair value and periodic amortization is recorded in OCI.
 II-245

 The pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on AOCI were immaterial for Alabama Power for all years presented and immaterial for Mississippi Power in 2023.
 The pre-tax effects of cash flow and fair value hedge accounting on income for the years ended December 31, 2023, 2022, and 2021 were as follows:

 Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships
 2023
 2022
 2021

 Total cost of natural gas
 $
 1,644
 $
 3,004
 $
 1,619

 ( 44)

 Total other operations and maintenance
 6,093
 6,573
 5,902

 ( 2)
 —
 —

 Total depreciation and amortization
 4,525
 3,663
 3,565

 ( 23)
 ( 5)

 Total interest expense, net of amounts capitalized
 ( 2,446)
 ( 2,022)
 ( 1,837)

 Gain (loss) on interest rate cash flow hedges(a)

 ( 35)
 ( 25)
 ( 27)

 Gain (loss) on foreign currency cash flow hedges(a)

 ( 11)
 ( 19)
 ( 24)

 Gain (loss) on interest rate fair value hedges(b)

 ( 291)
 ( 30)

 Total other income (expense), net

 Gain (loss) on foreign currency cash flow hedges(a)(c)

 ( 83)

 Gain (loss) on foreign currency fair value hedges
 ( 63)

 Amount excluded from effectiveness testing recognized in earnings
 ( 21)

 Total depreciation and amortization
 $
 $
 $

 ( 23)
 ( 5)

 Total interest expense, net of amounts capitalized
 ( 129)
 ( 138)
 ( 147)

 Gain (loss) on foreign currency cash flow hedges(a)

 ( 11)
 ( 19)
 ( 24)

 Total other income (expense), net

 Gain (loss) on foreign currency cash flow hedges(a)(c)

 ( 83)

 Total cost of natural gas
 $
 1,644
 $
 3,004
 $
 1,619

 ( 44)

 Total other operations and maintenance

 1,194
 1,176
 1,072

 ( 2)
 —
 —

 Total interest expense, net of amounts capitalized
 ( 310)
 ( 263)
 ( 238)

 Gain (loss) on interest rate cash flow hedges(a)

 ( 19)
 ( 4)
 —

 Gain (loss) on interest rate fair value hedges(b)

 ( 86)
 —

 (a)Reclassified from AOCI 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 AOCI 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 hedge accounting on income for interest rate derivatives were immaterial for the traditional electric operating companies for all years presented.
 II-246

 At December 31, 2023 and 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

 Long-term debt
 $
 ( 3,024)
 $
 ( 2,927)
 $
 $

 Long-term debt
 $
 ( 427)
 $
 ( 415)
 $
 $

 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 for the years ended December 31, 2023, 2022, and 2021 were as follows:

 Gain (Loss)

 Derivatives in Non-Designated Hedging Relationships
 Statements of Income Location
 2023
 2022
 2021

 Natural gas revenues(*)

 $
 —
 $
 ( 11)
 $
 ( 117)

 ( 65)
 ( 27)

 Total derivatives in non-designated hedging relationships
 $
 $
 ( 76)
 $
 ( 144)

 (*) Excludes the impact of weather derivatives recorded in natural gas revenues of $ 15 million and $( 7) million for 2023 and 2022, respectively, as they are accounted for based on intrinsic value rather than fair value. There was no weather derivatives impact for 2021.
 The pre-tax effects of energy-related derivatives not designated as hedging instruments were immaterial for all other Registrants for all years presented.
 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 December 31, 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 $ 52 million at December 31, 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 immaterial at December 31, 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 December 31, 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 December 31, 2023, cash collateral posted in these accounts was immaterial for Alabama Power and Southern 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 December 31, 2023, cash collateral held on deposit in broker margin accounts was $ 62 million.
 II-247

 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.

 15. ACQUISITIONS AND DISPOSITIONS
 None of the dispositions discussed herein, both individually and combined, represented a strategic shift in operations for the applicable Registrants that has, or is expected to have, a major effect on its operations and financial results; therefore, none of the assets related to the sales have been classified as discontinued operations for any of the periods presented.

 In October 2021, Southern Company completed the sale of a leveraged lease investment to the lessee for $ 45 million. No gain or loss was recognized on the sale; however, it did result in the recognition of approximately $ 16 million of additional tax benefits. Prior to the sale, in the second quarter 2021, a charge of $ 7 million ($ 6 million after tax) was recorded to reduce the investment to its estimated fair value, less costs to sell.
 In December 2021, Southern Company completed the termination of its leasehold interest in assets associated with its two international leveraged lease projects and received cash proceeds of approximately $ 673 million after the accelerated exercise of the lessee's purchase options. The pre-tax gain associated with the transaction was approximately $ 93 million ($ 99 million gain after tax).

 In September 2022, Alabama Power completed its acquisition of the Calhoun Generating Station, which was accounted for as an asset acquisition. The total purchase price was $ 179 million, of which $ 171 million was related to net assets recorded within property, plant, and equipment on the balance sheet and reflected in property additions within the investing section of the statement of cash flows. The remainder primarily related to fossil fuel stock and materials and supplies. See Note 2 under "Alabama Power – Rate CNP New Plant" for additional information.
 II-248

 Southern Power's acquisition-related costs for the projects discussed under "Asset Acquisitions" and "Construction Projects" were not material for any of the years presented. There were no asset acquisitions during 2022.
 Asset Acquisitions

 Project
Facility
 Resource
 Seller
 Approximate Nameplate Capacity (MW)

Power
Ownership
Percentage
 Expected/Actual COD

 PPA
Contract Period

 Asset Acquisitions During 2023

 Millers Branch(a)

 Solar
 EDF Renewables
 Development, Inc.

 Haskell County, TX
 100 %

 Fourth quarter 2025
 20 years

 South Cheyenne
 Solar
 Hanwha Q Cells USA Corp.
 Laramie County, WY
 100 %
 Second quarter 2024

 20 years

 Asset Acquisitions During 2021

 Deuel Harvest(b)

 Wind
 Invenergy Renewables LLC
 Deuel County, SD
 100 % of Class B

 February 2021
 25 years
 and
 15 years

 (a)The project includes an option to expand capacity up to an additional 300 MWs. Subsequent to December 31, 2023, Southern Power committed to expand the construction of the facility through a second phase adding up to 205 MWs, with commercial operation expected to occur in the second quarter 2026.
 (b)In March 2021, Southern Power acquired a controlling interest in the project from Invenergy Renewables LLC and completed a tax equity transaction whereby it sold the Class A membership interests in the project. Southern Power consolidates the project's operating results in its financial statements and the tax equity partner and Invenergy Renewables LLC each own a noncontrolling interest.
 The aggregate purchase price for the two projects acquired during 2023 was $ 193 million, which is primarily recorded within construction work in progress on the balance sheet at December 31, 2023.
 Construction Projects

 Project
Facility
 Resource
 Approximate Nameplate Capacity (MW)

 COD
 PPA Contract Period

 Projects Completed During 2022

 Garland Solar Storage(a)

 Battery energy storage
 September 2021 through February 2022(b)

 20 years

 Tranquillity Solar Storage(a)

 Battery energy storage
 Fresno County, CA
 November 2021 through
 March 2022(c)

 20 years

 Projects Completed During 2021

 Glass Sands(d)

 Wind
 Murray County, OK
 November 2021
 12 years

 (a)In 2020, Southern Power restructured its ownership of the project, while retaining the controlling interests, by contributing the Class A membership interests to an existing partnership and selling 100 % of the Class B membership interests. During 2021, Southern Power further restructured its ownership in the battery energy storage projects and completed tax equity transactions whereby it sold the Class A membership interests in the projects. Southern Power consolidates each project's operating results in its financial statements and the tax equity partner and two other partners each own a noncontrolling interest. See Note 9 under "Lessor" for additional information.
 (b)The facility has a total capacity of 88 MWs, of which 73 MWs were placed in service in 2021 and 15 MWs were placed in service in 2022.
 (c)The facility has a total capacity of 72 MWs, of which 32 MWs were placed in service in 2021 and 40 MWs were placed in service in 2022.
 (d)In December 2020, Southern Power purchased 100 % of the membership interests of the Glass Sands facility.
 Development Projects
 Southern Power purchased wind turbine equipment in 2016 and 2017 for deployment to development and construction projects. All of this equipment has either been deployed to projects that have been completed or has been sold to third parties. Gains on wind turbine equipment contributed to various equity method investments totaled approximately $ 37 million in 2021.
 II-249

 Sale of Sequent
 In July 2021, Southern Company Gas affiliates completed the sale of Sequent to Williams Field Services Group for a total cash purchase price of $ 159 million, including final working capital adjustments. The pre-tax gain associated with the transaction was approximately $ 121 million ($ 92 million after tax). The sale resulted in $ 85 million of additional tax expense.
 Sale of Natural Gas Storage Facilities
 In September 2022, certain affiliates of Southern Company Gas entered into agreements to sell two natural gas storage facilities located in California and Texas for an aggregate purchase price of $ 186 million, plus working capital and certain other adjustments. The sale of the Texas facility was completed in November 2022 and the sale of the California facility was completed on September 22, 2023. Both sales resulted in an immaterial loss. Completion of the sale of the Texas facility was subject to release of a Southern Company Gas parent guarantee, which was executed in October 2022 and, as a result, Southern Company Gas recorded pre-tax impairment charges totaling approximately $ 131 million ($ 99 million after tax) in the fourth quarter 2022.

 16. SEGMENT AND RELATED INFORMATION

 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 $ 537 million, $ 875 million, and $ 515 million in 2023, 2022, and 2021, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were immaterial for all periods presented. Revenues from sales of natural gas from Southern Company Gas (prior to its sale of Sequent) to Southern Power were $ 18 million in 2021. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing distributed energy and resilience solutions and deploying microgrids for commercial, industrial, governmental, and utility customers, as well as investments in telecommunications. All other inter-segment revenues are not material.
 II-250

 Financial data for business segments and products and services for the years ended December 31, 2023, 2022, and 2021 was as follows:

 Electric Utilities

 Traditional
Operating
Companies
Power
 Eliminations
 Total
 All
Other
 Eliminations
 Consolidated

 2023

 $
 18,358
 $
 2,189
 $
 ( 549)
 $
 19,998
 $
 4,702
 $
 $
 $
 25,253

 3,361
 —
 3,865
 —
 4,525

 Interest income
 —
 ( 26)

 ( 1)
 —
 —
 ( 1)
 —

 1,145
 —
 1,274
 ( 17)
 2,446

 —
 ( 298)
 —

 Segment net income (loss)(a)(b)(c)(d)

 3,637
 —
 3,994
 ( 635)
 3,976

 —
 —
 5,015
 —
 5,161

 100,429
 12,761
 ( 545)
 112,645
 25,083
 2,446
 ( 843)
 139,331

 2022

 $
 20,408
 $
 3,369
 $
 ( 904)
 $
 22,873
 $
 5,962
 $
 $
 ( 149)
 $
 29,279

 2,513
 —
 3,029
 —
 3,663

 Interest income
 —
 ( 7)

 —
 —
 —
 —
 —

 —
 1,067
 ( 2)
 2,022

 —
 ( 233)
 —

 Segment net income (loss)(a)(b)(e)(f)

 3,318
 —
 3,672
 ( 711)
 ( 9)
 3,524

 —
 —
 5,015
 —
 5,161

 95,861
 13,081
 ( 659)
 108,283
 24,621
 2,665
 ( 678)
 134,891

 2021

 $
 16,614
 $
 2,216
 $
 ( 530)
 $
 18,300
 $
 4,380
 $
 $
 ( 149)
 $
 23,113

 2,436
 —
 2,953
 —
 3,565

 Interest income
 —
 —
 ( 3)

 —
 —

 —
 —
 1,837

 ( 13)
 —
 ( 227)
 —

 Segment net income (loss)(a)(b)(g)(h)(i)

 1,981
 —
 2,247
 ( 384)
 ( 9)
 2,393

 —
 —
 5,015
 —
 5,280

 89,051
 13,390
 ( 667)
 101,774
 23,560
 2,975
 ( 775)
 127,534

 II-251

 (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 $( 68) million ($( 50) million after tax) in 2023, $ 183 million ($ 137 million after tax) in 2022, and $ 1.7 billion ($ 1.3 billion after tax) in 2021. See Note 2 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) related to an arbitration award and a $ 16 million pre-tax gain ($ 12 million after tax) on the sale of spare parts. See Note 3 under "General Litigation Matters – Southern Power" for additional information.
 (d)For Southern Company Gas, includes pre-tax charges totaling approximately $ 96 million ($ 72 million after tax) associated with the disallowance of certain capital investments at Nicor Gas. See Note 2 under "Southern Company Gas" for additional information.
 (e)For Southern Company Gas, includes pre-tax impairment charges totaling approximately $ 131 million ($ 99 million after tax) related to the sale of natural gas storage facilities. See Note 15 under "Southern Company Gas" for additional information.
 (f)For the "All Other" column, includes a $ 119 million goodwill impairment loss (pre-tax and after tax) at PowerSecure. See Note 1 under "Goodwill and Other Intangible Assets" for additional information.
 (g)For Southern Power, includes gains on wind turbine equipment contributed to various equity method investments totaling approximately $ 37 million pre-tax ($ 28 million after tax). See Notes 7 and 15 under "Southern Power" for additional information.
 (h)For Southern Company Gas, includes a pre-tax gain of $ 121 million ($ 92 million after tax) related to its sale of Sequent, as well as the resulting $ 85 million of additional tax expense due to changes in state apportionment rates, and pre-tax impairment charges totaling $ 84 million ($ 67 million after tax) related to its equity method investment in the PennEast Pipeline project. See Notes 7 and 15 under "Southern Company Gas" for additional information.
 (i)For the "All Other" column, includes a pre-tax gain of $ 93 million ($ 99 million gain after tax) associated with the termination of two leveraged leases projects. See Note 15 under "Southern Company" for additional information.
 Products and Services

 Electric Utilities' Revenues

 Year
 Retail
 Other
 Total

 2023
 $
 16,343
 $
 2,467
 $
 1,188
 $
 19,998

 2022
 18,197
 3,641
 1,035
 22,873

 2021
 14,852
 2,455
 18,300

 Southern Company Gas' Revenues

 Year
 Gas
Distribution
Operations
 Gas
Marketing
Services
 All Other
 Total

 2023
 $
 4,090
 $
 $
 $
 4,702

 2022
 5,240
 5,962

 2021
 3,656
 4,380

 II-252

 Southern Company Gas manages its business through three reportable segments – gas distribution operations, gas pipeline investments, and gas marketing services. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' reportable segments also included wholesale gas services. The non-reportable segments are combined and presented as all other. See Note 15 under "Southern Company Gas" for additional information on the disposition activities described herein.
 Gas distribution operations is the largest component of Southern Company Gas' business and includes natural gas local distribution utilities that construct, manage, and maintain intrastate natural gas pipelines and gas distribution facilities in four states.
 Gas pipeline investments consists of joint ventures in natural gas pipeline investments including a 50 % interest in SNG 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 Notes 5 and 7 for additional information.
 Through July 1, 2021, wholesale gas services provided natural gas asset management and/or related logistics services for each of Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. Additionally, wholesale gas services engaged in natural gas storage and gas pipeline arbitrage and related activities.
 Gas marketing services provides natural gas marketing to end-use customers primarily in Georgia and Illinois through SouthStar.
 The all other column includes segments and subsidiaries that fall below the quantitative threshold for separate disclosure, including storage and fuels operations. 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.
 II-253

 Financial data for business segments for the years ended December 31, 2023, 2022, and 2021 was as follows:

 Gas Pipeline Investments
 Wholesale Gas Services(a)

 Gas Marketing Services
 Total
 All Other
 Eliminations
 Consolidated

 2023

 $
 4,105
 $
 $
 —
 $
 $
 4,685
 $
 $
 ( 19)
 $
 4,702

 —
 —

 Operating income (loss)
 —
 ( 4)
 ( 13)

 —
 —
 —
 —
 —

 —
 —

 —
 —

 Segment net income (loss)(b)

 —
 ( 15)
 —

 22,906
 1,534
 —
 1,615
 26,055
 9,675
 ( 10,647)
 25,083

 2022

 $
 5,267
 $
 $
 —
 $
 $
 5,937
 $
 $
 ( 30)
 $
 5,962

 —
 —

 Operating income (loss)
 —
 ( 135)
 ( 8)

 —
 —
 —
 —
 —

 —
 —

 —
 ( 37)
 —

 Segment net income (loss)(c)

 —
 ( 99)
 —

 22,040
 1,577
 —
 1,616
 25,233
 8,943
 ( 9,555)
 24,621

 2021

 $
 3,679
 $
 $
 $
 $
 4,374
 $
 $
 ( 32)
 $
 4,380

 —
 —

 Operating income (loss)
 1,095
 ( 40)
 —
 1,055

 —
 —
 —
 —
 —

 —

 —

 Segment net income (loss)(d)(e)(f)

 ( 87)
 —

 20,917
 1,467
 1,556
 23,971
 12,114
 ( 12,525)
 23,560

 (a)As a result of the sale of Sequent, wholesale gas services is no longer a reportable segment in 2023 or 2022. Prior to the sale of Sequent, the revenues for wholesale gas services were netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table.

 Third Party Gross Revenues
 Intercompany Revenues
 Total Gross Revenues
 Less Gross Gas Costs

 2021
 $
 3,881
 $
 $
 3,971
 $
 3,783
 $

 (b)For gas distribution operations, includes pre-tax charges totaling approximately $ 96 million ($ 72 million after tax) associated with the disallowance of certain capital investments at Nicor Gas. See Note 2 under "Southern Company Gas" for additional information.
 (c)For the "All Other" column, includes pre-tax impairment charges totaling approximately $ 131 million ($ 99 million after tax) related to the sale of natural gas storage facilities. See Note 15 under "Southern Company Gas" for additional information.
 (d)For gas pipeline investments, includes pre-tax impairment charges totaling $ 84 million ($ 67 million after tax) related to the equity method investment in the PennEast Pipeline project. See Note 7 under "Southern Company Gas" for additional information.
 (e)For wholesale gas services, includes a pre-tax gain of $ 121 million ($ 92 million after tax) related to the sale of Sequent.
 (f)For the "All Other" column, includes $ 85 million of additional tax expense as a result of the sale of Sequent.

 II-254

 Item 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
 None.

 Item 9A.CONTROLS AND PROCEDURES
 Disclosure Controls and Procedures.
 As of the end of the period covered by this Annual Report on Form 10-K, 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 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) of the Securities Exchange Act of 1934, as amended). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.
 Internal Control Over Financial Reporting.
 (a) Management's Annual Report on Internal Control Over Financial Reporting.

 Page

 II- 256

 II- 257

 II- 258

 II- 259

 II- 260

 II- 261

 (b) Attestation Report of the Registered Public Accounting Firm.
 The report of Deloitte & Touche LLP, Southern Company's independent registered public accounting firm, regarding Southern Company's Internal Control over Financial Reporting is included in Item 8 herein of this Form 10-K. This report is not applicable to Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas as these companies are not accelerated filers or large accelerated filers.
 (c) 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 fourth 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.
 Item 9B.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 December 31, 2023 by the Registrants' directors and "officers," as defined in Rule 16a-1(f) under the Securities Exchange Act of 1934, as amended.
 Item 9C.DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
 Not applicable.
 II-255

 The management of Southern Company is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
 Under management's supervision, an evaluation of the design and effectiveness of Southern Company's internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Southern Company's internal control over financial reporting was effective as of December 31, 2023.
 Deloitte & Touche LLP, as auditors of Southern Company's financial statements, has issued an attestation report on the effectiveness of Southern Company's internal control over financial reporting as of December 31, 2023, which is included herein.

 /s/ Christopher C. Womack

 /s/ Daniel S. Tucker
 Daniel S. Tucker
 Executive Vice President and Chief Financial Officer

 II-256

 The management of Alabama Power is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
 Under management's supervision, an evaluation of the design and effectiveness of Alabama Power's internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Alabama Power's internal control over financial reporting was effective as of December 31, 2023.

 /s/ J. Jeffrey Peoples
 J. Jeffrey Peoples

 /s/ Moses H. Feagin
 Moses H. Feagin

 II-257

 The management of Georgia Power is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
 Under management's supervision, an evaluation of the design and effectiveness of Georgia Power's internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Georgia Power's internal control over financial reporting was effective as of December 31, 2023.

 /s/ Kimberly S. Greene
 Kimberly S. Greene

 /s/ Aaron P. Abramovitz
 Aaron P. Abramovitz

 II-258

 The management of Mississippi Power is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
 Under management's supervision, an evaluation of the design and effectiveness of Mississippi Power's internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Mississippi Power's internal control over financial reporting was effective as of December 31, 2023.

 /s/ Anthony L. Wilson
 Anthony L. Wilson

 /s/ Matthew P. Grice
 Matthew P. Grice
 Vice President, Chief Financial Officer, and Treasurer

 II-259

 The management of Southern Power is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
 Under management's supervision, an evaluation of the design and effectiveness of Southern Power's internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Southern Power's internal control over financial reporting was effective as of December 31, 2023.

 /s/ Christopher Cummiskey
 Christopher Cummiskey
 Chairman and Chief Executive Officer

 /s/ Gary Kerr
 Gary Kerr
 Senior Vice President, Chief Financial Officer, and Treasurer

 II-260

 The management of Southern Company Gas is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
 Under management's supervision, an evaluation of the design and effectiveness of Southern Company Gas' internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Southern Company Gas' internal control over financial reporting was effective as of December 31, 2023.

 /s/ James Y. Kerr II
 James Y. Kerr II

 /s/ Grace A. Kolvereid
 Grace A. Kolvereid
 II-261

 Items 10 (other than the information under "Code of Ethics" below), 11, 12, 13, and 14 for Southern Company are incorporated by reference to Southern Company's Definitive Proxy Statement relating to the 2024 Annual Meeting of Stockholders. Specifically, reference is made to "Corporate Governance at Southern Company" and "Biographical Information about our Nominees for Director," as well as "Delinquent Section 16(a) Reports," if required, for Item 10, "Compensation Discussion and Analysis," "Executive Compensation Tables," and "Director Compensation" for Item 11, "Stock Ownership Information," "Executive Compensation Tables," and "Equity Compensation Plan Information" for Item 12, "Biographical Information about our Nominees for Director" and "Corporate Governance at Southern Company" for Item 13, and "Principal Independent Registered Public Accounting Firm Fees" for Item 14.
 Items 10, 11, 12, and 13 for each of the Subsidiary Registrants are omitted pursuant to General Instruction I(2)(c) of Form 10-K. Item 14 for each of the Subsidiary Registrants is contained herein.

 Item 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
 Code of Ethics
 The Registrants collectively have adopted a code of business conduct and ethics (Code of Ethics) that applies to each director, officer, and employee of the Registrants and their subsidiaries. The Code of Ethics can be found on Southern Company's website located at www.southerncompany.com. The Code of Ethics is also available free of charge in print to any shareholder by requesting a copy from Myra C. Bierria, Corporate Secretary, Southern Company, 30 Ivan Allen Jr. Boulevard NW, Atlanta, Georgia 30308. Any amendment to or waiver from the Code of Ethics that applies to executive officers and directors will be posted on the website.
 III-1

 Item 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES
 The following represents fees billed to the Subsidiary Registrants in 2023 and 2022 by Deloitte & Touche LLP, each company's principal public accountant:

 2023
 2022

 (in thousands)

 Audit Fees (1)

 $
 3,830
 $
 2,860

 Audit-Related Fees (2)

 —
 —

 Total
 $
 4,095
 $
 3,185

 Audit Fees (1)

 $
 5,611
 $
 3,973

 Audit-Related Fees (4)

 —
 —

 Total
 $
 5,907
 $
 4,428

 Audit Fees (1)

 $
 $
 1,432

 Audit-Related Fees (5)

 —
 —

 Total
 $
 $
 1,574

 Audit Fees (1)

 $
 1,105
 $
 1,671

 Audit-Related Fees(6)

 2,333
 2,070

 —
 —

 Total
 $
 3,491
 $
 3,779

 Audit Fees (1)(7)

 $
 2,648
 $
 3,863

 Audit-Related Fees (8)

 —
 —

 Total
 $
 3,520
 $
 4,279

 (1)Includes services performed in connection with financing transactions.
 (2)Represents fees for non-statutory audit services and audit services associated with reviewing internal controls for a system implementation in 2022 and attest services related to GHG emissions in 2023 and 2022 and sustainability bond expenditures in 2023.
 (3)Represents registration fees for attendance at Deloitte & Touche LLP-sponsored education seminars and other non-audit advisory services.
 (4)Represents fees for non-statutory audit services and audit services associated with reviewing internal controls for a system implementation in 2022 and attest services related to GHG emissions and sustainability bond expenditures in 2023 and 2022.
 (5)Represents fees for non-statutory audit services and audit services associated with reviewing internal controls for a system implementation in 2022 and attest services related to sustainability bond expenditures in 2022 and GHG emissions in 2023 and 2022.
 (6)Represents fees in connection with audits of Southern Power partnerships, attest services related to GHG emissions in 2023 and 2022, and agreed upon procedures in 2023.
 (7)Includes fees in connection with statutory audits of several Southern Company Gas subsidiaries.
 (8)Represents fees for non-statutory audit services and audit services associated with reviewing internal controls for a system implementation in 2022, attest services related to GHG emissions and sustainability bond expenditures in 2023 and 2022, and audit services associated with a forecast review in 2023.
 The Southern Company Audit Committee (on behalf of Southern Company and its subsidiaries) has a Policy of Engagement of the Independent Auditor for Audit and Non-Audit Services that includes pre-approval requirements for the audit and non-audit services provided by Deloitte & Touche LLP. All of the services provided by Deloitte & Touche LLP in fiscal years 2023 and 2022 and related fees were approved in advance by the Southern Company Audit Committee.
 III-2

 Item 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
 (a)The following documents are filed as a part of this report on Form 10-K:
 (1)Financial Statements and Financial Statement Schedules:
 Management's Reports on Internal Control Over Financial Reporting for Southern Company and Subsidiary Companies, Alabama Power, Georgia Power, Mississippi Power, Southern Power and Subsidiary Companies, and Southern Company Gas and Subsidiary Companies are listed under Item 9A herein.
 Reports of Independent Registered Public Accounting Firm ( Deloitte & Touche LLP, PCAOB ID: 34) on the financial statements and financial statement schedules for Southern Company and Subsidiary Companies, Alabama Power Company, Georgia Power Company, Mississippi Power Company, Southern Power Company and Subsidiary Companies, and Southern Company Gas and Subsidiary Companies are listed under Item 8 herein. Also included in Item 8 herein is the Report of Independent Registered Public Accounting Firm ( BDO USA, P.C.; Houston, Texas; PCAOB ID: 243) on the financial statements of Southern Natural Gas Company, L.L.C., Southern Company Gas' investment which is accounted for by the use of the equity method.
 The financial statements filed as a part of this report for Southern Company and Subsidiary Companies, Alabama Power, Georgia Power, Mississippi Power, Southern Power and Subsidiary Companies, and Southern Company Gas and Subsidiary Companies are listed under Item 8 herein.
 The financial statement schedules (Schedule II, Valuation and Qualifying Accounts and Reserves) for Southern Company and Subsidiary Companies, Alabama Power, Georgia Power, Mississippi Power, Southern Power and Subsidiary Companies, and Southern Company Gas and Subsidiary Companies are included on pages IV-2 and IV-3. Columns in Schedule II may be omitted if the information is not applicable or not required. All other schedules are omitted as not applicable or not required.
 (2)Exhibits:
 Exhibits for the Registrants are listed in the Exhibit Index at page E-1.

 Item 16.FORM 10-K SUMMARY

 None.
 IV-1

 SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
 FOR THE YEARS ENDED DECEMBER 31, 2023, 2022, AND 2021

 Additions

 Description
 Balance at Beginning of Period
 Charged to Income
 Charged to Other Accounts
 Deductions(a)

 Balance at End of Period

 Provision for uncollectible accounts:

 Southern Company(b)

 2023
 $
 $
 $
 $
 $

 2022
 ( 1)

 2021
 ( 23)

 2023
 $
 $
 $
 —
 $
 $

 2022
 —

 2021
 ( 7)
 —

 Georgia Power(b)

 2023
 $
 $
 $
 —
 $
 $

 2022
 —

 2021
 ( 23)

 2023
 $
 $
 $
 —
 $
 $

 2022

 2021
 —

 2023
 $
 $
 —
 $
 —
 $
 —
 $

 2022
 ( 2)
 —

 2021
 —
 —
 —

 2023
 $
 $
 $
 $
 $

 2022
 —

 2021
 —

 (a)Deductions represent write-offs of accounts considered to be uncollectible, less recoveries of amounts previously written off.
 (b)During 2020, Georgia Power recorded $ 23 million of expected bad debt related to the COVID-19 pandemic to a regulatory asset in accordance with orders from the Georgia PSC. During 2021, based on a review of bad debt amounts under a Georgia PSC-approved methodology, Georgia Power reversed substantially all of the amount recorded in 2020.
 IV-2

 SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS (CONTINUED)
 FOR THE YEARS ENDED DECEMBER 31, 2023, 2022, AND 2021

 Additions

 Description
 Balance at Beginning of Period
 Charged to Income
 Charged to Other Accounts
 Deductions
 Balance at End of Period

 Tax valuation allowance (net state):

 Southern Company(a)(b)

 2023
 $
 $
 ( 14)
 $
 ( 25)
 $
 —
 $

 2022
 ( 30)
 —

 2021
 —
 —

 Georgia Power(a)

 2023
 $
 $
 ( 15)
 $
 ( 23)
 $
 —
 $

 2022
 ( 30)
 —

 2021
 —
 —

 Mississippi Power(b)

 2023
 $
 $
 —
 $
 —
 $
 —
 $

 2022
 —
 —
 —

 2021
 —
 —
 —

 Southern Power(b)

 2023
 $
 $
 —
 $
 —
 $
 —
 $

 2022
 —
 —
 —

 2021
 ( 6)
 —
 —

 Southern Company Gas(b)

 2023
 $
 $
 —
 $
 ( 2)
 $
 —
 $

 2022
 —
 —
 —

 2021
 —
 —

 (a)In 2018, Georgia Power established a valuation allowance for certain Georgia state tax credits expected to expire prior to being fully utilized, which has been adjusted in subsequent years as a result of changes in projected state taxable income.
 (b)Associated with a state net operating loss carryforward expected to expire prior to being fully utilized.
 See Note 10 to the financial statements in Item 8 herein for additional information.
 IV-3

 EXHIBIT INDEX
 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 required to be identified as such by Item 15 of Form 10-K.

 (3)
 Articles of Incorporation and By-Laws

 (a)
 —
 Restated Certificate of Incorporation of Southern Company, dated February 12, 2019. (Designated in Form 10-K for the year ended December 31, 2018, File No. 1-3526, as Exhibit 3(a)1.)

 (a)
 —
 Amended and Restated By-laws of Southern Company effective December 12, 2022, and as presently in effect. (Designated in Form 8-K dated December 12, 2022, File No. 1-3526, as Exhibit 3.1.)

 (b)
 —
 Charter of Alabama Power and amendments thereto through September 7, 2017. (Designated in Registration Nos. 2-59634 as Exhibit 2(b), 2-60209 as Exhibit 2(c), 2-60484 as Exhibit 2(b), 2-70838 as Exhibit 4(a)-2, 2-85987 as Exhibit 4(a)-2, 33-25539 as Exhibit 4(a)-2, 33-43917 as Exhibit 4(a)-2, in Form 8-K dated February 5, 1992, File No. 1-3164, as Exhibit 4(b)-3, in Form 8-K dated July 8, 1992, File No. 1-3164, as Exhibit 4(b)-3, in Form 8-K dated October 27, 1993, File No. 1-3164, as Exhibits 4(a) and 4(b), in Form 8-K dated November 16, 1993, File No. 1-3164, as Exhibit 4(a), in Certificate of Notification, File No. 70-8191, as Exhibit A, in Form 10-K for the year ended December 31, 1997, File No. 1-3164, as Exhibit 3(b)2, in Form 8-K dated August 10, 1998, File No. 1-3164, as Exhibit 4.4, in Form 10-K for the year ended December 31, 2000, File No. 1-3164, as Exhibit 3(b)2, in Form 10-K for the year ended December 31, 2001, File No. 1-3164, as Exhibit 3(b)2, in Form 8-K dated February 5, 2003, File No. 1-3164, as Exhibit 4.4, in Form 10-Q for the quarter ended March 31, 2003, File No 1-3164, as Exhibit 3(b)1, in Form 8-K dated February 5, 2004, File No. 1-3164, as Exhibit 4.4, in Form 10-Q for the quarter ended March 31, 2006, File No. 1-3164, as Exhibit 3(b)(1), in Form 8-K dated December 5, 2006, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated September 12, 2007, File No. 1-3164, as Exhibit 4.5, in Form 8-K dated October 17, 2007, File No. 1-3164, as Exhibit 4.5, in Form 10-Q for the quarter ended March 31, 2008, File No. 1-3164, as Exhibit 3(b)1, and in Form 8-K dated September 5, 2017, File No. 1-3164, as Exhibit 4.1.)

 (b)
 —
 Amended and Restated By-laws of Alabama Power effective October 16, 2023, and as presently in effect. ( Designated in Form 10-Q for the quarter ended September 30, 2023, File No 1-3164, as Exhibit 3(b)1.)

 (c)
 —
 Charter of Georgia Power and amendments thereto through October 9, 2007. (Designated in Registration Nos. 2-63392 as Exhibit 2(a)-2, 2-78913 as Exhibits 4(a)-(2) and 4(a)-(3), 2-93039 as Exhibit 4(a)-(2), 2-96810 as Exhibit 4(a)-2, 33-141 as Exhibit 4(a)-(2), 33-1359 as Exhibit 4(a)(2), 33-5405 as Exhibit 4(b)(2), 33-14367 as Exhibits 4(b)-(2) and 4(b)-(3), 33-22504 as Exhibits 4(b)-(2), 4(b)-(3) and 4(b)-(4), in Form 10-K for the year ended December 31, 1991, File No. 1-6468, as Exhibits 4(a)(2) and 4(a)(3), in Registration No. 33-48895 as Exhibits 4(b)-(2) and 4(b)-(3), in Form 8-K dated December 10, 1992, File No. 1-6468 as Exhibit 4(b), in Form 8-K dated June 17, 1993, File No. 1-6468, as Exhibit 4(b), in Form 8-K dated October 20, 1993, File No. 1-6468, as Exhibit 4(b), in Form 10-K for the year ended December 31, 1997, File No. 1-6468, as Exhibit 3(c)2, in Form 10-K for the year ended December 31, 2000, File No. 1-6468, as Exhibit 3(c)2, in Form 8-K dated June 27, 2006, File No. 1-6468, as Exhibit 3.1, and in Form 8-K dated October 3, 2007, File No. 1-6468, as Exhibit 4.5.)

 (c)
 —
 By-laws of Georgia Power as amended effective November 9, 2016, and as presently in effect. (Designated in Form 8-K dated November 9, 2016, File No. 1-6468, as Exhibit 3.1.)

 (d)
 —
 Amended and Restated Articles of Incorporation of Mississippi Power dated July 22, 2020. ( Designated in Form 10-Q for the quarter ended June 30, 2020, File No. 001-11229, as Exhibit 3(d)1.)

 (d)
 —
 By-laws of Mississippi Power as amended effective July 22, 2020, and as presently in effect. ( Designated in Form 10-Q for the quarter ended June 30, 2020, File No. 001-11229, as Exhibit 3(d)2.)

 E-1

 (e)
 —
 Certificate of Incorporation of Southern Power Company dated January 8, 2001. (Designated in Registration No. 333-98553 as Exhibit 3.1.)

 (e)
 —
 By-laws of Southern Power Company effective January 8, 2001. (Designated in Registration No. 333-98553 as Exhibit 3.2.)

 (f)
 —
 Amended and Restated Articles of Incorporation of Southern Company Gas dated July 11, 2016. (Designated in Form 8-K dated July 8, 2016, File No. 1-14174, as Exhibit 3.1.)

 (f)
 —
 Amended and Restated By-laws of Southern Company Gas effective October 23, 2018. (Designated in Form 10-Q for the quarter ended June 30, 2019, File No. 1-14174, as Exhibit 3(e).)

 (4)
 Instruments Describing Rights of Security Holders, Including Indentures

 With respect to each of Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power Company, and Southern Company Gas, such Registrant has excluded certain instruments with respect to long-term debt that does not exceed 10% of the total assets of such Registrant and its subsidiaries. Each such Registrant agrees, upon request of the SEC, to furnish copies of any or all such instruments to the SEC.

 (a)
 —
 Senior Note Indenture dated as of January 1, 2007, between Southern Company and Computershare Trust Company, N.A., as successor Trustee, and certain indentures supplemental thereto through September 8, 2023. (Designated in Form 8-K dated January 11, 2007, File No. 1-3526, as Exhibit 4.1, in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(e), in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(f), in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(g), in Form 8-K dated April 1, 2020, File No. 1-3526, as Exhibit 4.2, in Form 8-K dated February 23, 2021, File No. 1-3526, as Exhibit 4.4(a), in Form 8-K dated February 23, 2021, File No. 1-3526, as Exhibit 4.4(b), in Form 8-K dated October 3, 2022, File No. 1-3526, as Exhibit 4.4(a), in Form 8-K dated October 3, 2022, File No. 1-3526, as Exhibit 4.4(b), in Form 8-K dated February 28, 2023, File No. 1-3526, as Exhibit 4.2, in Form 8-K dated May 15, 2023, File No. 1-3526, as Exhibit 4.4(a), in Form 8-K dated May 15, 2023, File No. 1-3526, as Exhibit 4.4(b), in Form 8-K dated September 5, 2023, File No. 1-3526, as Exhibit 4.4(a), and in Form 8-K dated September 5, 2023, File No. 1-3526, as Exhibit 4.4(b).)

 (a)
 —
 Subordinated Note Indenture dated as of October 1, 2015, between The Southern Company and Computershare Trust Company, N.A., as successor Trustee, and certain indentures supplemental thereto through May 1, 2022. (Designated in Form 8-K dated October 1, 2015, File No. 1-3526, as Exhibit 4.3, in Form 10-Q for the quarter ended June 30, 2017, File No. 1-3526 as Exhibit 4(a)1, in Form 8-K dated November 17, 2017, File No. 1-3526, as Exhibit 4.4, in Form 8-K dated August 13, 2019, File No. 1-3526, as Exhibit 4.4(a), in Form 8-K dated August 13, 2019, File No. 1-3526, as Exhibit 4.4(b), in Form 8-K dated January 6, 2020, File No. 1-3526 as Exhibit 4.4, in Form 8-K dated September 15, 2020, File No. 1-3526, as Exhibit 4.4(a), in Form 8-K dated September 15, 2020, File No. 1-3526, as Exhibit 4.4(b), in Form 8-K dated May 3, 2021, File No. 1-3526, as Exhibit 4.4, in Form 8-K dated September 13, 2021, File No. 1-3526, as Exhibit 4.4, in Form 8-K dated May 9, 2022, File No. 1-3526, as Exhibit 4.4(a), and in Form 8-K dated May 9, 2022, File No. 1-3526, as Exhibit 4.4(b).)

 (a)
 —
 Description of securities registered pursuant to Section 12 of the Securities Exchange Act of 1934, as amended. (Designated in Form 10-K for the year ended December 31, 2022, File No. 1-3526, as Exhibit 4(a)3.)

 E-2

 (b)
 —
 Senior Note Indenture dated as of December 1, 1997, between Alabama Power and Regions Bank, as Successor Trustee, and certain indentures supplemental thereto through November 9, 2023. (Designated in Form 8-K dated December 4, 1997, File No. 1-3164, as Exhibit 4.1, bit 4.2, in Form 8-K dated February 11, 2003, File No. 1-3164, as Exhibit 4.2(a), in Form 8-K dated March 12, 2003, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 8, 2008, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated February 26, 2009, File No. 1-3164 as Exhibit 4.2, in Form 8-K dated March 3, 2011, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 18, 2011, File No. 1-3164, as Exhibit 4.2(b), in Form 8-K dated January 10, 2012, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated November 27, 2012, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated August 20, 2014, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated March 5, 2015, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated April 9, 2015, File No. 1-3164, as Exhibit 4.6(b), in Form 8-K dated January 8, 2016, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated November 2, 2017, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated June 21, 2018, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated September 12, 2019, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated August 24, 2020, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated June 7, 2021, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated November 15, 2021, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated March 2, 2022, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated August 9, 2022, File No. 1-3164, as Exhibit 4.6(a), in Form 8-K dated August 9, 2022, File No. 1-3164, as Exhibit 4.6(b), in Form 8-K dated May 3, 2023, File No. 1-3164, as Exhibit 4.6, and in Form 8-K dated November 6, 2023, File No. 1-3164, as Exhibit 4.6.)

 (c)
 —
 Senior Note Indenture dated as of January 1, 1998, between Georgia Power and Computershare Trust Company, N.A., as Successor Trustee, and certain indentures supplemental thereto through November 8, 2023. (Designated in Form 8-K dated January 21, 1998, File No. 1-6468, as Exhibits 4.1, in Form 8-K dated March 6, 2007, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated February 4, 2009, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated May 24, 2010, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated August 26, 2010, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated February 29, 2012, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated March 12, 2013, File No. 1-6468, as Exhibit 4.2(a), in Form 8-K dated March 2, 2016, File No. 1-6468, as Exhibit 4.2(a), in Form 8-K dated February 28, 2017, File No. 1-6468, as Exhibit 4.2(b), in Form 8-K dated September 4, 2019, File No. 1-6468, as Exhibit 4.2(a), in Form 8-K dated September 4, 2019, File No. 1-6468, as Exhibit 4.2(b), in Form 8-K dated January 8, 2020, File No. 1-6468, as Exhibit 4.2(c), in Form 8-K dated February 22, 2021, File No. 1-6468, as Exhibit 4.2 in Form 8-K dated May 2, 2022, File No. 1-6468, as Exhibit 4.2(a), in Form 8-K dated May 2, 2022, File No. 1-6468, as Exhibit 4.2(b), in Form 8-K dated May 1, 2023, File No. 1-6468, as Exhibit 4.2(a), in Form 8-K dated May 1, 2023, File No. 1-6468, as Exhibit 4.2(b), and in Form 8-K dated November 3, 2023, File No.1-6468, as Exhibit 4.2.)

 (c)
 —
 Subordinated Note Indenture, dated as of September 1, 2017, between Georgia Power and Computershare Trust Company, N.A., as Successor Trustee, and First Supplemental Indenture thereto dated as of September 21, 2017. (Designated in Form 8-K dated September 18, 2017, File No. 1-6468, as Exhibit 4.3, and in Form 8-K dated September 18, 2017, File No. 1-6468, as Exhibit 4.4.)

 (c)
 —
 Amended and Restated Loan Guarantee Agreement, dated as of March 22, 2019, between Georgia Power and the DOE. (Designated in Form 8-K dated March 22, 2019, File No. 1-6468, as Exhibit 4.1.)

 (c)
 —
 Note Purchase Agreement among Georgia Power, the DOE, and the Federal Financing Bank dated as of February 20, 2014. (Designated in Form 8-K dated February 20, 2014, File No. 1-6468, as Exhibit 4.2.)

 (c)
 —
 Future Advance Promissory Note dated February 20, 2014 made by Georgia Power to the FFB. (Designated in Form 8-K dated February 20, 2014, File No. 1-6468, as Exhibit 4.3.)

 (c)
 —
 Amended and Restated Deed to Secure Debt, Security Agreement and Fixture Filing, dated as of March 22, 2019, by Georgia Power to PNC Bank, National Association, doing business as Midland Loan Services Inc., a division of PNC Bank, National Association. (Designated in Form 8-K dated March 22, 2019, File No. 1-6468, as Exhibit 4.4.)

 (c)
 —
 Amended and Restated Owners Consent to Assignment and Direct Agreement and Amendment to Plant Alvin W. Vogtle Additional Units Ownership Participation Agreement, dated as of March 22, 2019, among Georgia Power, the other Vogtle Owners, the DOE, and PNC Bank, National Association, doing business as Midland Loan Services Inc., a division of PNC Bank, National Association. (Designated in Form 8-K dated March 22, 2019, File No. 1-6468, as Exhibit 4.5.)

 E-3

 (c)
 —
 Note Purchase Agreement, dated as of March 22, 2019, between Georgia Power, the DOE, and the FFB. (Designated in Form 8-K dated March 22, 2019, File No. 1-6468, as Exhibit 4.2.)

 (c)
 —
 Promissory Note of Georgia Power, dated as of March 22, 2019. (Designated in Form 8-K dated March 22, 2019, File No. 1-6468, as Exhibit 4.3.)

 (c)
 —
 Description of securities registered pursuant to Section 12 of the Securities Exchange Act of 1934, as amended. (Designated in Form 10-K for the year ended December 31, 2019, File No. 1-6468, as Exhibit 4(c)10.)

 (d)
 —
 Senior Note Indenture dated as of May 1, 1998, between Mississippi Power and Computershare Trust Company, N.A., as Successor Trustee, and certain indentures supplemental thereto through June 29, 2021. (Designated in Form 8-K dated May 14, 1998, File No. 001-11229, as Exhibit 4.1, in Form 8-K dated October 11, 2011, File No. 001-11229, as Exhibit 4.2(b), in Form 8-K dated March 5, 2012, File No. 001-11229, as Exhibit 4.2(b), in Form 8-K dated March 22, 2018, File No. 001-11229, as Exhibit 4.2(b), in Form 8-K dated June 24, 2021, File No. 001-11229, as Exhibit 4.2(a), and in Form 8-K dated June 24, 2021, File No. 001-11229, as Exhibit 4.2(b).)

 (d)

 —
 Senior Note Indenture dated as of June 1, 2023, between Mississippi Power and Regions Bank, as Trustee, and certain indentures supplemental thereto through June 28, 2023. (Designated in Form 10-Q for the quarter ended June 30, 2023, File No. 001-11229, as Exhibit 4(d)1, in Form 10-Q for the quarter ended June 30, 2023, File No. 001-11229, as Exhibit 4(d)2, and in Form 10-Q for the quarter ended June 30, 2023, file No. 001-11229, as Exhibit 4(d)3.)

 (e)
 —
 Senior Note Indenture dated as of June 1, 2002, between Southern Power Company and Computershare Trust Company, N.A., as Successor Trustee, and certain indentures supplemental thereto through January 8, 2021. (Designated in Registration No. 333-98553 as Exhibit 4.1, in Form 8-K dated September 14, 2011, File No. 333-98553, as Exhibit 4.4, in Form 8-K dated July 10, 2013, File No. 333-98553, as Exhibit 4.4, in Form 8-K dated November 12, 2015, File No. 333-98553, as Exhibit 4.4(a), in Form 8-K dated June 13, 2016, File No. 001-37803, as Exhibit 4.4(b), in Form 10-Q for the quarter ended September 30, 2016, File No. 001-37803, as Exhibit 4(f)1, in Form 8-K dated November 10, 2016, File No. 001-37803, as Exhibit 4.4(c), and in Form 8-K dated January 5, 2021, File No. 001-37803, as Exhibit 4.4.)

 (e)
 —
 Description of securities registered pursuant to Section 12 of the Securities Exchange Act of 1934, as amended. ( Designated in Form 10-K for the year ended December 31, 2022, File No. 001-37803, as Exhibit 4(e)2.)

 (f)
 —
 Indenture dated February 20, 2001 between AGL Capital Corporation, AGL Resources Inc., and Computershare Trust Company, N.A., as Successor Trustee and First Supplemental Indenture thereto dated as of September 9, 2021. (Designated in Form S-3, File No. 333-69500, as Exhibit 4.2, and in Form 8-K dated September 7, 2021, File No. 1-14174, as Exhibit 4.2.)

 (f)
 —
 Southern Company Gas Capital Corporation's 6.00% Senior Notes due 2034, 5.875% Senior Notes due 2041, 4.40% Senior Notes due 2043, 3.875% Senior Notes due 2025, 3.250% Senior Notes due 2026, Form of 3.950% Senior Note due October 1, 2046, Form of Series 2017A 4.400% Senior Note due May 30, 2047, Form of 2020A 1.750% Senior Note due January 15, 2031, Form of Series 2021A 3.15% Senior Note due September 30, 2051, Form of Series 2022A 5.15% Senior Note due September 30, 2032, and Form of Series 2023A 5.75% Senior Note due September 15, 2033. (Designated in Form 8-K dated September 22, 2004, File No. 1-14174, as Exhibit 4.1, in Form 8-K dated March 16, 2011, File No. 1-14174, as Exhibit 4.1, in Form 8-K dated May 13, 2013, File No. 1-14174, as Exhibit 4.2, in Form 8-K dated November 13, 2015, File No. 1-14174, as Exhibit 4.2, in Form 8-K dated May 13, 2016, File No. 1-14174, as Exhibit 4.2, in Form 8-K dated September 8, 2016, File No. 1-14174, as Exhibit 4.1(b), in Form 8-K dated May 5, 2017, File No. 1-14174, as Exhibit 4.1, in Form 8-K dated August 17, 2020, File No. 1-14174, as Exhibit 4.1, in Form 8-K dated September 9, 2021, File No. 1-14174, as Exhibit 4.1, in Form 8-K dated September 6, 2022, File No. 1-14174, as Exhibit 4.1, and in Form 8-K dated September 11, 2023, File No. 1-14174, as Exhibit 4.1, respectively.)

 E-4

 (f)
 —
 Southern Company Gas' Guarantee related to the 6.00% Senior Notes due 2034, Guarantee related to the 5.875% Senior Notes due 2041, Guarantee related to the 4.40% Senior Notes due 2043, Guarantee related to the 3.875% Senior Notes due 2025, Guarantee related to the 3.250% Senior Notes due 2026, Form of Guarantee related to the 3.950% Senior Notes due October 1, 2046, Form of Guarantee related to the Series 2017A 4.400% Senior Notes due May 30, 2047, Form of Guarantee related to the Series 2020A 1.750% Senior Notes due January 15, 2031, Form of Guarantee related to the Series 2021A 3.15% Senior Note due September 30, 2051, Form of Guarantee related to the Series 2022A 5.15% Senior Notes due September 30, 2032, and Form of Guarantee related to the Series 2023A 5.75% Senior Notes Due September 15, 2033. (Designated in Form 8-K dated September 22, 2004, File No. 1-14174, as Exhibit 4.3, in Form 8-K dated March 16, 2011, File No. 1-14174, as Exhibit 4.1, in Form 8-K dated May 13, 2013, File No. 1-14174, as Exhibit 4.3, in Form 8-K dated November 13, 2015, File No. 1-14174, as Exhibit 4.3, in Form 8-K dated May 13, 2016, File No. 1-14174, as Exhibit 4.3, in in Form 8-K dated September 8, 2016, File No. 1-14174, as Exhibit 4.3(b), in Form 8-K dated May 5, 2017, File No. 1-14174, as Exhibit 4.3, in Form 8-K dated August 17, 2020, File No. 1-14174, as Exhibit 4.3, in Form 8-K dated September 9, 2021, File No. 1-14174, as Exhibit 4.3, in Form 8-K dated September 6, 2022, File No. 1-14174, as Exhibit 4.3, and in Form 8-K dated September 11, 2023, File No. 1-14174, as Exhibit 4.3, respectively.)

 (f)
 —
 Indenture dated December 1, 1989 of Atlanta Gas Light Company and First Supplemental Indenture thereto dated March 16, 1992. (Designated in Form S-3, File No. 33-32274, as Exhibit 4(a) and in Form S-3, File No. 33-46419, as Exhibit 4(a).)

 (f)
 —
 Indenture of Commonwealth Edison Company to Continental Illinois National Bank and Trust Company of Chicago, Trustee, dated as of January 1, 1954, Indenture of Adoption of Northern Illinois Gas Company to Continental Illinois National Bank and Trust Company of Chicago, Trustee, dated February 9, 1954, and certain indentures supplemental thereto. (Designated in Form 10-K for the year ended December 31, 1995, File No. 1-7296, as Exhibit 4.01, in Form 10-K for the year ended December 31, 1995, File No. 1-7296, as Exhibit 4.02, in Registration No. 2-56578 as Exhibits 2.21 and 2.25, in Form 10-Q for the quarter ended June 30, 1996, File No. 1-7296, as Exhibit 4.01, in Form 10-K for the year ended December 31, 1997, File No. 1-7296, as Exhibit 4.19, in Form 10-K for the year ended December 31, 2003, File No. 1-7296, as Exhibit 4.09, in Form 10-K for the year ended December 31, 2003, File No. 1-7296, as Exhibit 4.10, in Form 10-K for the year ended December 31, 2006, File No. 1-7296, as Exhibit 4.11, in Form 10-Q for the quarter ended September 30, 2008, File No. 1-7296, as Exhibit 4.01, in Form 10-Q for the quarter ended September 30, 2012, File No. 1-7296, as Exhibit 4, in Form 10-K for the year ended December 31, 2016, File No. 1-14174, as Exhibit 4(g)6, in Form 10-K for the year ended December 31, 2017, File No. 1-14174, as Exhibit 4(g)6, in Form 10-Q for the quarter ended September 30, 2018, File No. 1-14174, as Exhibit 4(g)1, in Form 10-K for the year ended December 31, 2019, File No. 1-14174, as Exhibit 4(f)6, in Form 10-K for the year ended December 31, 2020, File No. 1-14174, as Exhibit 4(f)6, in Form 10-Q for the quarter ended September 30, 2021, File No. 1-4174, as Exhibit 4(f)4, and in Form 10-Q for the quarter ended September 30, 2023, File No. 1-4174, as Exhibit 4(f)3.)

 (10)
 Material Contracts

 #
 (a)
 —
 Southern Company 2011 Omnibus Incentive Compensation Plan effective May 25, 2011. (Designated in Form 8-K dated May 25, 2011, File No. 1-3526, as Exhibit 10.1.)

 #
 (a)
 —
 Form of Stock Option Award Agreement for Executive Officers of Southern Company under the Southern Company Omnibus Incentive Compensation Plan. (Designated in Form 10-Q for the quarter ended March 31, 2011, File No. 1-3526, as Exhibit 10(a)3.)

 #
 (a)
 —
 Deferred Compensation Plan for Outside Directors of The Southern Company, Amended and Restated effective June 1, 2021 and First Amendment thereto effective as of June 1, 2021. (Designated in Form 10-Q for the quarter ended June 30, 2021, File No. 1-3526, as Exhibit 10(a)2, and in Form 10-K for the year ended December 31, 2021, File No. 1-3526, as Exhibit 10(a)25.)

 E-5

 #
 (a)
 —
 Southern Company Deferred Compensation Plan, Amended and Restated as of January 1, 2018, First Amendment thereto dated as of December 7, 2018, Second Amendment thereto dated as of January 29, 2019, Third Amendment thereto effective January 1, 2018 and Fourth Amendment thereto dated as of December 1, 2021. (Designated in Form 10-K for the year ended December 31, 2017, File No. 1-3526, as Exhibit 10(a)4, in Form 10-K for the year ended December 31, 2018, File No. 1-3526, as Exhibit 10(a)21, in Form 10-K for the year ended December 31, 2018, File No. 1-3526, as Exhibit 10(a)22, in Form 10-K for the year ended December 31, 2020, File No.1-3526, as Exhibit 10(a)24, and in Form 10-Q for the quarter ended March 31, 2022, File No. 1-3536, as Exhibit 10(a)4.)

 #
 (a)
 —
 The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective June 30, 2016, Amendment No. 1 thereto effective January 1, 2017, Amendment No. 2 thereto effective January 1, 2018, Amendment No. 3 thereto effective April 1, 2018, Amendment No. 4 thereto effective December 4, 2018, Amendment No. 5 thereto effective January 1, 2019 and Amendment No. 6 thereto effective January 1, 2019. (Designated in Form 10-Q for the quarter ended June 30, 2016, File No. 1-3526, as Exhibit 10(a)1, in Form 10-K for the year ended December 31, 2016, File No. 1-3526, as Exhibit 10(a)18, in Form 10-K for the year ended December 31, 2017, File No. 1-3526, as Exhibit 10(a)16, in Form 10-Q for the quarter ended March 31, 2018, File No. 1-3526, as Exhibit 10(a)1, in Form 10-K for the year ended December 31, 2018, File No. 1-3526, as Exhibit 10(a)23, in Form 10-K for the year ended December 31, 2018, File No. 1-3526, as Exhibit 10(a)24, and in Form 10-K for the year ended December 31, 2019, File No. 1-3526, as Exhibit 10(a)24.)

 #
 (a)
 —
 The Southern Company Supplemental Benefit Plan, Amended and Restated effective as of June 30, 2016, Amendment No. 1 thereto effective January 1, 2017, Amendment No. 2 thereto effective January 1, 2018, Amendment No. 3 thereto effective April 1, 2018, Amendment No. 4 thereto dated December 14, 2018, Amendment No. 5 thereto effective January 1, 2019, Amendment No. 6 thereto effective January 1, 2019, Amendment No. 7 thereto effective June 30, 2016, and Amendment No. 8 thereto effective July 1, 2021. (Designated in Form 10-Q for the quarter ended June 30, 2016, File No. 1-3526, as Exhibit 10(a)2, in Form 10-K for the year ended December 31, 2016, File No. 1-3526, as Exhibit 10(a)19, in Form 10-K for the year ended December 31, 2017, File No. 1-3526, as Exhibit 10(a)17, in Form 10-Q for the quarter ended March 31, 2018, File No. 1-3526, as Exhibit 10(a)2, in Form 10-K for the year ended December 31, 2018, File No. 1-3526, as Exhibit 10(a)25, in Form 10-K for the year ended December 31, 2018, File No. 1-3526, as Exhibit 10(a)26 in Form 10-K for the year ended December 31, 2019, File No. 1-3526, as Exhibit 10(a)23, in Form 10-K for the year ended December 31, 2020, File No. 1-3526, as Exhibit 10(a) 25, and in Form 10-Q for the quarter ended March 31, 2022, File No. 1-3526, as Exhibit 10(a)5.)

 #
 (a)
 —
 Amended and Restated Southern Company Change in Control Benefits Protection Plan effective August 15, 2022. ( Designated in Form 8-K dated August 15, 2022, File No. 1-3526, as Exhibit 10.1.)

 #
 (a)
 —
 Deferred Compensation Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective January 1, 2001, between Delaware Charter Guarantee & Trust Company, Southern Company, SCS, Alabama Power, Georgia Power, Mississippi Power, Southern Linc, Southern Company Energy Solutions, LLC, and Southern Nuclear and First Amendment thereto effective January 1, 2009. (Designated in Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)103 and in Form 10-K for the year ended December 31, 2008, File No. 1-3526, as Exhibit 10(a)16.)

 #
 (a)
 —
 Amended and Restated Deferred Stock Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective December 16, 2020, by and between Southern Company and Delaware Charter Guarantee & Trust Company. ( Designated in Form 10-K for the year ended December 31, 2020, File No. 1-3526, as Exhibit 10(a)9.)

 #
 (a)
 —
 Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective December 16, 2020, by and between Southern Company and Delaware Charter Guarantee & Trust Company. ( Designated in Form 10-K for the year ended December 31, 2020, File No. 1-3526, as Exhibit 10(a)10.)

 #
 (a)
 —
 Southern Company Senior Executive Change in Control Severance Plan, Amended and Restated effective August 15, 2022. (Designated in Form 8-K dated August 15, 2022, File No. 1-3526, as Exhibit 10.2.)

 #
 (a)
 —
 Southern Company Executive Change in Control Severance Plan, Amended and Restated effective August 15, 2022. (Designated in Form 10-Q for the quarter ended September 30, 2022, File No. 1-3526, as Exhibit 10(a)3.)

 E-6

 #
 (a)
 —
 Form of Terms for Named Executive Officer Equity Awards Granted under the Southern Company 2021 Equity and Incentive Compensation Plan. (Designated in Form 10-Q for the quarter ended March 31, 2022, File No. 1-3526, as Exhibit 10(a)1).

 #
 (a)
 —
 Deferred Compensation Agreement between Southern Company, SCS, Alabama Power, and Mark A. Crosswhite, effective July 30, 2008. (Designated in Form 10-K for the year ended December 31, 2016, File No. 1-3526, as Exhibit 10(a)17.)

 #
 (a)
 —
 Consulting Agreement between SCS and Mark A. Crosswhite dated December 7, 2022. (Designated in Form 10-K for the year ended December 31, 2022, File No. 1-3526, as Exhibit 10(a)15.)

 (a)
 —
 The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 2018, First Amendment thereto dated December 7, 2018, Second Amendment thereto dated January 29, 2019, Third Amendment thereto dated December 4, 2019, Fourth Amendment thereto dated November 27, 2020, Fifth Amendment thereto effective July 1, 2021, and Sixth Amendment thereto effective July 1, 2021. (Designated in Post-Effective Amendment No. 1 to Form S-8, File No. 333-212783 as Exhibit 4.3, in Form 10-K for the year ended December 31, 2019, File No. 1-3526, as Exhibit 10(a)25, in Form 10-K for the year ended December 31, 2019, File No. 1-3526, as Exhibit 10(a)26, in Form 10-K for the year ended December 31, 2019, File No. 1-3526, as Exhibit 10(a)27, in Form 10-K for the year ended December 31, 2020, File No. 1-3526, as Exhibit 10(a)26, in Form 10-Q for the quarter ended March 31, 2022, File No. 1-3526, as Exhibit 10(a)2, in Form 10-Q for the quarter ended March 31, 2022, File No. 1-3526, as Exhibit 10(a)3, and in Form 10-K for the year ended December 31, 2022, File No. 1-3526, as Exhibit 10(a)17.)

 *
 #
 (a)
 —
 Eighth Amendment to the Southern Company Employee Savings Plan, dated December 13, 2023.

 #
 (a)
 —
 Deferred Compensation Agreement between Southern Company, SCS, Georgia Power, and Christopher C. Womack, effective December 10, 2008. (Designated in Form 10-Q for the quarter ended September 30, 2022, File No. 1-3526, as Exhibit 10(a)4.)

 *
 #
 (a)
 —
 Consulting Agreement between SCS and Thomas A. Fanning dated December 13, 2023.

 #
 (a)
 —
 The Southern Company Equity and Incentive Compensation Plan, effective May 26, 2021. (Designated in Form 8-K dated May 26, 2021, File No. 1-3526, as Exhibit 10.1.)

 (b)
 —
 Intercompany Interchange Contract as revised effective May 1, 2007, among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power Company, and SCS and Appendix A thereto dated as of January 1, 2019. (Designated in Form 10-Q for the quarter ended March 31, 2007, File No. 1-3164, as Exhibit 10(b)5 and in Form 10-K for the year ended December 31, 2018, File No. 1-3164, as Exhibit 10(b)2.)

 (c)
 —
 Intercompany Interchange Contract as revised effective May 1, 2007, among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power Company, and SCS and Appendix A thereto dated as of January 1, 2019. See Exhibit 10(b)1 herein.

 (c)
 —
 Revised and Restated Integrated Transmission System Agreement dated as of November 12, 1990, between Georgia Power and OPC. (Designated in Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(g).)

 (c)
 —
 Revised and Restated Integrated Transmission System Agreement between Georgia Power and Dalton dated as of December 7, 1990. (Designated in Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(gg).)

 (c)
 —
 Revised and Restated Integrated Transmission System Agreement between Georgia Power and MEAG Power dated as of December 7, 1990. (Designated in Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(hh).)

 (c)
 —
 Settlement Agreement dated as of June 9, 2017, by and among Georgia Power, OPC, MEAG Power, Dalton, and Toshiba and Amendment No. 1 thereto dated as of December 8, 2017. (Designated in Form 8-K dated June 16, 2017, File No. 1-6468, as Exhibit 10.1 and in Form 8-K dated December 8, 2017, File No. 1-6468, as Exhibit 10.1.)

 (c)
 —
 Amended and Restated Services Agreement dated as of June 20, 2017, by and among Georgia Power, for itself and as agent for OPC, MEAG Power, MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC, and Dalton, and Westinghouse and WECTEC Global Project Services, Inc. (Pursuant to Item 601(b)(10) of Regulation S-K, certain identified information has been omitted from this exhibit because it is both not material and is the type that Georgia Power treats as private or confidential.) (Designated in Form 8-K dated February 1, 2024, File No. 1-6468, as Exhibit 10.1.)

 E-7

 (c)
 —
 Construction Completion Agreement dated as of October 23, 2017, between Georgia Power, for itself and as agent for OPC, MEAG Power, MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC, and Dalton, and Bechtel, Amendment No. 1 thereto dated as of October 12, 2018, and Amendment No. 2 thereto dated as of November 8, 2019. (Georgia Power has requested confidential treatment for certain portions of these documents pursuant to applications for confidential treatment sent to the SEC. Georgia Power omitted such portions from the filings and filed them separately with the SEC.) (Designated in Form 10-K for the year ended December 31, 2017, File No. 1-6468, as Exhibit 10(c)8 and in Form 10-K for the year ended December 31, 2018, File No. 1-6468, as Exhibit 10(c)10, and in Form 10-K for the year ended December 31, 2019, File No. 1-6468, as Exhibit 10(c)8.)

 (c)
 —
 Plant Alvin W. Vogtle Additional Units Ownership Participation Agreement dated as of April 21, 2006, among Georgia Power, OPC, MEAG Power, and The City of Dalton, Georgia, Amendment 1 thereto dated as of April 8, 2008, Amendment 2 thereto dated as of February 20, 2014, Agreement Regarding Additional Participating Party Rights and Amendment 3 thereto dated as of November 2, 2017, and First Amendment to Agreement Regarding Additional Participating Party Rights and Amendment No. 3 to Plant Alvin W. Vogtle Additional Units Ownership Participation Agreement, dated as of August 31, 2018. (Designated in Form 8-K dated April 21, 2006, File No. 33-7591, as Exhibit 10.4.4, in Form 10-K for the year ended December 31, 2013, File No. 000-53908, as Exhibit 10.3.2(a), in Form 10-K for the year ended December 31, 2013, File No. 000-53908, as Exhibit 10.3.2(b), in Form 10-Q for the quarter ended September 30, 2017, File No. 000-53908, as Exhibit 10.1, and in Form 8-K dated August 31, 2018, File No. 1-6468, as Exhibit 10.1.)

 (c)
 —
 Global Amendments to Vogtle Additional Units Agreements, dated as of February 18, 2019, among Georgia Power, OPC, MEAG Power, MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC, and Dalton. (Designated in Form 10-K for the year ended December 31, 2018, File No. 1-6468, as Exhibit 10(c)12.)

 (d)
 —
 Intercompany Interchange Contract as revised effective May 1, 2007, among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power Company, and SCS and Appendix A thereto dated as of January 1, 2019. See Exhibit 10(b)1 herein.

 (d)
 —
 Transmission Facilities Agreement dated February 25, 1982, Amendment No. 1 dated May 12, 1982 and Amendment No. 2 dated December 6, 1983, between Entergy Corporation (formerly Gulf States) and Mississippi Power. (Designated in Form 10-K for the year ended December 31, 1981, File No. 001-11229, as Exhibit 10(f), in Form 10-K for the year ended December 31, 1982, File No. 001-11229, as Exhibit 10(f)(2), and in Form 10-K for the year ended December 31, 1983, File No. 001-11229, as Exhibit 10(f)(3).)

 (e)
 —
 Intercompany Interchange Contract as revised effective May 1, 2007, among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power Company, and SCS and Appendix A thereto dated as of January 1, 2019. See Exhibit 10(b)1 herein.

 (f)
 —
 Final Allocation Agreement dated January 3, 2008. (Designated in Form 10-K for the year ended December 31, 2007, File No. 1-7296, as Exhibit 10.15.)

 (14)
 Code of Ethics

 (a)
 —
 The Southern Company Code of Ethics. (Designated in Form 10-K for the year ended December 31, 2016, File No. 1-3526, as Exhibit 14(a).)

 (b)
 —

 (c)
 —

 (d)
 —

 (e)
 —

 E-8

 (f)
 —

 (21)
 Subsidiaries of Registrants

 *
 (a)
 —
 Subsidiaries of Registrant.

 (23)
 Consents of Experts and Counsel

 *
 (a)
 —

 *
 (b)
 —

 *
 (c)
 —

 *
 (d)
 —

 *
 (e)
 —

 *
 (f)
 —

 *
 (f)
 —
 Consent of BDO USA, P.C.

 (24)
 Powers of Attorney and Resolutions

 *
 (a)
 —

 *
 (b)
 —

 *
 (c)
 —

 *
 (d)
 —

 *
 (e)
 —

 *
 (f)
 —

 E-9

 (31)
 Section 302 Certifications

 *
 (a)
 —
 Certificate of Southern Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

 *
 (a)
 —
 Certificate of Southern Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

 *
 (b)
 —
 Certificate of Alabama Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 200 2.

 *
 (b)
 —
 Certificate of Alabama Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

 *
 (c)
 —
 Certificate of Georgia Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

 *
 (c)
 —
 Certificate of Georgia Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

 *
 (d)
 —
 Certificate of Mississippi Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

 *
 (d)
 —
 Certificate of Mississippi Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

 *
 (e)
 —
 Certificate of Southern Power Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

 *
 (e)
 —
 Certificate of Southern Power Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

 *
 (f)
 —
 Certificate of Southern Company Gas' Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

 *
 (f)
 —
 Certificate of Southern Company Gas' Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

 (32)
 Section 906 Certifications

 *
 (a)
 —
 Certificate of Southern Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

 *
 (b)
 —
 Certificate of Alabama Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

 *
 (c)
 —
 Certificate of Georgia Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

 *
 (d)
 —
 Certificate of Mississippi Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

 *
 (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.

 *
 (f)
 —
 Certificate of Southern Company Gas' Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

 E-10

 (97)
 Policy Relating to Recovery of Erroneously Awarded Compensation

 *
 (a)
 —
 The Southern Company and Covered Subsidiaries Compensation Recoupment Policy, effective December 1, 2023.

 (c)
 —
 The Southern Company and Covered Subsidiaries Compensation Recoupment Policy, effective December 1, 2023. See Exhibit 97(a) herein.

 (e)
 —
 The Southern Company and Covered Subsidiaries Compensation Recoupment Policy, effective December 1, 2023. See Exhibit 97(a) herein.

 (101)
 Interactive Data Files

 *
 INS
 —

 *
 SCH
 —

 *
 CAL
 —

 *
 DEF
 —

 *
 LAB
 —

 *
 PRE
 —

 (104)
 Cover Page Interactive Data File

 *
 —

 E-11

 THE SOUTHERN COMPANY
 Pursuant to the requirements of Section 13 or 15(d) 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.

 THE SOUTHERN COMPANY

 By:

 Chairman, President, and

 Chief Executive Officer

 By:

 Date:

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

 Chairman, President, and
Chief Executive Officer

 Daniel S. Tucker

 Executive Vice President and Chief Financial Officer

 David P. Poroch

 Comptroller and Chief Accounting Officer

 Janaki Akella
 Henry A. Clark III
 Shantella E. Cooper
 Anthony F. Earley, Jr.
 David J. Grain
 Donald M. James
 John D. Johns

 Dale E. Klein
 David E. Meador
 Ernest J. Moniz
 William G. Smith, Jr.
 Kristine L. Svinicki
 Lizanne Thomas
 E. Jenner Wood III

 By:

 ALABAMA POWER COMPANY
 Pursuant to the requirements of Section 13 or 15(d) 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.

 ALABAMA POWER COMPANY

 By:
 J. Jeffrey Peoples

 By:

 Date:

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

 J. Jeffrey Peoples

 Moses H. Feagin

 Anita Allcorn-Walker

 Senior Vice President and Comptroller

 Angus R. Cooper, III
 O. B. Grayson Hall, Jr.
 Anthony A. Joseph
 Barbara J. Knight
 Catherine J. Randall

 Kevin B. Savoy
 R. Mitchell Shackleford, III
 Charisse D. Stokes
 Phillip M. Webb

 By:

 Supplemental Information to be Furnished with Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act:

 Alabama Power is not required to send an annual report or proxy statement to its sole shareholder and parent company, The Southern Company, and will not prepare such a report after filing this Annual Report on Form 10-K for fiscal year 2023. Accordingly, Alabama Power will not file an annual report with the Securities and Exchange Commission.

 GEORGIA POWER COMPANY
 Pursuant to the requirements of Section 13 or 15(d) 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.

 GEORGIA POWER COMPANY

 By:
 Kimberly S. Greene

 By:

 Date:

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

 Kimberly S. Greene

 Aaron P. Abramovitz

(Principal Financial and Accounting Officer)

 Adam D. Houston

 Vice President and Comptroller

 Mark L. Burns
 Jill Campbell
 Andrew W. Evans
 Steven R. Ewing

 Thomas M. Holder
 Kessel D. Stelling, Jr.
 Charles K. Tarbutton
 Clyde C. Tuggle

 By:

 MISSISSIPPI POWER COMPANY
 Pursuant to the requirements of Section 13 or 15(d) 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.

 MISSISSIPPI POWER COMPANY

 By:
 Anthony L. Wilson

 By:

 Date:

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

 Anthony L. Wilson

 Matthew P. Grice

 Vice President, Treasurer, and
 Chief Financial Officer

 Pascal B. Gill

 Comptroller

 Augustus Leon Collins
 Thomas M. Duff
 Mary S. Graham

 Mark E. Keenum
 Kari R. Wilkinson
 Camille Scales Young

 By:

 Supplemental Information to be Furnished with Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act:

 Mississippi Power is not required to send an annual report or proxy statement to its sole shareholder and parent company, The Southern Company, and will not prepare such a report after filing this Annual Report on Form 10-K for fiscal year 2023. Accordingly, Mississippi Power will not file an annual report with the Securities and Exchange Commission.

 SOUTHERN POWER COMPANY
 Pursuant to the requirements of Section 13 or 15(d) 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.

 SOUTHERN POWER COMPANY

 By:
 Christopher Cummiskey

 Chairman and Chief Executive Officer

 By:

 Date:

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

 Christopher Cummiskey

 Chairman and Chief Executive Officer

 Gary Kerr

 Senior Vice President, Chief Financial Officer, and Treasurer

 Jelena Andrin

 Vice President and Comptroller

 Bryan D. Anderson
 Stan W. Connally
 Martin B. Davis
 Sloane N. Drake

 James Y. Kerr, II
 Sterling A. Spainhour
 Daniel S. Tucker

 By:

 SOUTHERN COMPANY GAS
 Pursuant to the requirements of Section 13 or 15(d) 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.

 SOUTHERN COMPANY GAS

 By:
 James Y. Kerr II

 By:

 Date:

 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

 James Y. Kerr II

 Grace A. Kolvereid

 Sarah P. Adams

 Senior Vice President and Comptroller

 Sandra N. Bane
 Thomas D. Bell, Jr.
 Brenda J. Gaines
 Bradley J. Henderson

 Norman G. Holmes
 J. Bret Lane
 John E. Rau
 Eric S. Smith

 By:

 Supplemental Information to be Furnished with Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act:

 Southern Company Gas is not required to send an annual report or proxy statement to its sole shareholder and parent company, The Southern Company, and will not prepare such a report after filing this Annual Report on Form 10-K for fiscal year 2023. Accordingly, Southern Company Gas will not file an annual report with the Securities and Exchange Commission.