Table of Contents                                Index to Financial Statements

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, 2025

OR

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period from            to

| Commission<br>File Number | Registrant,<br>State of Incorporation,<br>Address and Telephone Number | I.R.S. Employer<br>Identification No. | | --- | --- | --- || 1-3526 | The Southern Company | 58-0690070 | | --- | --- | --- |

(A Delaware Corporation)

30 Ivan Allen Jr. Boulevard, N.W.

Atlanta, Georgia 30308

(404) 506-5000

1-3164	Alabama Power Company	63-0004250

(An Alabama Corporation)

600 North 18th Street

Birmingham, Alabama 35203

(205) 257-1000

1-6468	Georgia Power Company	58-0257110

(A Georgia Corporation)

241 Ralph McGill Boulevard, N.E.

Atlanta, Georgia 30308

(404) 506-6526

001-11229	Mississippi Power Company	64-0205820

(A Mississippi Corporation)

2992 West Beach Boulevard

Gulfport, Mississippi 39501

(228) 864-1211

001-37803	Southern Power Company	58-2598670

(A Delaware Corporation)

30 Ivan Allen Jr. Boulevard, N.W.

Atlanta, Georgia 30308

(404) 506-5000

1-14174	Southern Company Gas	58-2210952

(A Georgia Corporation)

Ten Peachtree Place, N.E.

Atlanta, Georgia 30309

(404) 584-4000

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

Registrant		Title of Each Class	Trading<br>Symbol(s)	Name of Each Exchange<br>on Which Registered
The Southern Company		Common Stock, par value $5 per share	SO	New York Stock Exchange
	(NYSE)
The Southern Company		Series 2017B 5.25% Junior Subordinated Notes due 2077	SOJC	NYSE
The Southern Company		Series 2020A 4.95% Junior Subordinated Notes due 2080	SOJD	NYSE
The Southern Company		Series 2020C 4.20% Junior Subordinated Notes due 2060	SOJE	NYSE
The Southern Company		Series 2021B 1.875% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2081	SO 81	NYSE
The Southern Company		Series 2025A 6.50% Junior Subordinated Notes due 2085	SOJF	NYSE
The Southern Company		2025 Series A Corporate Units	SOMN	NYSE
Georgia Power Company		Series 2017A 5.00% Junior Subordinated Notes due 2077	GPJA	NYSE
Southern Power Company		Series 2016B 1.850% Senior Notes due 2026	SO/26A	NYSE

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.

Registrant	Yes	No
The Southern Company	X
Alabama Power Company	X
Georgia Power Company	X
Mississippi Power Company		X
Southern Power Company	X
Southern Company Gas	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.

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

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

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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.

Registrant	Yes	No
The Southern Company	X
Alabama Power Company		X
Georgia Power Company		X
Mississippi Power Company		X
Southern Power Company		X
Southern Company Gas		X

If 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, 2025: $101.0 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:

Registrant	Description of<br>Common Stock	Shares Outstanding at January 31, 2026
The Southern Company	Par Value $5 Per Share	1,119,391,291
Alabama Power Company	Par Value $40 Per Share	30,537,500
Georgia Power Company	Without Par Value	9,261,500
Mississippi Power Company	Without Par Value	1,121,000
Southern Power Company	Par Value $0.01 Per Share	1,000
Southern Company Gas	Par Value $0.01 Per Share	100

Documents incorporated by reference: specified portions of The Southern Company's Definitive Proxy Statement on Schedule 14A relating to the 2026 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.

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Table of Contents

		Page
	Definitions	ii
	Cautionary Statement Regarding Forward-Looking Information	vi
	PART I
Item 1	Business	I-1
	The Southern Company System	I-1
	Construction Programs	I-4
	Financing Programs	I-5
	Fuel Supply	I-5
	Territoryand CustomersServed by the Southern Company System	I-6
	Competition	I-8
	Seasonality	I-10
	Regulation	I-10
	Rate Matters	I-11
	Human Capital	I-13
Item 1A	Risk Factors	I-15
Item 1B	Unresolved Staff Comments	I-28
Item 1C	Cybersecurity	I-28
Item 2	Properties	I-32
Item 3	Legal Proceedings	I-38
Item 4	Mine Safety Disclosures	I-39
	Information about Our Executive Officers – Southern Company	I-40
	PART II
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-68
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	II-253
Item 9A	Controls and Procedures	II-253
Item 9B	Other Information	II-253
Item 9C	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	II-254
	PART III
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
	PART IV
Item 15	Exhibits and Financial Statement Schedules	IV-1
Item 16	Form 10-K Summary	IV-1
	Signatures

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DEFINITIONS

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

Term	Meaning
2022 ARP	Georgia Power's Alternate Rate Plan approved by the Georgia PSC in 2022 for the years 2023 through 2025
2023 IRP Update	Georgia Power's updated IRP filed in 2023 and approved by the Georgia PSC in April 2024 as modified by a stipulation among Georgia Power, the staff of the Georgia PSC, and certain intervenors
AFUDC	Allowance for funds used during construction
AGL Services Company	AGL Services Company, Inc., the Southern Company Gas system service company and a wholly-owned subsidiary of Southern Company Gas
Alabama Power	Alabama Power Company
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 2019, under which the proceeds of borrowings were 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	Atlanta Gas Light Company, a wholly-owned subsidiary of Southern Company Gas
Bcf	Billion cubic feet
CAMT	Corporate alternative minimum tax
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	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
CODM	Chief operating decision maker
Cooperative Energy	Electric generation and transmission cooperative in Mississippi
CPCN	Certificate of public convenience and necessity
CWIP	Construction work in progress
Dalton	City of Dalton, Georgia, an incorporated municipality in the state of Georgia, acting by and through its Board of Water, Light, and Sinking Fund Commissioners
Dalton Pipeline	A pipeline facility in Georgia in which Southern Company Gas has a 50% undivided ownership interest
DOE	U.S. Department of Energy
ECCR	Georgia Power's Environmental Compliance Cost Recovery tariff
ECO Plan	Mississippi Power's environmental compliance overview plan
ELG	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
FASB	Financial Accounting Standards Board
FCC	Federal Communications Commission
FERC	Federal Energy Regulatory Commission
FFB	Federal Financing Bank
FFB Credit Facilities	Note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities

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DEFINITIONS

(continued)

Term	Meaning
Fitch	Fitch Ratings, Inc.
FP&L	Florida Power and Light Company
GAAP	U.S. generally accepted accounting principles
Georgia Power	Georgia Power Company
GHG	Greenhouse gas
GRAM	Atlanta Gas Light's Georgia Rate Adjustment Mechanism
GW	Gigawatt
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 of 2022
IRP	Integrated resource plan
IRS	Internal Revenue Service
ITC	Investment tax credit
KW	Kilowatt
KWH	Kilowatt-hour
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
Mississippi Power	Mississippi Power Company
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
NDR	Alabama Power's Natural Disaster Reserve
Nicor Gas	Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas
NRC	U.S. Nuclear Regulatory Commission
NYMEX	New York Mercantile Exchange, Inc.
NYSE	New York Stock Exchange
OBBB	One Big Beautiful Bill Act
OCI	Other comprehensive income
OPC	Oglethorpe Power Corporation (an EMC)
OTC	Over-the-counter

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DEFINITIONS

(continued)

Term	Meaning
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
RFP	Request for proposals
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
SNG	Southern Natural Gas Company, L.L.C., a pipeline system in which Southern Company Gas has a 50% ownership interest
SOFR	Secured Overnight Financing Rate
Southern Company	The Southern Company
Southern Company Gas	Southern Company Gas and its subsidiaries
Southern Company Gas Capital	Southern Company Gas Capital Corporation, a wholly-owned subsidiary of Southern Company Gas
Southern Company power pool	The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations
Southern Company system	Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas, SEGCO, Southern Nuclear, SCS, Southern 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	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 and wholly-owned by Southern Power as of December 31, 2025, was previously in a tax equity arrangement where Southern Power was the controlling partner through December 31, 2025

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DEFINITIONS

(continued)

Term	Meaning
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
traditional electric operating companies	Alabama Power, Georgia Power, and Mississippi Power
U.S. Treasury	U.S. Department of the Treasury
VIE	Variable interest entity
Virginia Commission	Virginia State Corporation Commission
Virginia Natural Gas	Virginia Natural Gas, Inc., a wholly-owned subsidiary of Southern Company Gas
Vogtle Owners	Georgia Power, OPC, MEAG Power, and Dalton

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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 interest rates, tariffs, and 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, 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 legal and 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, regulations, and guidance;

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

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

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

•variations in demand for electricity and natural gas, including uncertainties related to projected significant growth in electricity demand driven primarily by data centers and other large load customers, and the related requirement for substantial new generation and transmission investments, creating capital access and revenue recovery risks for the traditional electric operating companies;

•customer affordability matters;

•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 due to 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 and trade policies (including tariffs and other trade measures) of the United States and other countries; 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 future epidemic or 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;

•legal proceedings and regulatory approvals and actions related to past, ongoing, and proposed construction projects, including state PSC or other applicable state regulatory agency approvals and FERC and NRC actions;

•the ability to construct facilities in accordance with the requirements of permits and licenses, 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 and, with respect to retiree benefit plans, changes in actuarial assumptions and differences between the assumptions and actual values, any of the foregoing of which could cause additional funding requirements;

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

(continued)

•advances in technology, including the pace and extent of development of low- to no-carbon energy and battery energy storage technologies and the impact of advancing technology on data center and other large load customer demand;

•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 transmission facilities, extension of retirement dates for fossil fuel plants, and fuel and other cost recovery mechanisms;

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

•the inherent risks involved in operating nuclear generating facilities;

•the inherent risks involved in generation, transmission, and distribution of electricity and transportation and storage of natural gas, including accidents, explosions, fires, mechanical problems, discharges or releases of toxic or hazardous substances or gases, and other environmental risks;

•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, or interests therein, 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, changes in trade policies (including tariffs and other trade measures) of the United States and other countries, interest rate fluctuations, and financial market conditions, and the results of financing efforts;

•prolonged or recurring U.S. federal government shutdowns;

•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, including wildfires, land movement, earthquakes, explosions, floods, high winds, tornadoes, hurricanes and other storms, solar flares, droughts, future epidemic or pandemic health events, wars, political unrest, or other similar occurrences;

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

•impairments of goodwill or long-lived assets;

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

•other factors discussed elsewhere herein and in other reports filed by the Registrants from time to time with the SEC.

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

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PART I

Item 1. 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 vertically integrated utilities providing electric service to retail customers in three Southeastern states in addition to wholesale customers in the Southeast.

•Southern Power Company is 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, operates, and manages power generation assets, including battery energy storage 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, through its subsidiaries, invests in various projects and insures various risk exposures of Southern Company and its subsidiaries. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. 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 the Registrants is included in Note 16 to the financial statements in Item 8 herein.

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 information contained on, or available through, Southern Company's internet website is not, and shall not be deemed to be, incorporated by reference into this report.

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 – "Electric" 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 and Customers 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 schedules, load retention programs, emergency operations, and other matters affecting the reliability of bulk power supply. The

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traditional electric operating companies have joined with other utilities in the Southeast to form the SERC Reliability Corporation (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 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. Following a remand order issued by the U.S. Court of Appeals for the D.C. Circuit related to the FERC's initial approval of SEEM, on March 14, 2025, the FERC issued a further order affirming its initial approval of the SEEM market platform, subject to a later compliance filing. The FERC accepted the required compliance filing on June 26, 2025. New appeals were filed at the U.S. Court of Appeals for the D.C. Circuit while the FERC considered the court's earlier remand. On January 6, 2026, the FERC issued an order accepting a settlement agreement between SEEM members and petitioners in the ongoing appeal proceedings to resolve all pending appeals, subject to a compliance filing to modify the SEEM agreement in accordance with the settlement. The compliance filing was submitted on February 5, 2026. The pending appeals have been withdrawn in accordance with the settlement, which concludes all pending challenges to SEEM's approval. 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 the 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.

The traditional electric operating companies are projecting a significant increase in demand for electricity sales, largely driven by data centers and other large load customers. Serving the projected increased load demand from these new customers while continuing to serve existing customers safely, reliably, and affordably requires investing in generation, transmission, and distribution systems and pricing sales to these new customers such that the related incremental costs are met with adequate incremental revenues from these new customers. Through the 2022 IRP and the 2023 IRP Update, the Georgia PSC has certified resources totaling approximately 13 GWs, approximately nine GWs of which are new generation and battery energy storage facilities that are being, or are expected to be, constructed by Georgia Power. The certified costs of these Georgia Power projects total $19.5 billion, and these projects are projected to be placed in service through 2030. Since 2023, the traditional electric operating companies have contracted with new data centers and other large load customers covering approximately nine GWs of electric load, with each contract individually representing a maximum annual electric load greater than 100 MWs, that have been signed by the parties and/or reviewed by the state regulatory commissions. These new contracts fully ramp up over several years after commencement of service. Some of these contracts are already in effect. Service under the contracts is expected to begin through 2028. The contracts contain various terms and conditions, such as minimum duration, minimum bill provisions, contribution by the customer to local construction costs, termination payment requirements, and financial security, designed to generate adequate incremental revenues associated with incremental costs to serve these customers.

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 nuclear plants, Plants Farley, Hatch, and Vogtle. See "Regulation – Nuclear Regulation" herein for additional information.

Southern Power

Southern Power develops, constructs, acquires, owns, operates, and manages power generation assets, including battery energy storage 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, sales and purchases 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. 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.

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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, 2025, Southern Power's generation fleet, which is owned in part with various partners, totaled 12,648 MWs of nameplate capacity in commercial operation (including 5,268 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 the partnerships. At December 31, 2025, Southern Power had seven 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 – "Electric" in Item 2 herein for additional detail regarding Southern Power's generating facilities and 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's electricity sales from natural gas generating facilities are primarily through long-term, fixed-price capacity PPAs with unaffiliated wholesale purchasers as well as with the traditional electric operating companies and 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 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.

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 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, 2025 was 97% through 2030 and 89% through 2035, with an average remaining contract duration of approximately 12 years. For the year ended December 31, 2025, approximately 63% of contracted MWs were with AAA to A- or equivalent rated counterparties, 31% were with BBB+ to BBB- or equivalent rated counterparties, and 4% were with unrated entities that either have ratemaking authority or have posted collateral to cover potential credit exposure.

Southern Power's future earnings will depend on 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 generating 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

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state ITCs and PTCs under current and future tax legislation and U.S. Treasury guidance; transmission constraints; cost of generation from units within the Southern Company power pool; and operational limitations.

Southern Company Gas

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.

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 Illinois, Georgia, Virginia, and Tennessee.

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. SNG is developing a proposed pipeline project, designed to meet customer demand by increasing SNG's existing pipeline capacity by approximately 1.3 billion cubic feet per day, which the operator of the joint venture anticipates will be completed by 2029. The ultimate outcome of this matter cannot be determined at this time. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Construction Programs" in Item 7 herein for additional information.

Gas marketing services is comprised of SouthStar, which serves approximately 677,000 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.

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 2026, the Southern Company system's construction program is expected to be apportioned approximately as follows:

	Southern Company<br><br>system(a)(b)(c)(d)		Alabama<br><br>Power(c)		Georgia<br><br>Power(d)		Mississippi<br><br>Power(a)
	(in billions)
New generation	$	3.7	$	0.1	$	3.6	$	—
Environmental compliance(e)	0.2		0.1		0.1		—
Generation maintenance	1.4		0.3		1.0		0.1
Transmission	3.2		0.4		2.6		0.2
Distribution	2.0		0.5		1.4		0.1
Nuclear fuel	0.3		0.1		0.2		—
General plant	1.8		0.5		1.2		0.1
	12.6		2.0		10.1		0.4
Southern Power(f)	0.9
Southern Company Gas(g)	2.2
Other subsidiaries	0.2
Total(a)	$	15.9	$	2.0	$	10.1	$	0.4

(a)Totals may not add due to rounding.

(b)Includes the Subsidiary Registrants, as well as other subsidiaries.

(c)Excludes $38 million related to Alabama Power's decision to convert Plant Barry Unit 5 from coal to natural gas. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" in Item 7 herein and Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" in Item 8 herein for additional information.

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(d)Includes expenditures of approximately $3.1 billion for construction projects and related transmission investments approved in conjunction with the 2022 IRP, the 2023 IRP Update, and the 2025 IRP. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" and " – Other Construction" in Item 8 herein for additional information.

(e)Reflects cost estimates for environmental laws and regulations. These estimated expenditures do not include compliance costs associated with the regulation of GHG emissions or costs associated with closure and monitoring of surface impoundments 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.

(f)Includes $40 million and $0.7 billion related to the Millers Branch solar project and wind repowering projects, respectively. 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. See Note 15 to the financial statements under "Southern Power" in Item 8 herein for additional information regarding the Millers Branch solar project and the wind repowering projects.

(g)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. Also includes gas pipeline investment of approximately $0.3 billion. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Construction Programs" in Item 7 herein for information regarding this project.

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 surface impoundments 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 2026 total $653 million for Southern Company, primarily consisting of $256 million for Alabama Power, $360 million for Georgia Power, and $18 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 surface impoundments and landfills for the years 2027 through 2030.

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.

Fuel Supply

Electric

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 OPERATIONS – "Southern Company – Electricity Business – Fuel and Purchased Power Expenses" and MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS 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 2024 and 2025.

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 2026, SCS has contracted for 644 Bcf of natural gas supply under agreements with remaining terms up to nine 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 2026 coal burn requirements. These agreements have terms ranging between one and five 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

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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 or extension of retirement dates of certain fossil fuel plants. 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 Plans" 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 10 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 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

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 have continued to grow; however, this growth has been accompanied by LNG export growth. Forward curves project prices will remain in the mid- to high-$3 per mmBtu range 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 and energy, including 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 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 and Customers 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, 2025, 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.

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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 three rural distributing municipal and cooperative associations. In addition, Alabama Power markets and sells outdoor lighting services and other customer-focused utility services. As of December 31, 2025, Alabama Power's sales contract with AMEA expired, thus eliminating wholesale sales to 11 municipally-owned electric distribution systems previously served indirectly through sales to AMEA.

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, 2025:

	Alabama Power	Georgia Power	Mississippi Power(a)	Total(b)
	(in thousands)
Residential	1,347	2,480	158	3,986
Commercial	209	333	34	576
Industrial	6	11	—	17
Other	1	10	—	10
Total(b)	1,563	2,834	193	4,590

(a)Includes 421 industrial retail customers and 104 other retail customers.

(b)Totals may not add due to rounding.

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, 2025, 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, 2025, PowerSouth owned generating units with more than 2,300 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

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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, 2025, 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, 2025, 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.

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

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, 2025 are as follows:

Utility	State	Number of customers	Approximate miles of pipe
		(in thousands)
Nicor Gas	Illinois	2,294	33.8
Atlanta Gas Light	Georgia	1,733	36.4
Virginia Natural Gas	Virginia	316	5.9
Chattanooga Gas	Tennessee	73	1.8
Total		4,416	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

Electric

The electric utility industry in the United States is continuing to evolve as a result of regulatory, projected demand requirements, 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.

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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.

As of December 31, 2025, 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 2025, Alabama Power purchased approximately 83 million KWHs from such companies. The related costs were immaterial.

As of December 31, 2025, Georgia Power had contracts in effect to purchase alternative energy generation from 40 IPPs within the state of Georgia. During 2025, Georgia Power purchased 8.2 billion KWHs from such companies at a cost of $363 million. Georgia Power also has PPAs for electricity at cogeneration facilities with six industrial customers. Payments are subject to reductions for failure to meet minimum capacity output. During 2025, Georgia Power purchased 533 million KWHs at a cost of $50 million from these facilities.

As of December 31, 2025, 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 2025, Mississippi Power did not make any such purchases.

Natural Gas

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.

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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. 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 and Customers Served by the Southern Company System" and "Rate Matters" herein for additional information.

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 jurisdiction of the FERC under the Federal Power Act. In addition, the traditional electric operating companies and SEGCO are subject to the 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, 2025, 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 15 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 D.C. 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, in December 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 fourth quarter 2026.

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, as they were inoperable by 2009. Georgia Power is currently awaiting the FERC surrender order, which is expected to include dam removal obligations and other post-dam removal activities such as monitoring and riverbank restoration activities.

In September 2024, Georgia Power received a new 40-year FERC license for the Lloyd Shoals project on the Ocmulgee River.

Georgia Power and OPC have a license, expiring on December 31, 2026, for the Rocky Mountain project, a pure pumped storage facility of 903,000 KW installed capacity. In December 2024, OPC, as an agent for co-licensees of the project, filed an

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application with the FERC to relicense the project. 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 2034-2064 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.

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

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.

The NRC licenses for Georgia Power's Plant Hatch Units 1 and 2 expire in 2034 and 2038, respectively. On May 15, 2025, Southern Nuclear submitted a subsequent license renewal application to the NRC seeking to renew both units' operating licenses for an additional 20 years (through 2054 and 2058 for Units 1 and 2, respectively). The NRC's decision on this application is anticipated by the end of the second quarter 2026.

The NRC licenses for Alabama Power's Plant Farley Units 1 and 2 expire in 2037 and 2041, respectively. Southern Nuclear has notified the NRC of its intent to seek to renew the plant's licenses for an additional 20 years (through 2057 and 2061 for Units 1 and 2, respectively). The subsequent license renewal application is projected to be submitted by the second quarter 2027.

The NRC licenses for Georgia Power's Plant Vogtle Units 1, 2, 3, and 4 expire in 2047, 2049, 2062, and 2063, respectively.

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

Electric

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

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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 which are subject to regulation by the FERC. The contracts with these wholesale customers represented 12.9% of Mississippi Power's total operating revenues in 2025.

Natural Gas

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 price levels for natural gas and general economic conditions that may impact customers' ability to pay for natural gas consumed. 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.

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. For 2025, scenarios considered a range of views regarding pressure on CO2 emissions, load growth, supply options, and fuel prices. Views regarding future pressure on CO2 emissions include a fee beginning between $0 and $50 per metric ton rising above inflation over the 30-year planning period. 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.

Alabama Power

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 2025. On August 13, 2025, the Alabama PSC approved a CCN authorizing Alabama Power to complete the acquisition of the Lindsay Hill Generating station. The transaction closed on September 30, 2025. See Note 2 to the financial statements under "Alabama Power – Rate CNP New Plant" in Item 8 herein for additional information.

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Georgia Power

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 serving retail customers. Once certified, the lesser of actual or certified construction costs and purchased power costs is recoverable through rates. Georgia Power may request cost recovery for costs greater than those approved by the Georgia PSC if proven to be prudent and reasonable. 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 April 2024, the Georgia PSC approved Georgia Power's 2023 IRP Update as modified by a stipulation among Georgia Power, the staff of the Georgia PSC, and certain intervenors, which limited recovery of certain costs over the certified amount for Plant Yates Units 8, 9, and 10. On July 15, 2025, the Georgia PSC approved Georgia Power's 2025 IRP, as modified by a stipulation among Georgia Power, the staff of the Georgia PSC, and certain intervenors.

On September 4, 2025, the Georgia PSC approved Georgia Power's request to certify a Georgia Power-owned battery energy storage facility with a capacity of 200 MWs and a projected COD in 2027. On December 19, 2025, the Georgia PSC approved Georgia Power's request, as modified by a stipulation between Georgia Power and the staff of the Georgia PSC, to certify resources totaling 9,885 MWs with projected CODs or delivery commencement dates between 2027 and 2030. As included in the 2022 IRP final order, on February 11, 2026, Georgia Power initiated an RFP for up to 500 MWs of capacity for battery energy storage facilities with projected CODs or delivery commencement dates by 2031.

See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" and " – Rate Plans" in Item 8 herein for additional information.

Mississippi Power

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. In April 2024, Mississippi Power filed its 2024 IRP with the Mississippi PSC. The Mississippi PSC did not note any deficiencies within the prescribed 120-day review period; therefore, the filing was concluded. On January 9, 2025, Mississippi Power notified the Mississippi PSC of its intent to extend the retirement date of Plant Daniel Unit 2 and potentially extend the retirement dates of other fossil steam units beyond their current 2028 retirement dates in order to serve recently signed economic development loads of approximately 600 MWs. Mississippi Power has since acquired FP&L's 50% ownership interest in Plant Daniel Units 1 and 2. In 2026, Mississippi Power is expected to file an update to its 2024 IRP with the Mississippi PSC. Mississippi Power must also file an annual report on energy delivery improvements, the latest of which was filed in November 2025. See Note 2 to the financial statements under "Mississippi Power – Integrated Resource Plans" and " – Plant Daniel" in Item 8 herein for additional information.

Human Capital

Southern Company system management is committed to attracting, developing, and retaining a sustainable workforce and aims to foster a culture of belonging where all employees feel valued. The Southern Company system's values – safety first, intentional inclusion, act with integrity, and superior performance – guide behavior. The Southern Company system had approximately 29,800 employees on its payroll at December 31, 2025 comprised of the following:

	At December 31, 2025(*)
Alabama Power	6,100
Georgia Power	7,700
Mississippi Power	1,100
Southern Power	500
Southern Company Gas	5,000
SCS	4,800
Southern Nuclear	3,700
PowerSecure and other	900
Total Southern Company system	29,800

(*)Numbers are rounded to 100s.

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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 an inclusive and innovative workforce. Southern Company's subsidiaries have policies, programs, and processes to help ensure that all employees are included and fairly treated across all job levels. The Southern Company system encourages different ideas and points of view, and its Code of Ethics affirms its expectation that employees treat each other with fairness, respect, and dignity. The Southern Company Board of Directors and management believe that diverse perspectives and experiences are important to help inform management of risk, business strategy, and innovation. Southern Company management leads the Southern Company system's intentional 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 supports various employee-led groups to provide formal and informal networks of colleagues that can help promote belonging, improve employee retention, and support development.

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 enhance 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 in Item 8 herein for additional information. At December 31, 2025, the average age of the Southern Company system employees was 44 and the average tenure with the Southern Company system was 13 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 6.3%.

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 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. Southern Company's safety metrics include the serious injury rate and the number of fatalities. The serious injury rate represents the number of incidents per 100 employees and is calculated by taking the number of serious injuries multiplied by 200,000 workhours and dividing 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. In 2025, the Southern Company system had a serious injury rate of 0.03 and no fatal 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, 2025, approximately 32% of Southern Company system employees were covered by agreements with unions, with agreements expiring between 2026 and 2030.

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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 legal and regulatory requirements and procurement of necessary approvals, permits, and certificates may result in substantial costs to Southern Company and its subsidiaries. The reduction, elimination, or expiration of government incentives for, or regulations mandating or restricting the use of, renewable energy projects could reduce demand for renewable energy projects and harm the Registrants' businesses.

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 traditional electric operating companies, and the power industry in general, have experienced a period of rising costs and projected capital expenditures, especially with respect to infrastructure investments, which is projected to continue for the foreseeable future. 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 their 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 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 current period of rising costs and increased projected capital expenditures could result in increased resistance to authorizing cost recovery. Furthermore, the outcome of any rate proceeding could be impacted by a variety of factors, including the level of opposition from intervenors, potential impacts to customers, including affordability concerns, and past or future changes in the political, regulatory, economic, or legislative environment. See Note 2 to the financial statements under "Alabama Power" for additional information regarding the Alabama PSC's approval of a plan to keep retail rates stable through 2027, under "Georgia Power – Rate Plans" for additional information regarding the Georgia PSC's approval of a settlement agreement to extend the 2022 ARP through December 31, 2028, with no adjustments to base rates except for storm damage costs incurred through December 31, 2025, and under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects – Nicor Gas" and " – Rate Proceedings – Nicor Gas" in Item 8 herein for additional information regarding certain disallowances at Nicor Gas.

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 are subject to review 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% CAMT on adjusted financial statement income, as defined in the law, and is subject to the issuance of additional guidance by the U.S. Treasury and the IRS. Any rate recovery by the traditional electric operating companies or the natural gas distribution utilities subject to the CAMT 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 will be recoverable through the applicable regulatory process.

The OBBB was signed into law on July 4, 2025. The OBBB, among other things, materially changed the requirements for most of the federal renewable energy incentives. The Registrants are still assessing the impacts of the OBBB on tax incentives for renewable energy projects. Any loss of, reduction in, or impacts on tax incentives, including transferability of tax credits, due to the OBBB could have a material adverse effect on the Registrants. See MANAGEMENT'S DISCUSSION AND ANALYSIS –

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FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Legislation" in Item 7 herein for additional information.

The Registrants are unable to predict changes in laws or regulations, regulatory guidance, legal interpretations, policy positions, and implementation actions that may occur in the future. The impact of any future revision or changes in interpretations or application of existing laws and regulations or the adoption of new laws and regulations applicable to Southern Company or any of its subsidiaries is uncertain. Changes in laws and regulations, the imposition of additional legal or regulatory requirements, changes in application of existing laws and regulations and in enforcement practices of regulators, as well as associated litigation, 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 regulations 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 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 and replacements, 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 and, as a result, demand for energy conservation and sustainable assets could further increase. The public holds diverse and often conflicting views on the use of fossil fuels which may subject the Registrants to adverse publicity in connection with their use or supply of fossil fuels. 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

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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.

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, beginning in 2024, Nicor Gas' regulator, the Illinois Commission, has conducted "future of natural gas" proceedings to explore the recommendations involved with decarbonization of the gas distribution system in Illinois. The Illinois Commission's final report is expected by the end of 2026. 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.

Since 2018, Southern Company system management established GHG emissions reductions goals including an intermediate goal of 50% from 2007 levels by 2030 and a long-term goal of net zero by 2050. Due primarily to the projected electric load growth, current projections indicate it will be extremely challenging to meet the 2030 goal. Achievement of these goals is dependent on various factors, many of which the Southern Company system does not control, including load growth across the Southern Company system's service territory, including projected load growth from large load customers, energy policy and regulations, natural gas prices, customer demand for carbon-free energy, and the development and deployment of low- to no-GHG energy technologies. The strategy to achieve these goals also relies on continuing to economically transition the Southern Company system's generating fleet through a diverse portfolio of resources including low-carbon and carbon-free resources; making the necessary related investments in transmission and distribution systems; continuing to implement effective energy efficiency and demand response programs; implementing initiatives to reduce natural gas distribution emissions; continuing research and development with a focus on technologies that lower GHG emissions; and constructively engaging with policymakers, regulators, investors, customers, and other stakeholders to support outcomes leading to a net zero future. There is 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 or joint venture arrangements, failure of performance by counterparties, 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 add generation, transmission, and related infrastructure to meet projected electric demand growth, 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, including wildfires, land movement, earthquakes, explosions, floods, high winds, tornadoes, hurricanes and other storms, solar flares, droughts, future pandemic health events, wars, political unrest, or other similar occurrences.

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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, six nuclear units. The eight units are operated by Southern Nuclear and represented approximately 22% and 36% of the total KWHs generated by Alabama Power and Georgia Power, respectively, in the year ended December 31, 2025. 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 or license extensions 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 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.

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 and that may present potential exposures in excess of insurance coverage.

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, storage facilities, and other infrastructure are subject to various state and other regulatory requirements. Failure to comply with these requirements could result in substantial monetary penalties, which could exceed the amount of insurance coverage.

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, failure, or unauthorized access due to human error, natural disaster, technological failure, or internal or external physical attack. 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.

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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 failure due to hacking, virus, denial of service, ransomware, act of war or terrorism, or other type of data security breach, the Registrants face a heightened risk of cyberattack. In addition, the increased use of smartphones, tablets, and other wireless devices, as well as remote working arrangements, may also increase the Registrants' data security risks. 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 growing in sophistication, magnitude, and frequency. Use of generative artificial intelligence has also increased the frequency, scale, and sophistication of cyber attacks and increased the capability of less sophisticated actors. As generative artificial intelligence continues to evolve, new technologies and increased computing power could cause these trends to continue or exacerbate. Moreover, 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 the Registrants or their 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, especially 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.

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, as well as other vendors, to disrupt or compromise services and products. Such third-party vendors have been increasingly used as attack vectors in efforts to target critical infrastructure, including that of the Registrants. The Registrants cannot fully assess the security maturity of all third-party vendors and such vendors 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. Any violations of applicable laws and regulations could lead to material losses, both financial and reputational. Insurance may not be adequate to cover any associated losses, and there is no assurance that such losses would be recovered through customer rates. 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

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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 and Southern Company Gas also utilizes its own pipeline network. 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, environmental regulations affecting fuel suppliers, constraints on existing natural gas pipeline capacity or on construction of new natural gas pipelines, or changing economic conditions could limit the ability of the traditional electric operating companies and Southern Power to operate certain facilities, which could impact reliability and 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. The pace of retirement of coal-fired generating facilities can affect the demand for coal. If these facilities are retired in the future, the demand for coal may 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.

The traditional electric operating companies and Southern Power have been increasing their renewable resources and expect to continue to add renewable capacity in the future. The production of energy from wind and solar facilities depends heavily on suitable weather conditions, which are variable. Wind conditions or solar irradiance that are unfavorable or below the Southern Company system's estimates can cause electricity production to be substantially below expectations.

In addition to fuel supply and suitable weather conditions, 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 25% of Southern Power's total revenues for the year ended December 31, 2025. In addition to Mississippi Power's PPA with Georgia Power, the traditional electric operating companies have entered into PPAs with non-affiliated parties for the sale of generating capacity.

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, which may result in impairment charges. 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

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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 energy customers may also result from customers' changing perceptions of the merits of utilizing existing generation technology or tax or other economic incentives. Additionally, state PSCs or legislatures may modify certain aspects of the traditional electric operating companies' businesses 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'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 the Southern Company system's ability to manage and operate its business.

Supply chain disruptions, inflation, elevated interest rates, trade policies (including tariffs and other trade measures), and other economic factors 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 or international conflicts, such as those in Ukraine and the Middle East, and any strained relationships between the United States and other countries related to such conflicts, and the impact of trade policies (including tariffs and other trade measures) of the United States and other countries, 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 and trade policies 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, further impacts of trade policies, or other economic factors may negatively affect operations and the timely recovery of costs.

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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 maintain reliability and 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, generation, and battery energy storage facilities for the traditional electric operating companies, generation and battery energy storage facilities for Southern Power, and capital improvements to natural gas distribution facilities for Southern Company Gas, to, among other things, maintain reliability and meet projected electric demand growth. 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 and is involved in new gas pipeline construction projects. Moreover, the pace and extent of the traditional electric operating companies' planned construction program have increased as a response to projected electric demand growth. The traditional electric operating companies also are in the process of closing surface impoundments 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 maintain reliability and 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 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 and trade policies (including tariffs and other trade measures) of the United States and other countries; 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 future epidemic or 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 project. Further, the traditional electric operating companies are incurring, and may in the future incur, significant engineering, design, and equipment costs in advance of receiving approval of generation, distribution, and transmission projects. If any of these projects are canceled for any reason, including if a traditional electric operating company is not selected through a PSC-approved RFP process or due to failure to receive other necessary regulatory approvals and/or siting or environmental permits, significant cancellation penalties under the equipment purchase orders and construction contracts could occur and such traditional electric operating company may not be able to recover through customer rates all such penalties or registration, prepayment, or other fees incurred in such process. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans – 2025 IRP" and " – Certification Requests" in Item 8 herein for additional information.

In addition, partnership and joint ownership agreements may provide partners or co-owners with certain decision-making authority in connection with projects under construction. 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 Company Gas' current pipeline development project involves a joint owner that controls management of the project, and Southern Power participates in partnership agreements with respect to a majority of its renewable energy projects. 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 Subsidiary 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.

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Even if a construction project (including a joint venture construction project) is completed, the total costs may be higher than estimated or certified or may be deemed imprudent, disallowed, or otherwise not recoverable through regulated rates, if applicable. In addition, construction delays and contractor performance shortfalls can result in the loss of revenues. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Construction Programs" in Item 7 herein for additional information.

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.

Southern Company Gas' significant investment in pipeline development projects involves financial and execution risks.

Southern Company Gas, through SNG, has approved a significant investment in a pipeline development project. The pipeline development project will be constructed and operated by a third party. If the third party fails to perform in a proper manner, the book value of the investment could be impaired and Southern Company Gas could lose part or all of its investment. In addition, Southern Company Gas is required to fulfill capital obligations related to other pipelines in which Southern Company Gas has an ownership interest or, as necessary, guarantee the obligations related thereto, and Southern Company Gas may participate in other pipeline development projects in the future.

With respect to the pipeline development project, Southern Company Gas will rely on its joint venture partner for construction management and will not exercise direct control over the process. The project is dependent on contractors for successful and timely completion. Further, the development of the pipeline project involves numerous regulatory, environmental, construction, safety, political, and legal uncertainties and may require a significant investment. This project may not be completed on schedule, at the budgeted cost, or at all. There may be cost overruns and construction difficulties that cause Southern Company Gas' investment to exceed its initial expectations, which may impact the earnings of the joint venture partnership. Moreover, Southern Company Gas' net income will not materially increase immediately upon the expenditure of funds on this pipeline project. Pipeline construction occurs over an extended period of time, and Southern Company Gas' net income will not be materially impacted unless and until the project is placed in service.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Construction Programs" in Item 7 herein for information regarding this project.

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 have continued to grow; however, this growth has been accompanied by LNG export growth. Forward curves project prices will remain in the mid- to high-$3 per mmBtu range through 2030; however, short-term price volatility is expected and future prices could be materially impacted by various factors, including unexpected geopolitical events, increased demand for natural gas, including to fuel electric generation to serve data centers and other large load customers, and government policies related to natural gas and energy, including 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 under recovered 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

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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 customers.

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 or uncertainty, government shutdowns, trade policies (including tariffs and other trade measures) of the United States and other countries, government fiscal policy, future 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 the 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, elimination of government energy assistance programs, government shutdowns, increases in energy prices, or individual conservation efforts.

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 data centers and electric and natural gas vehicles can create additional demand. Given that these technologies are rapidly evolving, the extent of any additional demand is uncertain. In particular, future incremental electric demand from data centers could be substantial or, on the other hand, future technological advances could offset or eliminate any such demand. Accordingly, future energy demand may vary widely from projections. 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 and/or earnings. 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, wildfires, and extreme temperatures. 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. For example, in September 2024, Hurricane Helene caused significant damage to Georgia Power's transmission and distribution facilities. The incremental restoration costs related to this hurricane totaled approximately $880 million, of which approximately $780 million was deferred in the regulatory asset for storm damage, approximately $75 million was capitalized to property, plant, and equipment, and approximately $25 million was deferred as future billings to open access transmission tariff customers. See Note 2 to the financial statements in Item 8 herein for more information regarding storm damage balances. Additionally, the applicable state PSC or other applicable state regulatory agency may deny or delay recovery of any portion of such costs. Any

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such delay or failure in recovering costs by the Subsidiary Registrants could have a material adverse effect on the Registrants, including lower credit ratings and, thus, higher costs for future debt issuances, as well as limitations on their ability to fund capital expenditures and support economic development opportunities.

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, including through SNG's pipeline development projects. 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 or businesses (or interests therein). Specifically, Southern Power continually seeks opportunities to execute its strategy to create value through various transactions, including acquisitions, dispositions, and sales and purchases 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. Additionally, Southern Company Gas continues to make 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 projected 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 projected 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 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.

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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, business risk, 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 any rating agency downgrades 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 downgrade could require altering the mix of debt financing currently used and could require the issuance of secured indebtedness (which would rank senior to unsecured 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.

The traditional electric operating companies are experiencing projected demand that significantly exceeds recent experience, creating the need for new power generating resources and transmission facilities. The majority of this demand is driven by the power needs and projected power needs of data centers to serve an increasingly digital economy and to support artificial intelligence. Other demands are coming from new industrial facilities with advanced manufacturing processes for products such as electric vehicles and batteries. Extending service to these customers necessitates significant capital expenditures, which in turn requires sufficient access to sources of capital. These additional capital spending needs, the increased concentration of business within a single industry based on emerging technologies, and uncertainties on the actual capacity required to satisfy the projected new demands of these new industries creates risks for the traditional electric operating companies. Ensuring that incremental revenues from these projected new demands cover incremental costs and risks is critical to continuing the traditional electric operating companies' value proposition to customers. In particular, Georgia Power has agreed to file its next base rate case in a manner that will ensure the incremental revenue from large load customers has downward pressure, on a levelized basis, of at least $556 million per year for the years 2029, 2030, and 2031. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans – Certification Requests" in Item 8 herein for additional information. While electric service agreements with new large load customers (including data centers) typically include provisions such as early termination payments, minimum bills, and financial security, these and other contractual provisions may not fully protect the traditional electric operating companies against all risks. Changes in industry practice or advances in the related technologies could reduce the demand for electricity to power data centers or other large load facilities. Additionally, these industries may experience a business downturn, which could cause the loss of current or potential customers or may weaken the financial condition and creditworthiness of existing customers. If anticipated demand growth does not materialize, the traditional electric operating companies could experience unrecovered capital investments made to serve expected load. Conversely, if demand grows more rapidly than projected, the traditional electric operating companies may face challenges in securing adequate generation and transmission capacity and maintaining service reliability.

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 regulated 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 expected.

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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 obligations 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 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 through regulated 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, including capital expenditures to meet projected electric demand growth. Access to capital markets may also be critical to finance unexpected material expenditures such as unusually volatile commodity costs or significant storm restoration activities for severe weather events. 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 and affordability concerns from increased borrowing costs could require the Registrants and Nicor Gas, unilaterally or at the direction of their regulators, to significantly scale back infrastructure investment, which could lead to additional risks related to safety and reliability. 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, 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 fiscal, monetary, trade, or 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, impacts of any future 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 of Plant Vogtle Units 3 and 4. Future debt and credit agreements may contain additional or different covenants, events of default, and mandatory prepayment events. 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 plans, 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

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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.

Activist shareholders could seek to engage in proxy solicitations, advance shareholder proposals, or otherwise attempt to assert influence on Southern Company's board of directors and management. Should such activity arise, it 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. 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 evaluated for impairment annually or on an interim basis if changes in circumstances or the occurrence of events suggest impairment exists. If impairment testing indicates that the carrying amount of reporting units exceeds the respective fair value, an impairment charge would be recognized. If goodwill were to become impaired, the results of operations could be materially and adversely affected. At December 31, 2025, 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. Long-lived assets are assessed for impairment whenever events or changes in circumstances indicate that the asset's carrying amount may not be recoverable. If impairment testing indicates that the carrying amount of the long-lived assets exceeds the respective fair value, an impairment charge would be recognized. See Notes 1 and 15 to the financial statements in Item 8 herein for information regarding certain impairment charges at Southern Company, Alabama Power, 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

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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 includes directors with an understanding of cyber issues, including former federal officials with high levels of security clearances. 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 Technology Officer (CITO). 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 Cybersecurity Organization, 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 CITO 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 25 years of cybersecurity experience and over a decade securing critical infrastructure. 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 Cybersecurity Organization, 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 Cybersecurity Organization 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

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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 Cybersecurity Organization 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 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

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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

Electric

At December 31, 2025, the traditional electric operating companies, Southern Power, and SEGCO owned and/or operated the generating and battery energy storage 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.

Company/Facility Type(a)/Facility Name/<br><br>Ownership Percentage	Location	Nameplate<br>Capacity (KWs)
Alabama Power
Natural Gas
Combined Cycle:
Barry Units 6 through 8	Mobile, AL	1,706,424
Central Alabama Generating Station	Autauga County, AL	885,000
Lindsay Hill Generating Station	Autauga County, AL	879,700
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		5,839,124
Coal
Barry Unit 5	Mobile, AL	700,000
Gaston Unit 5	Wilsonville, AL	880,000
Miller (91.8% of Units 1 and 2 and 100% of Units 3 and 4)	Birmingham, AL	2,532,288
Total Coal		4,112,288
Nuclear
Farley	Dothan, AL	1,720,000
Solar
Anniston Army Depot	Calhoun County, AL	7,380
Fort Rucker	Dale County, AL	10,560
Total Solar		17,940
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

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Company/Facility Type(a)/Facility Name/<br><br>Ownership Percentage	Location	Nameplate<br>Capacity (KWs)
Thurlow	Tallassee, AL	81,000
Weiss	Leesburg, AL	87,750
Yates	Tallassee, AL	47,000
Total Hydro		1,668,079
Cogeneration
Lowndes County	Burkeville, AL	104,800
Theodore	Theodore, AL	236,418
Washington County	Washington County, AL	123,428
Total Cogeneration		464,646
Total Alabama Power Generating Capacity		13,822,077
Georgia Power
Natural Gas
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
Nuclear
Hatch (50.1%)	Baxley, GA	899,612
Vogtle (45.7%)	Augusta, GA	2,167,094
Total Nuclear		3,066,706
Solar
Fort Benning	Columbus, GA	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
McIntosh	Effingham County, GA	10,000
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		368,106

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Company/Facility Type(a)/Facility Name/<br><br>Ownership Percentage	Location	Nameplate<br>Capacity (KWs)
Hydro
Bartletts Ferry	Columbus, GA	173,000
Burton	Clayton, GA	8,100
Flint River	Albany, GA	5,400
Goat Rock	Columbus, GA	40,500
Lloyd Shoals	Jackson, GA	18,000
Morgan Falls	Atlanta, GA	16,800
Nacoochee	Lakemont, GA	4,800
North Highlands	Columbus, GA	29,600
Oliver Dam	Columbus, GA	60,000
Rocky Mountain (25.4%)	Rome, GA	229,362	(b)
Sinclair Dam	Milledgeville, GA	45,000
Tallulah Falls	Clayton, GA	72,000
Terrora	Clayton, GA	20,800
Tugalo	Clayton, GA	59,250
Wallace Dam	Eatonton, GA	321,300
Yonah	Toccoa, GA	22,500
Total Hydro		1,126,412
Battery Energy Storage
Mossy Branch	Talbot County, GA	65,000
Total Georgia Power Generating Capacity		14,789,068
Mississippi Power
Natural Gas
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	Pascagoula, MS	1,000,000
Solar
Walnut Grove	Walnut Grove, MS	1,500
Cogeneration
Chevron Cogenerating Station	Pascagoula, MS	147,292	(c)
Total Mississippi Power Generating Capacity		4,017,874

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Company/Facility Type(a)/Facility Name/<br><br>Ownership Percentage	Location	Nameplate<br>Capacity (KWs)
Southern Power
Natural Gas
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
Solar
Adobe	Kern County, CA	20,000
Apex	North Las Vegas, NV	20,000
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	20,000
Campo Verde	Imperial County, CA	147,420
Cimarron	Colfax County, NM	30,640
Decatur County	Decatur County, GA	20,000
Decatur Parkway	Decatur County, GA	84,000
Desert Stateline	San Bernadino County, CA	299,990
East Pecos	Pecos County, TX	120,000
Garland	Kern County, CA	205,290
Gaskell West I	Kern County, CA	20,000
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	Kern County, CA	32,000
Macho Springs	Luna County, NM	55,000
Morelos del Sol	Kern County, CA	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
South Cheyenne	Laramie County, WY	150,000
Spectrum	Clark County, NV	30,240
Tranquillity	Fresno County, CA	205,300
Total Solar		2,545,460	(d)
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

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Company/Facility Type(a)/Facility Name/<br><br>Ownership Percentage	Location	Nameplate<br>Capacity (KWs)
Grant Plains	Grant County, OK	147,200
Grant	Grant County, OK	151,800
Kay	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	Crosby & Floyd Counties, TX	257,250
Wildhorse	Pushmataha County, OK	100,000
Total Wind		2,534,580	(e)
Battery Energy Storage
Garland	Kern County, CA	88,000	(f)
Tranquillity	Fresno County, CA	72,000	(f)
Total Battery Energy Storage		160,000
Fuel Cell
Red Lion and Brookside	New Castle and Newark, DE	27,500	(g)
Total Southern Power Generating Capacity		12,647,880
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
Natural Gas		23,360,146
Coal		9,023,212
Nuclear		4,786,706
Solar		2,933,006
Hydro		2,794,491
Wind		2,534,580
Cogeneration		611,938
Battery Energy Storage		225,000
Fuel Cell		27,500
Total Southern Company System Generating Capacity		46,296,579

(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 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, Roserock, and South Cheyenne 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 and South Cheyenne. 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. See Note 7 to the financial statements under "Southern Power – Variable Interest Entities – SP Solar" in Item 8 herein for additional information.

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(e)Southern Power is the controlling partner in a non-tax equity partnership for Beech Ridge II and is the controlling partner in tax equity partnerships owning Cactus Flats, Deuel Harvest, Reading, Skookumchuck, and Wildhorse. For Deuel Harvest and Skookumchuck, another partner holds a noncontrolling interest in Southern Power's remaining equity. Southern Power also owns 100% of Glass Sands and 100% of SP Wind (a holding company which owns the remaining eight Southern Power 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. See Note 7 to the financial statements under "Southern Power – Variable Interest Entities – SP Wind" in Item 8 herein for additional information.

(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 Plans" 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, substantially in good operating condition, and suitable for their intended purpose.

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 2027.

On July 30, 2025, Mississippi Power completed its acquisition of FP&L's 50% ownership interest in Plant Daniel Units 1 and 2. See Note 2 to the financial statements under "Mississippi Power – Integrated Resource Plans" and " – Plant Daniel" and Note 15 to the financial statements under "Mississippi Power" in Item 8 herein for additional information on Plant Daniel.

In 2025, the maximum demand on the traditional electric operating companies, Southern Power Company, and SEGCO was 37,006,000 KWs and occurred on January 22, 2025. The all-time maximum demand of 38,194,000 KWs occurred on January 17, 2024. 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 2025 was 20%.

Jointly-Owned Facilities

Alabama Power and Georgia Power at December 31, 2025 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
Facility	Total<br>Capacity	Alabama<br>Power		Power<br>South		Georgia<br>Power		OPC		MEAG<br>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 4	4,742	—		—		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	818	—		—		75.0		—		—		—		25.0
Rocky Mountain	903	—		—		25.4		74.6		—		—		—

Alabama Power and Georgia 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 $34 million at December 31, 2025, 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.

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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 relating to Plant Vogtle Units 3 and 4, which are secured by a first priority lien on (a) Georgia Power's undivided ownership interest in the units and (b) Georgia Power's rights and obligations under the principal contracts relating to the units. 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.

Natural Gas

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, 2025, 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 facilities are used by Southern Company Gas' gas distribution operations segment to supplement natural gas supply during peak usage periods.

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.

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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, 2025.

Christopher C. Womack

Chairman, President, and Chief Executive Officer

Age 67

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 and President of Georgia Power from November 2020 to March 2023.

David P. Poroch

Executive Vice President and Chief Financial Officer

Age 56

First elected in 2025. Executive Vice President and Chief Financial Officer since July 2025. Previously served as Comptroller from March 2023 to July 2025, Senior Vice President and Chief Accounting Officer of SCS from March 2023 to July 2025, and Executive Vice President, Chief Financial Officer, Chief Risk Officer, and Treasurer of Southern Company Gas from January 2021 to February 2023.

Bryan D. Anderson

Executive Vice President

Age 59

First elected in 2020. Executive Vice President and President of External Affairs since January 2021. Executive Vice President of SCS since November 2020.

Pedro P. Cherry

Chairman, President, and Chief Executive Officer of Mississippi Power

Age 54

First elected in 2025. Chairman and Chief Executive Officer of Mississippi Power since August 2025. President of Mississippi Power since March 2025. Previously served as Executive Vice President of Southern Company Gas and President and Chief Executive Officer of Atlanta Gas Light and Chattanooga Gas from August 2020 to March 2025.

Stanley W. Connally, Jr.

Executive Vice President and Chief Operating Officer

Age 56

First elected in 2012. Chief Operating Officer since January 2025. Executive Vice President since April 2021 and Executive Vice President of SCS since January 2025. Previously served as Chairman, President, and Chief Executive Officer of SCS from April 2021 to January 2025 and Executive Vice President for Operations of SCS from June 2018 to April 2021.

Christopher Cummiskey

Executive Vice President

Age 51

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. Chairman, President, and Chief Executive Officer of SCS since January 2025.

Sloane N. Drake

Executive Vice President and Chief Human Resources Officer

Age 49

First elected in 2024. Executive Vice President and Chief Human Resources Officer of Southern Company and SCS since March 2023. Previously served as Senior Vice President of SCS from February 2019 to March 2023 and Senior Vice President of Georgia Power from August 2018 to March 2023.

Kimberly S. Greene

Chairman, President, and Chief Executive Officer of Georgia Power

Age 59

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.

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James Y. Kerr II

Chairman, President, and Chief Executive Officer of Southern Company Gas

Age 61

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.

J. Jeffrey Peoples

Chairman, President, and Chief Executive Officer of Alabama Power

Age 66

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.

Peter P. Sena III

Chairman, President, and Chief Executive Officer of Southern Nuclear

Age 62

First elected in 2024. Chairman and Chief Executive Officer of Southern Nuclear since June 2024. President of Southern Nuclear since March 2023. Previously served as Executive Vice President and Chief Nuclear Officer of Southern Nuclear from July 2019 to March 2023.

Sterling A. Spainhour

Executive Vice President and Chief Legal Officer

Age 57

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, and Senior Vice President and General Counsel – East of SCS from July 2020 to March 2023.

Each officer listed above was initially elected at the time or times stated above by the board of directors of the applicable company and is currently serving until the next annual meeting (or written consent in lieu of the annual meeting) or until his or her successor is elected and qualified.

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PART II

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 United States.

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, 2026: 87,056

Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of common stock were $2.94 in 2025 and $2.86 in 2024. In January 2026, Southern Company declared a quarterly dividend of 74 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	II-3
Results of Operations	II-8
Southern Company	II-8
Alabama Power	II-16
Georgia Power	II-20
Mississippi Power	II-24
Southern Power	II-28
Southern Company Gas	II-30
Future Earnings Potential	II-35
Accounting Policies	II-46
Financial Condition and Liquidity	II-51

This section generally discusses 2025 and 2024 items and year-to-year comparisons between 2025 and 2024. Discussions of 2023 items and year-to-year comparisons between 2024 and 2023 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, 2024, which was filed with the SEC on February 19, 2025. 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.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS

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 distribution 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, operates, and manages power generation assets, including battery energy storage 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 and purchases 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 choice markets – and one non-reportable segment, all other. 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

Alabama Power

Jurisdictional Separation Study Order

On June 5, 2025, the Alabama PSC approved an order authorizing Alabama Power to implement changes related to the Jurisdictional Separation Study (JSS) under Rate RSE, which allocates costs between retail and other electric services. For 2026, a revised JSS allocation factor will account for Alabama Power system capacity previously allocated to wholesale electric services that is being used for retail electric service starting January 1, 2026. In addition, Alabama Power is authorized to establish a regulatory asset to defer certain costs associated with this capacity for 2026, and those costs are estimated to be approximately $100 million. Beginning in 2027, Alabama Power will amortize the regulatory asset on a levelized basis over a period not exceeding 10 years.

Reliability Reserve Accounting Order

In 2025, Alabama Power utilized $30 million of the reliability reserve for reliability-related transmission, distribution, and generation expenses and accrued $83 million to the reliability reserve in accordance with procedures established in the reliability reserve accounting order. In addition, Alabama Power notified the Alabama PSC through its annual RSE filing of its intent to utilize $60 million of its reliability reserve balance in 2026. See Note 2 to the financial statements under "Alabama Power – Reliability Reserve Accounting Order" for additional information.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS

Rate CNP New Plant

On August 13, 2025, the Alabama PSC approved Alabama Power's petition for a CCN authorizing Alabama Power to complete the acquisition of the Lindsay Hill Generating Station (879.7 MWs), which had been approved by the FERC on June 6, 2025. The transaction closed on September 30, 2025. See Notes 2 and 15 to the financial statements under "Alabama Power – Rate CNP New Plant" and "Alabama Power," respectively, for additional information.

Nuclear Production Tax Credits Order

On October 7, 2025, the Alabama PSC issued an order authorizing Alabama Power to establish a regulatory liability for nuclear PTCs received through its nuclear generating facilities pursuant to Internal Revenue Code §45U for tax years 2024 through 2032. The §45U PTCs will be deferred as a regulatory liability until the Alabama PSC provides direction on how to apply them for the benefit of customers. For the 2024 tax year, Alabama Power received $180 million in §45U PTCs on Southern Company's consolidated federal income tax return. The ultimate outcome of this matter cannot be determined at this time.

December 5th Consent Order

On December 5, 2025, the Alabama PSC issued a consent order (December 5th Consent Order) approving a plan to keep retail rates stable through 2027. Alabama Power has agreed to:

•a moratorium on any upward rate adjustments associated with Rate RSE for 2027;

•maintain the current Rate CNP Compliance factors through December 2027;

•delay the effective date of Rate CNP New Plant adjustment to recover costs associated with the Lindsay Hill Generating Station acquisition until January 2028 billings;

•maintain the current Rate CNP PPA factor through March 2028; and

•maintain the current Rate ECR interim factor through December 2027.

To implement the plan, the Alabama PSC authorized Alabama Power to apply any customer refund resulting from Alabama Power's 2025 Rate RSE actual result calculation to the NDR. The Alabama PSC also approved the use of Alabama Power's 2024 nuclear PTCs, when monetized, to offset retail cost of service in 2027. In addition, any future regulatory liabilities associated with monetized nuclear PTCs from 2025, 2026, and 2027 will be used to offset future retail cost of service, including any under recovered balances under Rate CNP and Rate ECR.

Furthermore, the Alabama PSC, as part of its routine oversight of Alabama Power's regulated activities, will monitor factors such as weather, natural disasters, changes in fuel markets, and other significant unforeseen events that may impact this plan. If such events occur, Alabama Power will work with the Alabama PSC to determine a reasonable and responsive course of action under the circumstances.

See Note 2 to the financial statements under "Alabama Power" for additional information.

Rate RSE

On December 1, 2025, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2026. Projected earnings were within the specified range; therefore, retail rates under Rate RSE remain unchanged for 2026.

For the year ended December 31, 2025, Alabama Power's weighted common equity return exceeded 6.15%, resulting in Alabama Power establishing a current regulatory liability of $57 million for Rate RSE refunds, which was subsequently applied to the NDR pursuant to the December 5th Consent Order.

See Note 2 to the financial statements under "Alabama Power – Rate RSE" for additional information.

Georgia Power

2022 ARP

On July 1, 2025, the Georgia PSC approved a settlement agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors to extend the 2022 ARP for an additional three-year term through December 31, 2028 (ARP Extension). Under the ARP Extension, base rates will not be adjusted in 2026, 2027, or 2028 except for reasonable and prudent storm damage costs incurred through December 31, 2025.

In a separate regulatory proceeding, on February 17, 2026, Georgia Power filed a request with the Georgia PSC to recover the reasonable and prudent storm costs incurred through December 31, 2025, which is expected to increase annual recovery by approximately $300 million effective June 1, 2026. The proposed annual recovery included in the filing is expected to fully

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recover the regulatory asset balance related to storm damage at December 31, 2025 over four years, and the remaining balance at December 31, 2028 will be included in the next rate case. Georgia Power expects the Georgia PSC to make a final decision on this matter on May 28, 2026. The ultimate outcome of this matter cannot be determined at this time.

Under the ARP Extension, Georgia Power's retail ROE set point will continue at 10.50% and its equity ratio will continue at 56%. Additionally, the retail ROE range approved by the Georgia PSC in the 2022 ARP, of 9.50% to 11.90%, will continue.

See Note 2 to the financial statements under "Georgia Power – Rate Plans" and " – Storm Damage Recovery" for additional information.

Integrated Resource Plans

2025 IRP

On July 15, 2025, the Georgia PSC approved Georgia Power's 2025 IRP, as modified by a stipulation among Georgia Power, the staff of the Georgia PSC, and certain intervenors. In the 2025 IRP decision, the Georgia PSC approved several requests, including the following:

•Extended operation of Plant Scherer Unit 3 (614 MWs based on 75% ownership) through at least December 31, 2035 and Plant Gaston Units 1 through 4 (500 MWs based on 50% ownership through SEGCO) through December 31, 2034.

•Installation of environmental controls and natural gas co-firing at Plant Bowen Units 1 through 4 (3,160 MWs), Plant Scherer Units 1 and 2 (137 MWs based on 8.4% ownership), and Plant Scherer Unit 3 for compliance with both ELG supplemental rules and GHG rules.

•Upgrades to Plant McIntosh Units 10 and 11 (1,319 MWs) for a projected 194 MWs of incremental capacity by 2028 and Plant McIntosh Units 1 through 8 (640 MWs) for a projected 74 MWs of incremental capacity by 2033.

•Upgrades to Plant Vogtle Units 1 and 2 (1,060 MWs based on 45.7% ownership) for a projected 54 MWs of incremental capacity, some of which could be available as early as 2028.

•Investments related to the continued reliable operations of four hydro facilities, as well as the authority to spend up to $25 million to undertake engineering studies related to two additional hydro facilities.

•RFP for at least 1,100 MWs of utility scale and distributed generation renewable resources.

See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans – 2025 IRP" for additional information.

Certification Requests

On September 4, 2025, the Georgia PSC approved Georgia Power's request to certify a Georgia Power-owned battery energy storage facility with a capacity of 200 MWs and a projected COD in 2027.

On December 19, 2025, the Georgia PSC approved Georgia Power's request, as modified by a stipulation between Georgia Power and the staff of the Georgia PSC (Certification Stipulation), to certify the following resources totaling 9,885 MWs:

•18 resources selected from the RFP pursuant to the 2022 IRP final order, totaling 7,999 MWs (6,804 MWs of Georgia Power projects) with projected CODs or delivery commencement dates between 2028 and 2030.

•Extension of 50 MWs of an existing 750-MW affiliate PPA with Mississippi Power for an additional year through December 31, 2029.

•A 20-year non-affiliate PPA for 930 MWs commencing in 2030 and five 25-year non-affiliate PPAs totaling 646 MWs commencing in 2027.

•Construction of a 260-MW Georgia Power-owned battery energy storage facility with a projected COD in 2027 to be paired with an existing non-affiliate solar PPA.

Pursuant to the Certification Stipulation, Georgia Power has agreed to file its next base rate case in a manner that will ensure the incremental revenue from large load customers has downward pressure, on a levelized basis, of at least $556 million per year for the years 2029, 2030, and 2031.

The approved certification requests in September and December 2025 associated with these Georgia Power-owned projects and related transmission investments total approximately $16.7 billion, excluding AFUDC.

See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans – Certification Requests" and FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" herein for additional information.

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Fuel Cost Recovery

On February 17, 2026, Georgia Power filed a request with the Georgia PSC to decrease fuel rates by 12.6% effective June 1, 2026, which is expected to reduce annual billings by approximately $388 million. Georgia Power expects the Georgia PSC to make a final decision on this matter on May 28, 2026. The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" for additional information.

Mississippi Power

On April 3, 2025, the FERC approved a settlement agreement filed by Mississippi Power and Cooperative Energy in December 2024, as part of the MRA tariff.

On June 17, 2025, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2025, resulting in an annual increase in revenues of approximately 4.0%, or $41 million. In accordance with the PEP rate schedule, an increase of 2.0% of total retail revenues, or approximately $22 million, became effective with the first billing cycle of April 2025, and the remaining approximately $19 million became effective with the first billing cycle of July 2025. Also in the PEP filing, the Mississippi PSC approved Mississippi Power's use of a portion of its retail reliability reserve balance during 2025. As a result, Mississippi Power utilized the retail reliability reserve in the amount of $10.9 million during 2025 for reliability-related generation, transmission, and distribution expenses.

On June 19, 2025, the Florida PSC issued a final order approving the transfer of FP&L's 50% ownership interest in Plant Daniel Units 1 and 2 to Mississippi Power. On July 30, 2025, Mississippi Power completed the acquisition of FP&L's 50% interest in Plant Daniel Units 1 and 2 and, as part of the acquisition, received approximately $36 million from FP&L, which was recorded as a regulatory liability and is being amortized to offset incremental costs as authorized by the Mississippi PSC.

On November 17, 2025, Mississippi Power submitted its annual preliminary retail PEP filing for 2026 to the Mississippi PSC, which requested a 1.8%, or $20 million, annual increase in revenues. In accordance with the PEP rate schedule, the rate increase became effective with the first billing cycle of January 2026, subject to refund. The Mississippi PSC is expected to render a final decision in the second quarter 2026. The ultimate outcome of this matter cannot be determined at this time.

On February 13, 2026, Mississippi Power submitted its annual ECO Plan filing to the Mississippi PSC, which requested a $2 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.

Southern Power

During 2025, Southern Power continued construction of the 200-MW first phase, the 180-MW second phase, and the 132-MW third phase of the Millers Branch solar facility. In addition, Southern Power continued the development project to repower 200 MWs of the 299-MW Kay wind facility and began development projects to repower the full capacity of the 147-MW Grant Plains, the 152-MW Grant, the 257-MW Wake, and the 276-MW Bethel wind facilities. The output of the development projects is contracted under new and amended PPAs, with commercial operations projected to occur between the third quarter 2026 and the third quarter 2027. The ultimate outcome of these matters cannot be determined at this time. Subsequent to December 31, 2025, Southern Power completed construction of the 200-MW first phase of the Millers Branch solar facility. See Note 15 to the financial statements under "Southern Power" for additional information.

On December 31, 2025, Southern Power purchased 100% of the noncontrolling Class A membership interests in the SP Wind tax equity partnership for approximately $282 million. See Note 7 to the financial statements under "Southern Power – Variable Interest Entities – SP Wind" for additional information.

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, 2025 was 97% through 2030 and 89% through 2035, with an average remaining contract duration of approximately 12 years.

Southern Company Gas

Nicor Gas

In connection with Nicor Gas' 2023 general base rate case proceeding, the Illinois Commission disallowed $127 million of capital investments that have been completed or were planned to be completed through December 31, 2024. This amount is comprised of $31 million for capital investments placed in service in 2022 and 2023 under a nine-year regulatory infrastructure program

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(Investing in Illinois) and $96 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. The disallowances are reflected on the statements of income in estimated loss on regulatory disallowance. In January 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 2023 base rate case decision. In February 2024, Nicor Gas filed a notice of appeal with the Illinois Appellate Court related to the Illinois Commission's rate case ruling. On December 1, 2025, the Illinois Appellate Court upheld the Illinois Commission's decision regarding certain capital investment disallowances in Nicor Gas' 2023 general base rate case proceeding. On December 22, 2025, Nicor Gas filed a petition for rehearing with the Illinois Appellate Court specifically addressing $43 million of the base rate case disallowances.

Any further cost disallowances by the Illinois Commission in the 2020 through 2023 annual review proceedings of the Investing in Illinois program could be material to the financial statements of Southern Company Gas. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects – Nicor Gas" for additional information.

On November 19, 2025, the Illinois Commission approved a $168 million annual base rate increase for Nicor Gas, which became effective December 2, 2025. The base rate increase was based on an ROE of 9.60% and an equity ratio of 50.00%.

Additionally, the Illinois Commission excluded $120 million of capital investments included in the base rate case filing that have been incurred or are expected to be incurred through December 31, 2026. Nicor Gas analyzed the Illinois Commission's order and recorded a pre-tax charge to income in the fourth quarter 2025 of $63 million ($47 million after tax) associated with excluded capital investments that have been incurred. The disallowances are reflected on the statements of income in estimated loss on regulatory disallowance.

On January 6, 2026, 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 19, 2025 base rate case decision. On January 14, 2026, Nicor Gas filed a petition for review with the Illinois Appellate Court related to the Illinois Commission's rate case ruling. It remains Nicor Gas' position that it has met its evidentiary burden to demonstrate that the amount and the timing of such capital investments are prudent and reasonable and that such capital investments should be included in base rates.

On January 9, 2026, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $221 million increase in annual base rate revenues. The requested increase is based on a projected test year for the 12-month period ending December 31, 2027, an ROE of 10.35%, and an equity ratio of 54.6%. The Illinois Commission is expected to rule on the requested increase within the 11-month statutory time limit, after which rate adjustments will be effective. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings – Nicor Gas" for additional information.

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

Virginia Natural Gas

On December 17, 2025, the Virginia Commission approved a stipulation related to Virginia Natural Gas' August 2024 general base rate case filing. The approved stipulation provides for a $40 million increase in annual base rate revenues, including the recovery of investments under the SAVE program, an ROE of 9.85%, and an equity ratio of 49.35%. Interim rates became effective January 1, 2025, subject to refund, based on Virginia Natural Gas' original requested increase of approximately $63 million. Refunds to customers related to the difference between the approved rates implemented December 31, 2025 and the interim rates will be administered during the first quarter 2026.

Key Performance Indicators

In striving to achieve attractive risk-adjusted returns while providing cost-effective energy to approximately 9.0 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

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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 customer count and volumes of natural gas sold. See RESULTS OF OPERATIONS – "Southern Company Gas" herein 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.

RESULTS OF OPERATIONS

Southern Company

Consolidated net income attributable to Southern Company was $4.3 billion in 2025, a decrease of $60 million, or 1.4%, from 2024. The decrease was primarily due to increases in depreciation and amortization, other operations and maintenance expenses, and interest expense, largely offset by increases in retail electric revenues associated with rates and pricing and sales growth, other revenues, natural gas revenues associated with base rate increases, and allowance for equity funds used during construction.

Basic EPS was $3.94 in 2025 and $4.02 in 2024. Diluted EPS, which factors in additional shares primarily related to stock-based compensation, was $3.92 in 2025 and $3.99 in 2024. EPS for 2025 and 2024 was negatively impacted by $0.03 and $0.01 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 $2.94 in 2025 and $2.86 in 2024. In January 2026, Southern Company declared a quarterly dividend of 74 cents per share. For 2025, the dividend payout ratio was 75% compared to 71% for 2024.

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.

	2025		2024
	(in millions)
Electricity business	$	4,707	$	4,473
Gas business	732		740
Other business activities	(1,098)		(812)
Net Income	$	4,341	$	4,401

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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:

	2025		Increase<br><br>(Decrease)<br><br>from 2024
	(in millions)
Retail electric revenues	$	19,331	$	1,541
Wholesale electric revenues	2,941		510
Other electric revenues	953		57
Other revenues	552		66
Total electric operating revenues	23,777		2,174
Fuel	4,897		801
Purchased power	980		97
Cost of other sales	274		37
Other operations and maintenance	5,454		364
Depreciation and amortization	4,725		691
Taxes other than income taxes	1,263		(25)
Total electric operating expenses	17,593		1,965
Operating income	6,184		209
Allowance for equity funds used during construction	318		109
Interest expense, net of amounts capitalized	1,445		73
Other income (expense), net	519		(4)
Income taxes	1,039		36
Net income	4,537		205
Net loss attributable to noncontrolling interests	(170)		(29)
Net Income Attributable to Southern Company	$	4,707	$	234

Retail Electric Revenues

Retail electric revenues increased $1.5 billion, or 8.7%, in 2025 as compared to 2024. Details of the changes in retail electric revenues were as follows:

	2025 vs. 2024
	(in millions)		(% change)
Estimated change in retail electric revenues resulting from —
Rates and pricing	$	885	5.0	%
Sales growth	216		1.2
Weather	(45)		(0.2)
Fuel and other cost recovery	485		2.7
Total change in retail electric revenues	$	1,541	8.7	%

Changes in rates and pricing resulted in an increase in retail electric revenues in 2025 as compared to 2024 primarily due to increases at Georgia Power related to base tariff increases and increased ECCR tariff revenues in accordance with the 2022 ARP and the inclusion of Plant Vogtle Unit 4 in retail rates net of elimination of the NCCR tariff, as well as an increase in Rate RSE at Alabama Power. See Note 2 to the financial statements under "Alabama Power" and "Georgia Power" for additional information.

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Changes in sales resulted in an increase in retail electric revenues in 2025 as compared to 2024. Changes in retail electric revenues are influenced heavily by the change in the volume of energy sold from year to year, which generally results from changes in electricity usage by customers, weather, and the number of customers. Total retail KWH sales for 2025 and the percent changes from 2024 were as follows:

	2025
	Total<br>KWHs	Total KWH<br><br>Percent Change		Weather-Adjusted<br><br>Percent Change(*)
	(in billions)
Residential	49.8	1.1	%	0.8	%
Commercial	51.4	2.5		2.8
Industrial	49.6	1.4		1.4
Other	0.5	(2.0)		(2.0)
Total retail energy sales	151.3	1.6	%	1.7	%

(*)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 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.

Weather-adjusted retail energy sales increased by 2.5 billion KWHs in 2025 as compared to 2024. Weather-adjusted residential KWH sales increased 0.8% primarily due to customer growth. Weather-adjusted commercial KWH sales increased 2.8% primarily due to additional sales from new and existing data centers at Georgia Power. Industrial KWH sales increased 1.4% primarily due to increases in the electronics and primary metals sectors, partially offset by decreases in the pipeline and textiles sectors.

Changes in fuel and other cost recovery revenues resulted in an increase in retail electric revenues in 2025 as compared to 2024 primarily due to higher recoverable fuel costs, as discussed further under "Fuel and Purchased Power Expenses" herein. 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 for additional information.

Wholesale Electric Revenues

Wholesale electric revenues increased $510 million, or 21.0%, in 2025 as compared to 2024. Details of wholesale electric revenues were as follows:

	2025		Increase<br><br>(Decrease)<br><br>from 2024
	(in millions)
Capacity and other	$	657	$	5
Energy	2,284		505
Total	$	2,941	$	510

The change in wholesale electric revenues was largely driven by increases in energy revenues of $326 million at the traditional electric operating companies and $179 million at Southern Power. The increase in energy revenues was due to a $420 million increase related to the average cost per KWH sold primarily resulting from higher fuel and purchased power prices, as well as an $85 million increase related to the volume of KWHs sold resulting from higher demand. Wholesale energy sales totaled 52.5 billion KWHs in 2025, a 4.7% increase as compared to 2024.

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

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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 and 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 $57 million, or 6.4%, in 2025 as compared to 2024. The increase was primarily due to increases of $27 million in revenues from renewable energy programs at Georgia Power primarily associated with solar application fees, $24 million in regulated outdoor lighting sales at Georgia Power, $17 million in realized gains associated with price stability products for retail customers on variable demand-driven pricing tariffs at Georgia Power, $10 million in customer fees at Georgia Power, and $7 million related to undistributed customer bill credits at Alabama Power, partially offset by decreases of $19 million in pole attachment revenues at Alabama Power and Georgia Power and $16 million associated with transmission revenues at Southern Power.

Other Revenues

Other revenues increased $66 million, or 13.6%, in 2025 as compared to 2024. The increase was primarily due to increases of $80 million in unregulated sales primarily associated with power delivery construction and maintenance, renewables, and resiliency projects at Georgia Power, partially offset by decreases of $10 million in unregulated sales associated with energy conservation projects at Georgia Power and $8 million in unregulated sales of products and services at Alabama Power.

Fuel and Purchased Power Expenses

In 2025, total fuel and purchased power expenses were $5.9 billion, an increase of $898 million, or 18.0%, as compared to 2024. The increase was primarily the result of a $592 million net increase related to the average cost of fuel and purchased power and a $251 million increase related to the volume of KWHs generated and purchased. Also contributing to the increase was $55 million related to credits recorded at Georgia Power in 2024 resulting from litigation related to nuclear fuel disposal costs. See Note 3 to the financial statements under "Nuclear Fuel Disposal Costs" for additional information.

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.

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

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

	2025	2024
Total generation (in billions of KWHs)(a)	191	188
Total purchased power (in billions of KWHs)	21	18
Sources of generation (percent) —
Gas	51	52
Coal	20	18
Nuclear(a)	19	20
Wind, Solar, and Other	8	8
Hydro	2	2
Cost of fuel, generated (in cents per net KWH) —
Gas	3.37	2.62
Nuclear(a)(b)	0.83	0.86
Coal	3.75	3.94
Average cost of fuel, generated (in cents per net KWH)(a)(b)	2.89	2.50
Average cost of purchased power (in cents per net KWH)(c)	5.01	5.14

(a)Excludes KWHs generated from test period energy at Plant Vogtle Unit 4 prior to being placed in service in April 2024. The related fuel costs were charged to CWIP in accordance with FERC guidance.

(b)Excludes $55 million of credits recorded to nuclear fuel expense in 2024 resulting from litigation related to nuclear fuel disposal costs. See Note 3 to the financial statements under "Nuclear Fuel Disposal Costs" for additional information.

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

Cost of Other Sales

Cost of other sales increased $37 million, or 15.6%, in 2025 as compared to 2024. The increase was primarily due to an increase in expenses associated with unregulated power delivery construction and maintenance contracts at Georgia Power.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $364 million, or 7.2%, in 2025 as compared to 2024. The increase was primarily due to a $132 million increase in generation expenses primarily due to non-outage maintenance expenses largely resulting from Plant Vogtle Unit 4 being placed in service in April 2024 at Georgia Power, as well as planned outages at Alabama Power and Mississippi Power, a $114 million gain in 2024 from the sale of integrated transmission system assets at Georgia Power, and increases of $65 million associated with reliability reserve accruals and reliability-related expenses at Alabama Power, $62 million associated with NDR accruals at Alabama Power, $60 million in certain employee compensation and benefit expenses, $57 million in certain technology infrastructure and application production costs, and $28 million related to injuries and damages primarily at Georgia Power, partially offset by a decrease of $98 million in transmission and distribution costs primarily associated with line maintenance and billings adjustments with integrated transmission system owners at Georgia Power, an increase of $39 million in credits to income related to the estimated probable loss on Plant Vogtle Units 3 and 4 at Georgia Power, and a $36 million impairment loss in 2024 associated with Alabama Power discontinuing the development of a multi-use commercial facility. See Note 1 to the financial statements under "Impairment of Long-Lived Assets" and Note 2 to the financial statements under "Alabama Power – Reliability Reserve Accounting Order" and – "Rate NDR" and "Georgia Power – Transmission Asset Sales" and " – Nuclear Construction" for additional information.

Depreciation and Amortization

Depreciation and amortization increased $691 million, or 17.1%, in 2025 as compared to 2024. The increase was primarily due to increases of $298 million in accelerated depreciation at Southern Power related to wind repowering projects, $226 million associated with additional plant in service, and $123 million in amortization of regulatory assets related to CCR AROs at Georgia Power as approved in the 2025 compliance filing under the terms of the 2022 ARP. See FUTURE EARNINGS POTENTIAL – "Construction Programs" herein and Notes 2 and 15 to the financial statements under "Georgia Power" and "Southern Power – Wind Repowering Projects," respectively, for additional information.

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Taxes Other Than Income Taxes

Taxes other than income taxes decreased $25 million, or 1.9%, in 2025 as compared to 2024. The decrease was primarily due to decreases of $78 million in property taxes primarily resulting from the actualization of prior-year tax assessments at Georgia Power, partially offset by increases of $21 million in municipal franchise fees resulting from higher retail revenues at Georgia Power, $18 million in utility license taxes at Alabama Power resulting from an increase in the tax base, and $9 million in payroll taxes.

Allowance for Equity Funds Used During Construction

Allowance for equity funds used during construction increased $109 million, or 52.2%, in 2025 as compared to 2024. The increase was primarily associated with increases in capital expenditures subject to AFUDC at Georgia Power and Alabama Power, partially offset by the impact of Plant Vogtle Unit 4 being placed in service in April 2024 at Georgia Power. See Notes 1 and 2 to the financial statements under "Allowance for Funds Used During Construction and Interest Capitalized" and "Georgia Power," respectively, for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $73 million, or 5.3%, in 2025 as compared to 2024. The increase primarily reflects approximately $95 million related to higher average outstanding borrowings and a decrease of $12 million in net deferred financing costs related to Plant Vogtle Unit 3 at Georgia Power, partially offset by an increase of $41 million in capitalized interest and AFUDC debt associated with increased capital expenditures. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and – "Financing Activities" herein, Note 1 to the financial statements under "Allowance for Funds Used During Construction and Interest Capitalized," and Note 8 to the financial statements for additional information.

Other Income (Expense), Net

Other income (expense), net decreased $4 million, or 0.8%, in 2025 as compared to 2024 primarily due to a $40 million increase in charitable donations at the traditional electric operating companies, primarily at Georgia Power, largely offset by increases of $13 million in interest income, $13 million in customer charges related to contributions in aid of construction at the traditional electric operating companies, and $10 million related to the receipt of liquidated damages at Alabama Power associated with the termination of two solar projects.

Income Taxes

Income taxes increased $36 million, or 3.6%, in 2025 as compared to 2024. The increase was primarily due to higher pre-tax earnings and a $29 million increase in charges to a valuation allowance on certain state tax credit carryforwards at Georgia Power, partially offset by increases of $28 million in the flowback of certain excess deferred income taxes at the traditional electric operating companies and $21 million in the generation of advanced nuclear PTCs at Georgia Power. See Note 10 to the financial statements for additional information.

Net Loss Attributable to Noncontrolling Interests

Substantially all noncontrolling interests relate to renewable projects at Southern Power. Net loss attributable to noncontrolling interests increased $29 million, or 20.6%, in 2025 as compared to 2024. The increased loss was primarily due to $20 million in higher HLBV loss allocations to Southern Power's tax equity partners and $11 million in lower income allocations to Southern Power's equity 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.

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A condensed statement of income for the gas business follows:

	2025		Increase<br><br>(Decrease)<br><br>from 2024
	(in millions)
Natural gas revenues	$	5,044	$	588
Cost of natural gas	1,599		403
Other operations and maintenance	1,360		125
Depreciation and amortization	708		58
Taxes other than income taxes	272		24
Total operating expenses	3,939		610
Operating income	1,105		(22)
Earnings from equity method investments	127		(19)
Interest expense, net of amounts capitalized	377		36
Other income (expense), net	59		(7)
Income taxes	182		(76)
Net income	$	732	$	(8)

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. During the Heating Season, more customers are connected to Southern Company Gas' distribution systems and natural gas usage is higher in periods of colder weather. As a result, operating results can vary significantly from quarter to quarter. For 2025, the percentage of operating revenues and net income generated during the Heating Season was 66% and 82%, respectively. For 2024, the percentage of operating revenues and net income generated during the Heating Season was 62% and 80%, respectively.

Natural Gas Revenues

Natural gas revenues in 2025 were $5.0 billion, reflecting a $588 million, or 13.2%, increase compared to 2024. Details of natural gas revenues were as follows:

	2025 vs. 2024
	(in millions)		(% change)
Estimated change in natural gas revenues resulting from –
Rate changes	$	146	3.3	%
Gas costs and other cost recovery	372		8.3
Gas marketing services	61		1.4
Other	9		0.2
Total change in natural gas revenues	$	588	13.2	%

Changes in rates resulted in an increase in revenues in 2025 as compared to 2024 primarily due to base rate increases at Atlanta Gas Light and Virginia Natural Gas. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" for additional information.

Revenues associated with gas costs and other cost recovery increased in 2025 primarily due to higher cost of natural gas driven by higher natural gas prices and gas volumes, as well as increases in other expenses passed through to customers. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. See "Cost of Natural Gas" and "Other Operations and Maintenance Expenses" herein for additional information.

Revenues from gas marketing services increased in 2025 primarily due to higher commodity prices.

Southern Company Gas has various regulatory mechanisms, such as weather and revenue normalization and straight-fixed-variable rate design, which limits positive or negative impacts to income from 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

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impacts in the event of warmer-than-normal weather in Illinois and Georgia for gas marketing services. Therefore, weather typically does not have a significant net income impact.

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 81.7% of the total cost of natural gas for 2025.

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, an increase of $403 million, or 33.7%, in 2025 as compared to 2024, which reflects higher gas cost recovery in 2025 as a result of a 51.0% increase in natural gas prices as compared to 2024.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $125 million, or 10.1%, in 2025 as compared to 2024. The increase was primarily due to $63 million in charges related to the disallowance of certain capital investments at Nicor Gas, as well as increases of $38 million in employee compensation and benefit expenses, $23 million in expenses passed through to customers at the natural gas distribution utilities, and $17 million in bad debt expense, partially offset by a decrease of $26 million related to certain deferred expenses. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings – Nicor Gas" for additional information.

Depreciation and Amortization

Depreciation and amortization increased $58 million, or 8.9%, in 2025 as compared to 2024. The increase was primarily due to additional plant in service related to continued 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 increased $24 million, or 9.7%, in 2025 as compared to 2024. The increase was primarily due to an increase in revenue taxes as a result of higher natural gas revenues at Nicor Gas. Revenue taxes imposed on Nicor Gas are recoverable from its customers.

Earnings from Equity Method Investments

Earnings from equity method investments decreased $19 million, or 13.0%, in 2025 as compared to 2024. The decrease was primarily due to legal settlements, increased spending on system integrity initiatives, and lower rates, all at SNG. See Note 7 to the financial statements under "Southern Company Gas" for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $36 million, or 10.6%, in 2025 as compared to 2024. The increase was primarily associated with 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

Income taxes decreased $76 million, or 29.5%, in 2025 as compared to 2024. The decrease was primarily due to lower pre-tax earnings, including the impact of the regulatory disallowance at Nicor Gas, an increase of $36 million in the flowback of excess federal and state deferred income taxes, and a decrease of $8 million related to uncertain state tax positions in 2024. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings – Nicor 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, through its subsidiaries, invests in various projects and insures various risk exposures of Southern Company and its subsidiaries; and Southern Linc, which provides digital

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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.

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

	2025		Increase<br><br>(Decrease)<br><br>from 2024
	(in millions)
Operating revenues	$	732	$	67
Cost of other sales	408		(3)
Other operations and maintenance	254		41
Depreciation and amortization	69		(2)
Taxes other than income taxes	4		—
Total operating expenses	735		36
Operating income (loss)	(3)		31
Earnings (loss) from equity method investments	(21)		(5)
Interest expense	1,417		387
Other income (expense), net	(50)		(26)
Income taxes (benefit)	(393)		(101)
Net loss	$	(1,098)	$	(286)

Operating Revenues

Operating revenues for these other business activities increased $67 million, or 10.1%, in 2025 as compared to 2024 primarily due to an increase in revenues at PowerSecure largely related to a higher volume of distributed infrastructure projects.

Other Operations and Maintenance

Other operations and maintenance expenses for these other business activities increased $41 million, or 19.2%, in 2025 as compared to 2024 primarily due to an increase of $43 million in expenses at PowerSecure primarily related to a higher volume of distributed infrastructure projects, partially offset by a decrease of $16 million in expenses at the parent company primarily related to lower director compensation expenses.

Interest Expense

Interest expense for these other business activities, which primarily results from parent company financing activities, increased $387 million, or 37.6%, in 2025 as compared to 2024 primarily due to increases of $252 million associated with the extinguishment of debt at the parent company, $117 million related to higher average outstanding borrowings, and $29 million related to higher interest rates. See Note 8 to the financial statements for additional information.

Other Income (Expense), Net

Other income (expense), net for these other business activities decreased $26 million, or 108.3%, in 2025 as compared to 2024 primarily due to an increase in charitable donations at the parent company.

Income Taxes (Benefit)

The income tax benefit for these other business activities increased $101 million, or 34.6%, in 2025 as compared to 2024 primarily due to higher pre-tax losses at the parent company.

Alabama Power

Alabama Power's net income was $1.5 billion in 2025, representing a $113 million, or 8.1%, increase from 2024. The increase was primarily due to higher retail electric revenues resulting from changes in rates and pricing, partially offset by increases in other operations and maintenance expenses and depreciation and amortization.

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A condensed income statement for Alabama Power follows:

	2025		Increase<br><br>(Decrease)<br><br>from 2024
	(in millions)
Retail revenues	$	7,136	$	497
Wholesale revenues, non-affiliates	449		112
Wholesale revenues, affiliates	188		49
Other revenues	462		23
Total operating revenues	8,235		681
Fuel	1,524		166
Purchased power	508		134
Other operations and maintenance	2,026		131
Depreciation and amortization	1,510		51
Taxes other than income taxes	498		27
Total operating expenses	6,066		509
Operating income	2,169		172
Allowance for equity funds used during construction	69		12
Interest expense, net of amounts capitalized	465		17
Other income (expense), net	168		11
Income taxes	425		65
Net income	$	1,516	$	113

Retail Revenues

Retail revenues increased $497 million, or 7.5%, in 2025 as compared to 2024. Details of the changes in retail revenues were as follows:

	2025 vs. 2024
	(in millions)		(% change)
Estimated change in retail revenues resulting from —
Rates and pricing	$	300	4.5	%
Sales growth	13		0.2
Weather	(3)		—
Fuel and other cost recovery	187		2.8
Total change in retail revenues	$	497	7.5	%

Changes in rates and pricing resulted in an increase in revenues primarily due to an increase in Rate RSE. See Note 2 to the financial statements under "Alabama Power – Rate RSE" for additional information.

Changes in sales resulted in an increase in retail revenues in 2025 as compared to 2024. Changes in retail revenues are influenced heavily by the change in the volume of energy sold from year to year, which generally results from changes in electricity usage by

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customers, weather, and the number of customers. Total retail KWH sales for 2025 and the percent change from 2024 were as follows:

	2025
	Total<br>KWHs	Total KWH<br><br>Percent Change		Weather-Adjusted<br><br>Percent Change(*)
	(in billions)
Residential	18.2	0.7	%	0.5	%
Commercial	13.2	(0.5)		0.2
Industrial	20.7	1.1		1.1
Other	0.1	(7.1)		(7.1)
Total retail sales	52.2	0.5	%	0.7	%

(*)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.

Weather-adjusted retail energy sales increased by 0.3 billion KWHs in 2025 as compared to 2024. Weather-adjusted residential and commercial KWH sales increased 0.5% and 0.2%, respectively, primarily due to customer growth. Industrial KWH sales increased 1.1% primarily due to increases in the primary metals sector.

Changes in fuel and other cost recovery revenues resulted in an increase in retail revenues in 2025 as compared to 2024 primarily due to higher recoverable fuel costs, as discussed further under "Fuel and Purchased Power Expenses" herein. 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

Wholesale revenues from sales to non-affiliates increased $112 million, or 33.2%, in 2025 as compared to 2024. Details of wholesale revenues from sales to non-affiliated utilities were as follows:

	2025		Increase<br><br>(Decrease)<br><br>from 2024
	(in millions)
Capacity and other	$	134	$	27
Energy	315		85
Total non-affiliated	$	449	$	112

The increase in wholesale revenues from sales to non-affiliates was due to increases of $45 million related to the volume of KWH sales associated with higher demand, $40 million related to the average cost per KWH sold due to higher Southern Company system fuel and purchased power prices, and $27 million related to non-fuel revenues from wholesale capacity contracts. Wholesale energy sales to non-affiliates totaled 7.6 billion KWHs in 2025, an 18.4% increase as compared to 2024.

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 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 made at market-based rates that generally provide a margin above Alabama Power's variable cost to produce the energy.

Wholesale revenues from sales to affiliates increased $49 million, or 35.3%, in 2025 as compared to 2024. The increase was primarily due to an increase of $48 million related to the average price of energy due to an increase in natural gas prices. Wholesale energy sales to affiliates totaled 5.7 billion KWHs in 2025, a 0.4% increase as compared to 2024.

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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.

Other Revenues

In 2025, other operating revenues increased $23 million, or 5.2%, as compared to 2024 primarily due to an $11 million increase in open access transmission tariff sales, a $10 million increase in regulated energy services revenues, $7 million related to undistributed customer bill credits associated with nuclear fuel disposal costs litigation, which was offset by an additional NDR accrual within other operations and maintenance expenses, and a $4 million increase in cogeneration revenues primarily related to higher fuel prices. These increases were partially offset by a $10 million decrease in pole attachment revenues and an $8 million decrease in sales of unregulated products and services. See Note 3 to the financial statements under "Nuclear Fuel Disposal Costs" for additional information.

Fuel and Purchased Power Expenses

Fuel and purchased power expenses were $2.0 billion in 2025, an increase of $300 million, or 17.3%, as compared to 2024. The increase was primarily due to a $159 million increase related to the volume of KWHs generated and purchased and a $141 million increase related to the average cost of fuel and purchased power.

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

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, Alabama Power purchases a portion of its electricity needs from the wholesale market. 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. 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.

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

	2025	2024
Total generation (in billions of KWHs)	59.4	60.0
Total purchased power (in billions of KWHs)	9.2	6.9
Sources of generation (percent) —
Coal	36	34
Gas	36	35
Nuclear	22	25
Hydro	6	6
Cost of fuel, generated (in cents per net KWH) —
Coal	3.29	3.19
Gas	3.20	2.73
Nuclear	0.73	0.72
Average cost of fuel, generated (in cents per net KWH)	2.66	2.36
Average cost of purchased power (in cents per net KWH)(*)	5.92	5.72

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

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $131 million, or 6.9%, in 2025 as compared to 2024. The increase was primarily due to increases of $65 million associated with reliability reserve accruals and reliability-related expenses, $62 million associated with NDR accruals, $27 million in certain employee compensation and benefit expenses, and $21 million in generation expenses primarily associated with planned outages, partially offset by a $36 million impairment loss in 2024 associated with

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Alabama Power discontinuing the development of a multi-use commercial facility. See Note 1 to the financial statements under "Impairment of Long-Lived Assets" and Note 2 to the financial statements under "Alabama Power – Reliability Reserve Accounting Order" and – "Rate NDR" for additional information.

Depreciation and Amortization

Depreciation and amortization increased $51 million, or 3.5%, in 2025 as compared to 2024 primarily due to additional plant in service related to transmission and distribution facilities.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $27 million, or 5.7%, in 2025 as compared to 2024 primarily due to an increase in utility license taxes resulting from an increase in the tax base.

Allowance for Equity Funds Used During Construction

Allowance for equity funds used during construction increased $12 million, or 21.1%, in 2025 as compared to 2024 primarily due to an increase in capital expenditures subject to AFUDC. See Note 1 to the financial statements under "Allowance for Funds Used During Construction and Interest Capitalized" for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $17 million, or 3.8%, in 2025 as compared to 2024. The increase was primarily associated with higher average outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" and – "Sources of Capital" herein and Note 8 to the financial statements for additional information.

Other Income (Expense), Net

Other income (expense), net increased $11 million, or 7.0%, in 2025 as compared to 2024 primarily due to the receipt of liquidated damages associated with the termination of two solar projects.

Income Taxes

Income taxes increased $65 million in 2025 as compared to 2024 primarily due to higher pre-tax earnings and a decrease of $39 million in the flowback of certain excess deferred income taxes. 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

Georgia Power's net income was $2.9 billion in 2025, representing a $308 million, or 12.1%, increase from 2024. The increase was primarily due to higher retail revenues associated with rates and pricing and sales growth, as well as an increase in other revenues, partially offset by increases in depreciation and amortization and other operations and maintenance expenses.

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A condensed income statement for Georgia Power follows:

	2025		Increase<br><br>(Decrease)<br><br>from 2024
	(in millions)
Retail revenues	$	11,110	$	923
Wholesale revenues	525		260
Other revenues	996		117
Total operating revenues	12,631		1,300
Fuel	2,040		382
Purchased power	1,517		157
Other operations and maintenance	2,585		234
Depreciation and amortization	2,074		300
Taxes other than income taxes	576		(71)
Total operating expenses	8,792		1,002
Operating income	3,839		298
Allowance for equity funds used during construction	248		96
Interest expense, net of amounts capitalized	793		68
Other income (expense), net	159		(19)
Income taxes (benefit)	602		(1)
Net income	$	2,851	$	308

Retail Revenues

Retail revenues increased $923 million, or 9.1%, in 2025 as compared to 2024. Details of the changes in retail revenues were as follows:

	2025 vs. 2024
	(in millions)		(% change)
Estimated change in retail revenues resulting from —
Rates and pricing	$	539	5.3	%
Sales growth	192		1.9
Weather	(40)		(0.4)
Fuel cost recovery	232		2.3
Total change in retail revenues	$	923	9.1	%

Changes in rates and pricing resulted in an increase in revenues primarily due to base tariff increases and increased ECCR tariff revenues in accordance with the 2022 ARP, the inclusion of Plant Vogtle Unit 4 in retail rates net of elimination of the NCCR tariff, and higher contributions from commercial and industrial customers with variable demand-driven pricing. See Note 2 to the financial statements under "Georgia Power" for additional information.

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Changes in sales resulted in an increase in retail revenues in 2025 as compared to 2024. Changes in retail revenues are influenced heavily by the change in the volume of energy sold from year to year, which generally results from changes in electricity usage by customers, weather, and the number of customers. Total retail KWH sales for 2025 and the percent change from 2024 were as follows:

	2025
	Total<br>KWHs	Total KWH<br><br>Percent Change		Weather-Adjusted<br><br>Percent Change(*)
	(in billions)
Residential	29.5	1.2	%	1.0	%
Commercial	35.4	3.9		4.1
Industrial	24.0	1.7		2.1
Other	0.4	(0.2)		(0.2)
Total retail sales	89.3	2.4	%	2.5	%

(*)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.

Weather-adjusted retail energy sales increased by 2.1 billion KWHs in 2025 as compared to 2024. Weather-adjusted residential sales increased 1.0% primarily due to customer growth. Weather-adjusted commercial KWH sales increased 4.1% primarily due to additional sales from new and existing data centers. Weather-adjusted industrial KWH sales increased 2.1% primarily due to an increase in the electronics and transportation sectors, partially offset by decreases in the textiles and pipeline sectors.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Changes in retail fuel cost recovery revenues resulted in an increase in retail revenues in 2025 as compared to 2024 primarily due to higher recoverable fuel costs, as discussed further under "Fuel and Purchased Power Expenses" herein. 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.

Wholesale Revenues

Wholesale revenues from power sales increased $260 million, or 98.1%, in 2025 as compared to 2024. Details of wholesale revenues were as follows:

	2025		Increase<br><br>(Decrease)<br><br>from 2024
	(in millions)
Capacity and other	$	148	$	21
Energy	377		239
Total	$	525	$	260

The increase in wholesale revenues from power sales was due to a $239 million increase in energy revenues due to increases of $195 million in fuel-related revenues, of which $118 million related to the volume of KWH sales associated with higher demand and $77 million related to the average cost per KWH sold due to higher Southern Company system fuel and purchased power prices, and $44 million in non-fuel-related energy revenues from wholesale contracts, as well as a $21 million increase in capacity revenues from new and existing power sales agreements. Wholesale energy sales from power sales totaled 9.5 billion KWHs in 2025, a 106.4% increase as compared to 2024.

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.

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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.

Other Revenues

In 2025, other operating revenues increased $117 million, or 13.3%, as compared to 2024 primarily due to increases of $80 million in unregulated sales primarily associated with power delivery construction and maintenance, renewables, and resiliency projects, $27 million in revenues from renewable energy programs primarily associated with solar application fees, $22 million in outdoor lighting sales, $17 million in realized gains associated with price stability products for retail customers on variable demand-driven pricing tariffs, and $10 million in customer fees, partially offset by decreases of $15 million in open access transmission tariff sales, $10 million in unregulated sales associated with energy conservation projects, $9 million in regulated sales associated with power delivery construction and maintenance projects, and $8 million in pole attachment revenues.

Fuel and Purchased Power Expenses

Fuel and purchased power expenses were $3.6 billion in 2025, an increase of $539 million, or 17.9%, as compared to 2024. The increase was due to a $288 million increase related to the volume of KWHs generated and purchased, an increase of $196 million related to the average cost of fuel and purchased power, and an increase of $55 million related to credits recorded in 2024 resulting from litigation related to nuclear fuel disposal costs. See Note 3 to the financial statements under "Nuclear Fuel Disposal Costs" for additional information.

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.

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. 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. 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, all as approved by the FERC.

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

	2025	2024
Total generation (in billions of KWHs)(a)	66.3	64.7
Total purchased power (in billions of KWHs)	35.9	30.8
Sources of generation (percent) —
Gas	40	44
Nuclear(a)	36	34
Coal	21	19
Hydro and other	3	3
Cost of fuel, generated (in cents per net KWH) —
Gas	3.53	2.88
Nuclear(a)(b)	0.89	0.96
Coal	4.31	4.94
Average cost of fuel, generated (in cents per net KWH)(a)(b)	2.72	2.61
Average cost of purchased power (in cents per net KWH)(c)	5.01	4.65

(a)Excludes KWHs generated from test period energy at Plant Vogtle Unit 4 prior to being placed in service in April 2024. The related fuel costs were charged to CWIP in accordance with FERC guidance.

(b)Excludes $55 million of credits recorded to nuclear fuel expense in 2024 resulting from litigation related to nuclear fuel disposal costs. See Note 3 to the financial statements under "Nuclear Fuel Disposal Costs" for additional information.

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

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Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $234 million, or 10.0%, in 2025 as compared to 2024. The increase was primarily due to a $114 million gain from the sale of integrated transmission system assets in 2024 and increases of $75 million in generation expenses primarily due to non-outage maintenance expenses largely resulting from Plant Vogtle Unit 4 being placed in service in April 2024, $42 million in certain technology infrastructure and application production costs, $38 million in expenses associated with unregulated power delivery construction and maintenance, energy conservation, and renewables projects, $33 million in certain employee compensation and benefit expenses, and $24 million related to injuries and damages, partially offset by a decrease of $80 million in transmission and distribution costs primarily associated with line maintenance and billings adjustments with integrated transmission system owners and an increase of $39 million in credits to income related to the estimated probable loss on Plant Vogtle Units 3 and 4. See Note 2 to the financial statements under "Georgia Power – Transmission Asset Sales" and " – Nuclear Construction" for additional information.

Depreciation and Amortization

Depreciation and amortization increased $300 million, or 16.9%, in 2025 as compared to 2024 primarily due to increases of $156 million associated with additional plant in service and $123 million in amortization of regulatory assets related to CCR AROs as approved in the 2025 compliance filing under the terms of the 2022 ARP. See Note 2 to the financial statements under "Georgia Power – Rate Plans" for additional information.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $71 million, or 11.0%, in 2025 as compared to 2024 primarily due to a decrease of $98 million in property taxes primarily resulting from the actualization of prior-year tax assessments, partially offset by an increase of $21 million in municipal franchise fees resulting from higher retail revenues.

Allowance for Equity Funds Used During Construction

Allowance for equity funds used during construction increased $96 million, or 63.2%, in 2025 as compared to 2024 primarily due to an increase in capital expenditures subject to AFUDC, partially offset by the impact of Plant Vogtle Unit 4 being placed in service in April 2024. See Notes 1 and 2 to the financial statements under "Allowance for Funds Used During Construction and Interest Capitalized" and "Georgia Power," respectively, for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $68 million, or 9.4%, in 2025 as compared to 2024. The increase was primarily associated with an increase of approximately $71 million related to higher average outstanding borrowings and a decrease of $12 million in net deferred financing costs related to Plant Vogtle Unit 3, partially offset by an increase of $22 million in AFUDC debt related to increased capital expenditures. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and – "Financing Activities" herein, Note 1 to the financial statements under "Allowance for Funds Used During Construction and Interest Capitalized," and Note 8 to the financial statements for additional information.

Other Income (Expense), Net

Other income (expense), net decreased $19 million, or 10.7%, in 2025 as compared to 2024 primarily due to a $45 million increase in charitable donations, partially offset by a $15 million increase in customer charges related to contributions in aid of construction.

Income Taxes

Income taxes decreased $1 million, or 0.2%, in 2025 as compared to 2024 primarily due to increases of $77 million in the flowback of excess state deferred income taxes and $21 million in the generation of advanced nuclear PTCs, largely offset by higher pre-tax earnings and a $29 million increase in charges to a valuation allowance on certain state tax credit carryforwards. See Note 10 to the financial statements for additional information.

Mississippi Power

Mississippi Power's net income was $215 million in 2025, representing a $16 million, or 8.0%, increase from 2024. The increase was primarily due to higher retail revenues primarily resulting from changes in rates and pricing, partially offset by increases in depreciation and amortization and other operations and maintenance expenses.

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A condensed income statement for Mississippi Power follows:

	2025		Increase<br><br>(Decrease)<br><br>from 2024
	(in millions)
Retail revenues	$	1,085	$	120
Wholesale revenues, non-affiliates	275		47
Wholesale revenues, affiliates	280		62
Other revenues	55		3
Total operating revenues	1,695		232
Fuel and purchased power	624		147
Other operations and maintenance	387		17
Depreciation and amortization	211		18
Taxes other than income taxes	139		12
Total operating expenses	1,361		194
Operating income	334		38
Interest expense, net of amounts capitalized	79		2
Other income (expense), net	25		(2)
Income taxes	65		18
Net income	$	215	$	16

Retail Revenues

Retail revenues for 2025 increased $120 million, or 12.4%, as compared to 2024. Details of the changes in retail revenues were as follows:

	2025 vs. 2024
	(in millions)		(% change)
Estimated change in retail revenues resulting from —
Rates and pricing	$	47	4.9	%
Sales growth	10		1.0
Weather	(2)		(0.2)
Fuel and other cost recovery	65		6.7
Total change in retail revenue	$	120	12.4	%

Changes in rates and pricing resulted in an increase in revenues primarily due to new PEP rates that became effective for the first billing cycle of April 2025. See Note 2 to the financial statements under "Mississippi Power – Performance Evaluation Plan" for additional information.

Changes in sales resulted in an increase in retail revenues in 2025 as compared to 2024. Changes in retail revenues are influenced heavily by the change in the volume of energy sold from year to year, which generally results from changes in electricity usage by

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customers, weather, and the number of customers. Total retail KWH sales for 2025 and the percent change from 2024 were as follows:

	2025
	Total<br>KWHs	Total KWH<br><br>Percent Change		Weather-Adjusted<br><br>Percent Change(*)
	(in millions)
Residential	2,140	2.0	%	2.1	%
Commercial	2,902	(0.7)		(0.5)
Industrial	4,795	1.3		1.3
Other	21	(11.1)		(11.1)
Total retail sales	9,858	0.8	%	0.9	%

(*)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 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.

Weather-adjusted retail energy sales increased by 86 million KWHs in 2025 as compared to 2024. Weather-adjusted residential KWH sales increased 2.1% primarily due to increased customer usage. Weather-adjusted commercial KWH sales decreased 0.5% primarily due to decreased customer usage. Industrial KWH sales increased 1.3% primarily due to increases in the petroleum and chemicals sectors.

Changes in fuel and other cost recovery revenues resulted in an increase in retail revenues in 2025 as compared to 2024 primarily due to higher recoverable fuel costs, as discussed further under "Fuel and Purchased Power Expenses" herein. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel and emissions portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates 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

Wholesale revenues from sales to non-affiliates increased $47 million, or 20.6%, in 2025 as compared to 2024. Details of wholesale revenues from power sales to non-affiliated utilities, including FERC-regulated MRA sales as well as market-based sales, were as follows:

	2025		Increase<br><br>(Decrease)<br><br>from 2024
	(in millions)
Capacity and other	$	8	$	6
Energy	267		41
Total non-affiliated	$	275	$	47

The increase in wholesale revenues from sales to non-affiliates was due to a $25 million increase associated with MRA customers largely due to higher recoverable fuel costs, a $15 million increase associated with changes in power supply agreements, and a $7 million increase in opportunity sales. Wholesale energy sales to non-affiliates totaled 3,397 million KWHs in 2025, an 8.5% increase as compared to 2024.

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 which are subject to regulation by the FERC. The contracts with these wholesale customers represented 12.9% of Mississippi Power's total operating revenues in 2025. Short-term opportunity energy sales are also included in sales for resale to non-affiliates. These opportunity sales are made at

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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 increased $62 million, or 28.4%, in 2025 as compared to 2024. The increase was primarily due to increases of $44 million related to the price of energy driven by natural gas prices and $16 million related to the volume of KWH sales. Wholesale energy sales to affiliates totaled 5,636 million KWHs in 2025, a 10.4% increase as compared to 2024. See Note 2 to the financial statements under "Mississippi Power – Integrated Resource Plans" for additional information.

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 or other contractual agreements, 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.

Other Revenues

In 2025, other operating revenues increased $3 million, or 5.8%, as compared to 2024 primarily due to an increase of $8 million in customer charges related to contributions in aid of construction included in rates, partially offset by a decrease of $4 million in transmission revenue primarily associated with open access transmission tariff revenues.

Fuel and Purchased Power Expenses

Fuel and purchased power expenses were $624 million in 2025, an increase of $147 million, or 30.8%, as compared to 2024. The increase was primarily due to a $111 million increase related to the average cost of fuel and a $36 million increase related to the volume of KWHs generated and purchased.

Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clauses. See Note 2 to the financial statements under "Mississippi Power – Fuel Cost Recovery" for additional information.

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, Mississippi Power purchases a portion of its electricity needs from the wholesale market. 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 electric 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.

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

	2025	2024
Total generation (in millions of KWHs)	18,227	17,667
Total purchased power (in millions of KWHs)	1,167	821
Sources of generation (percent) —
Gas	90	92
Coal	10	8
Cost of fuel, generated (in cents per net KWH) —
Gas	3.19	2.39
Coal	4.66	5.31
Average cost of fuel, generated (in cents per net KWH)	3.34	2.65
Average cost of purchased power (in cents per net KWH)	4.40	4.40

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $17 million, or 4.6%, in 2025 as compared to 2024. The increase was primarily due to increases of $20 million in generation expenses primarily associated with planned outages, $7 million in transmission and distribution expenses primarily associated with routine maintenance, and $3 million in customer service expenses, partially offset by a decrease of $10.9 million due to utilization of the retail reliability reserve to offset generation, transmission, and distribution expenses and a decrease of $8 million due to lower retail reliability reserve accruals. See Note 2 to the financial statements under "Mississippi Power – Reliability Reserve Accounting Order" for additional information.

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Depreciation and Amortization

Depreciation and amortization increased $18 million, or 9.3%, in 2025 as compared to 2024 primarily due to increases of $10 million resulting from higher depreciation rates and $9 million associated with additional plant in service. See Note 5 to the financial statements under "Depreciation and Amortization" for additional information.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $12 million, or 9.4%, in 2025 as compared to 2024. The increase was primarily due to an increase in property taxes primarily resulting from an increase in the assessed value of property.

Income Taxes

Income taxes increased $18 million, or 38.3%, in 2025 as compared to 2024 primarily due to a decrease of $10 million in the flowback of certain excess deferred income taxes and higher pre-tax earnings. See Note 10 to the financial statements for additional information.

Southern Power

Net income attributable to Southern Power for 2025 was $125 million, a $203 million decrease from 2024. The decrease was primarily due to accelerated depreciation related to wind repowering projects, partially offset by higher revenues driven by higher market prices of energy. See FUTURE EARNINGS POTENTIAL – "Construction Programs" herein and Note 15 to the financial statements under "Southern Power – Wind Repowering Projects" for additional information.

A condensed statement of income for Southern Power follows:

	2025		Increase<br><br>(Decrease)<br><br>from 2024
	(in millions)
Operating revenues	$	2,198	$	184
Fuel	676		97
Purchased power	122		44
Other operations and maintenance	528		12
Depreciation and amortization	843		321
Taxes other than income taxes	48		7
Total operating expenses	2,217		481
Operating income	(19)		(297)
Interest expense, net of amounts capitalized	104		(13)
Other income (expense), net	17		4
Income taxes (benefit)	(61)		(48)
Net income (loss)	(45)		(232)
Net loss attributable to noncontrolling interests	(170)		(29)
Net income attributable to Southern Power	$	125	$	(203)

Operating Revenues

Total operating revenues include PPA capacity revenues derived primarily from long-term contracts associated with natural gas facilities and PPA energy revenues derived from long-term contracts associated with 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

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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.

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:

	2025		2024
	(in millions)
PPA capacity revenues	$	513	$	497
PPA energy revenues	1,408		1,228
Total PPA revenues	1,921		1,725
Non-PPA revenues	259		252
Other revenues	18		37
Total operating revenues	$	2,198	$	2,014

Operating revenues for 2025 were $2.2 billion, a $184 million, or 9.1%, increase from 2024. The change in operating revenues was primarily due to the following:

•PPA capacity revenues increased $16 million, or 3.2%, due to a net increase in MW capacity under contract from natural gas PPAs, partially offset by a decrease associated with a change in rates from natural gas PPAs.

•PPA energy revenues increased $180 million, or 14.7%, primarily due to an increase of $96 million largely driven by fuel and purchased power prices and an increase of $87 million related to the volume of KWHs sold under natural gas PPAs.

•Non-PPA revenues increased $7 million, or 2.8%, due to an increase of $72 million driven by the market price of energy, largely offset by a decrease of $67 million related to the volume of KWHs sold through short-term sales.

•Other revenues decreased $19 million, or 51.4%, primarily due to a $16 million decrease associated with transmission revenues.

Fuel and Purchased Power Expenses

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

	Total KWHs	2025 vs. 2024
	2025	2024	Percent Change
	(in billions of KWHs)
Generation	45	44
Purchased power	3	2
Total generation and purchased power	48	46	4.3	%
Total generation and purchased power (excluding solar, wind, fuel cells, and tolling agreements)	22	28	(21.4)	%

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

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units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the Southern Company power pool for capacity owned directly by Southern Power.

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

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

	2025		2024
	(in millions)
Fuel	$	676	$	579
Purchased power	122		78
Total fuel and purchased power expenses	$	798	$	657

Total fuel and purchased power expenses increased $141 million, or 21.5%, in 2025 as compared to 2024. Fuel expense increased $97 million, or 16.8%, due to an increase of $232 million associated with the average cost of fuel, largely offset by a decrease of $135 million related to the volume of KWHs generated. Purchased power expense increased $44 million, or 56.4%, due to an increase of $29 million associated with the average cost of purchased power and an increase of $15 million related to the volume of KWHs purchased.

Depreciation and Amortization

Depreciation and amortization increased $321 million, or 61.5%, in 2025 as compared to 2024 primarily due to a $298 million increase in accelerated depreciation related to wind repowering projects. See FUTURE EARNINGS POTENTIAL – "Construction Programs" herein and Note 15 to the financial statements under "Southern Power – Wind Repowering Projects" for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized decreased $13 million, or 11.1%, in 2025 as compared to 2024. The decrease was primarily due to an $18 million increase in capitalized interest associated with construction and wind repowering projects, partially offset by a $5 million increase in interest expense 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 (Benefit)

Income tax benefit increased $48 million in 2025 as compared to 2024 primarily due to a decrease in pre-tax earnings attributable to Southern Power. See Notes 1, 10, and 15 to the financial statements under "Income Taxes," "Effective Tax Rate," and "Southern Power – Wind Repowering Projects," respectively, for additional information.

Net Loss Attributable to Noncontrolling Interests

Net loss attributable to noncontrolling interests increased $29 million, or 20.6%, in 2025 as compared to 2024. The increased loss was primarily due to $20 million in higher HLBV loss allocations to tax equity partners and $11 million in lower income allocations to equity partners.

Southern Company Gas

Southern Company Gas uses Heating Degree Days to measure weather and the operational effects on its business. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. However, Southern Company Gas has various regulatory mechanisms, such as weather and revenue normalization and straight-fixed-variable rate design, which limit positive or negative impacts to income from 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 and Georgia for gas marketing services. Therefore, weather typically does not have a significant net income impact.

During the Heating Season, 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

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quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. Thus, Southern Company Gas' operating results can vary significantly from quarter to quarter as a result of seasonality. The impact of Heating Season on Southern Company Gas' annual results is illustrated in the table below.

	Percent Generated During<br>Heating Season
	Operating<br>Revenues		Net<br>Income
2025	66	%	82	%
2024	62	%	80	%

Net Income

Net income attributable to Southern Company Gas in 2025 was $732 million, a decrease of $8 million, or 1.1%, compared to 2024. The decrease was primarily due to a $16 million decrease in net income at gas pipeline investments and a $15 million decrease in net income at gas marketing services, partially offset by a $19 million increase in net income at gas distribution operations.

A condensed income statement for Southern Company Gas follows:

	2025		Increase<br><br>(Decrease)<br><br>from 2024
	(in millions)
Natural gas revenues	$	5,044	$	588
Cost of natural gas	1,599		403
Other operations and maintenance	1,297		62
Depreciation and amortization	708		58
Taxes other than income taxes	272		24
Estimated loss on regulatory disallowance	63		63
Total operating expenses	3,939		610
Operating income	1,105		(22)
Earnings from equity method investments	127		(19)
Interest expense, net of amounts capitalized	377		36
Other income (expense), net	59		(7)
Income taxes	182		(76)
Net Income	$	732	$	(8)

Natural Gas Revenues

Natural gas revenues in 2025 were $5.0 billion, reflecting a $588 million, or 13.2%, increase compared to 2024. Details of natural gas revenues were as follows:

	2025 vs. 2024
	(in millions)		(% change)
Estimated change in natural gas revenues resulting from —
Rate changes	$	146	3.3	%
Gas costs and other cost recovery	372		8.3
Gas marketing services	61		1.4
Other	9		0.2
Total change in natural gas revenues	$	588	13.2	%

Changes in rates resulted in an increase in revenues in 2025 as compared to 2024 primarily due to base rate increases at Atlanta Gas Light and Virginia Natural Gas. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" for additional information.

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Revenues associated with gas costs and other cost recovery increased in 2025 as compared to 2024 primarily due to higher cost of natural gas driven by higher natural gas prices and volumes, as well as increases in other expenses passed through to 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 "Cost of Natural Gas" and "Other Operations and Maintenance Expenses" herein for additional information.

Revenues from gas marketing services increased in 2025 as compared to 2024 primarily due to higher commodity prices.

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, 2025 and 2024:

	2025		2024
	(in thousands, except market share percent)
Gas distribution operations	4,416		4,387
Gas marketing services
Energy customers	677		668
Market share of energy customers in Georgia	29.9	%	29.8	%

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 81.7% of the total cost of natural gas for 2025.

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, an increase of $403 million, or 33.7%, in 2025 as compared to 2024, which reflects higher gas cost recovery in 2025 as a result of a 51.0% increase in natural gas prices as compared to 2024.

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 2025 and 2024:

			2025 vs. 2024
	2025	2024	Percent Change
Gas distribution operations (mmBtu in millions)
Firm	688	626	9.9	%
Interruptible	87	92	(5.4)
Total	775	718	7.9	%
Gas marketing services (mmBtu in millions)
Firm	61	56	8.9
Interruptible large commercial and industrial	13	15	(13.3)
Total	74	71	4.2	%

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Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $62 million, or 5.0%, in 2025 as compared to 2024. The increase was primarily due to increases of $38 million in employee compensation and benefit expenses, $23 million in expenses passed through to customers at gas distribution operations, and $17 million in bad debt expense, partially offset by a decrease of $26 million related to certain deferred expenses.

Depreciation and Amortization

Depreciation and amortization increased $58 million, or 8.9%, in 2025 as compared to 2024. The increase was primarily due to additional plant in service related to continued 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 increased $24 million, or 9.7%, in 2025 as compared to 2024. The increase was primarily due to an increase in revenue taxes as a result of higher natural gas revenues at Nicor Gas. Revenue taxes imposed on Nicor Gas are recoverable from its customers.

Estimated Loss on Regulatory Disallowance

In 2025, Southern Company Gas recorded $63 million in charges related to the disallowance of certain capital investments at Nicor Gas. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings – Nicor Gas" for additional information.

Earnings from Equity Method Investments

Earnings from equity method investments decreased $19 million, or 13.0%, in 2025 as compared to 2024. The decrease was primarily due to legal settlements, increased spending on system integrity initiatives, and lower rates, all at SNG. See Note 7 to the financial statements under "Southern Company Gas" for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $36 million, or 10.6%, in 2025 as compared to 2024. The increase was primarily associated with 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

Income taxes decreased $76 million, or 29.5%, in 2025 as compared to 2024. The decrease was primarily due to lower pre-tax earnings, including the impact of the regulatory disallowance at Nicor Gas, an increase of $36 million in the flowback of excess federal and state deferred income taxes, and a decrease of $8 million related to uncertain state tax positions in 2024. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings – Nicor Gas" and Note 10 to the financial statements for additional information.

Segment Information

	2025						2024
	Operating<br><br>Revenues		Operating<br><br>Expenses		Net Income<br><br>(Loss)		Operating<br><br>Revenues		Operating<br><br>Expenses		Net Income<br><br>(Loss)
	(in millions)						(in millions)
Gas distribution operations	$	4,428	$	3,450	$	569	$	3,899	$	2,911	$	550
Gas pipeline investments	32		10		85		32		10		101
Gas marketing services	582		457		87		516		375		102
All other	12		17		(9)		23		33		(13)
Intercompany eliminations	(10)		5		—		(14)		—		—
Consolidated	$	5,044	$	3,939	$	732	$	4,456	$	3,329	$	740

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Gas Distribution Operations

The gas distribution operations segment 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 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, 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 2025, net income increased $19 million, or 3.5%, as compared to 2024 as described further below:

•Operating revenues increased $529 million primarily due to higher gas cost recovery and base rate increases. Gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas.

•Operating expenses increased $539 million primarily due to a $346 million increase in cost of natural gas as a result of higher gas prices and higher volumes sold compared to 2024, a $63 million charge related to the disallowance of certain capital investments at Nicor Gas, a $57 million increase in depreciation primarily due to additional plant in service related to continued investments at the natural gas distribution utilities, a $43 million increase related to expenses passed through to customers, a $25 million increase related to employee compensation and benefit expenses, and a $17 million increase in bad debt expense, partially offset by a decrease of $26 million related to certain deferred expenses.

•Interest expense, net of amounts capitalized increased $31 million primarily due to higher average outstanding borrowings.

•Income taxes decreased $63 million primarily due to lower pre-tax earnings, including the impact of the regulatory disallowance at Nicor Gas, and an increase in the flowback of excess federal and state deferred income taxes.

See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings – Nicor Gas" for additional information.

Gas Pipeline Investments

The gas pipeline investments segment consists primarily of joint ventures in natural gas pipeline investments including SNG and Dalton Pipeline. See Note 7 to the financial statements under "Southern Company Gas" for additional information. In 2025, net income decreased $16 million, or 15.8%, as compared to 2024 primarily due to legal settlements, increased spending on system integrity initiatives, and lower rates at SNG.

Gas Marketing Services

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

In 2025, net income decreased $15 million, or 14.7%, as compared to 2024. The decrease was due to an $82 million increase in operating expenses primarily related to an increase in cost of natural gas and an increase in charitable contributions, partially offset by a $66 million increase in operating revenues primarily due to higher commodity prices.

All Other

All other includes 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.

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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. The ability of the traditional electric operating companies and the natural gas distribution companies to effectively operate pursuant to these regulatory mechanisms and/or processes and appropriately balance required costs and capital expenditures with customer prices will continue to be a challenge 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. The Registrants are unable to predict changes in law, regulations, regulatory guidance, legal interpretations, policy positions, and implementation actions that may occur in the future.

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, extending the retirement dates of certain fossil fuel plants, and expanding and improving the transmission and distribution systems; continued customer growth; and the trends of an uncertain inflationary environment and reduced electricity usage per customer, especially in residential and commercial markets.

Earnings in the electricity business will also depend upon maintaining and growing sales and pricing of large load customers such that incremental costs are met with adequate incremental revenues, considering, among other things, recent trends driving projected growth in electricity consumption including the increasing digitization of the economy and growth in data centers, an increase in industrial activity in the Southern Company system's electric service territory, and continued electrification of transportation. Historically, the traditional electric operating companies have entered into large load contracts that support economic development and benefit existing customers; since 2023, the traditional electric operating companies have contracted with new data centers and other large load customers covering approximately nine GWs of electric load, with each contract individually representing a maximum annual electric load greater than 100 MWs, that have been signed by the parties and/or reviewed by the state regulatory commissions. These new contracts fully ramp up over several years after commencement of service. Some of these contracts are already in effect. Service under the contracts is expected to begin through 2028. The contracts contain various terms and conditions, such as minimum duration, minimum bill provisions, contribution by the customer to local construction costs, termination payment requirements, and financial security, designed to generate adequate incremental revenues associated with incremental costs to serve these customers. These projected growth opportunities may be affected by a variety of factors, such as energy efficiency, changes in technology, reliability and operational factors, customer demand, and government policies, which could increase or decrease the pace of growth associated with these opportunities. In addition, these opportunities present risks such as capital access and cost recovery risks. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" for additional information regarding Georgia Power's related regulatory proceedings.

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 generating 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 under current and future tax legislation and U.S. Treasury guidance; 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 and the OBBB's restrictions on 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

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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 United States 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, including from large customers, 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; demand growth from data centers and other large load customers and associated load and operating requirements; 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 and could be influenced by changes in technology, public policy, utility efficiency programs, and customer behavior. Significant changes in fiscal, monetary, or trade policies could affect actual economic activity and historical economic relationships in ways not anticipated in economic outlooks or Southern Company system plans. Additionally, changes in inflation, interest rates, and credit market conditions could affect the cost of doing business. All of these factors may impact future earnings. See RESULTS OF OPERATIONS herein for information on energy sales in the Southern Company system's service territory during 2025.

Mississippi Power provides service under long-term contracts with rural electric cooperative associations and a municipality located in southeastern Mississippi which are subject to regulation by the FERC. The contracts with these wholesale customers represented 12.9% of Mississippi Power's total operating revenues in 2025. See Note 2 to the financial statements under "Mississippi Power – Municipal and Rural Associations Tariff" for information on a rate settlement related to Mississippi Power's contract with Cooperative Energy through the end of 2035.

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, joint ventures, 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/or dispositions of businesses and assets as part of their business strategies. See Note 15 to the financial statements and "Construction Programs" herein 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 extensions or retirements and replacements, 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. A major portion of these costs is expected to be recovered through retail and wholesale rates,

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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 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 materially 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 2030 based on the current environmental compliance strategy for the Southern Company system and the traditional electric operating companies are as follows:

	2026		2027		2028		2029		2030		Total
	(in millions)
Southern Company	$	247	$	231	$	331	$	187	$	103	$	1,099
Alabama Power(a)	118		140		234		72		26		590
Georgia Power	117		68		60		65		69		379
Mississippi Power(b)	11		23		38		51		9		132

(a)Excludes amounts related to Alabama Power's decision to convert Plant Barry Unit 5 from coal to natural gas totaling $38 million in 2026, $15 million in 2027, and $54 million in 2028. See "Environmental Laws and Regulations – Water Quality" herein and Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" for additional information.

(b)Includes amounts contingent upon approval by the Mississippi PSC related to Mississippi Power's decision to convert Plant Daniel Unit 2 from coal to natural gas totaling $28 million in 2028 and $41 million in 2029. See Note 2 to the financial statements under "Mississippi Power – Integrated Resource Plans" for additional information.

These estimates do not include compliance costs associated with regulation of GHG emissions. See "Environmental Laws and Regulations – Greenhouse Gases" herein for additional information. The Southern Company system also anticipates substantial expenditures associated with surface impoundment 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

In February 2023, the EPA published a final rule disapproving 19 state implementation plans (SIPs), including SIPs submitted by 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). In March 2023, the State of Mississippi and Mississippi Power challenged the EPA's disapproval of the Mississippi SIP in the U.S. Court of Appeals for the Fifth Circuit. In June 2023, the U.S.

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Court of Appeals for the Fifth Circuit stayed the EPA's disapproval of the Mississippi SIP, and, on March 25, 2025, the court vacated and remanded the EPA's disapproval of the Mississippi SIP. On May 9, 2025, other parties to the case requested en banc review before the full U.S. Court of Appeals for the Fifth Circuit. The stay remains in effect, which protects the State of Mississippi from the requirements of the federal good neighbor plan. In April 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. In August 2023, the U.S. Court of Appeals for the Eleventh Circuit stayed the EPA's disapproval of the Alabama SIP, pending appeal, which protects the State of Alabama from the requirements of a federal good neighbor plan pending resolution of the case. The case is currently being held in abeyance. On January 30, 2026, the EPA published the proposed Phase 1 rule reconsideration of the good neighbor plan which includes a reconsideration of the EPA's previous disapprovals of ozone interstate transport SIPs from multiple states, including Alabama and Mississippi.

In June 2023, the EPA published the 2015 Ozone NAAQS good neighbor federal implementation plan (FIP), which requires reductions in nitrogen oxides emissions from sources in 23 states, including Alabama and Mississippi 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. In June 2023, the State of Mississippi and Mississippi Power challenged the FIP for Mississippi in the U.S. Court of Appeals for the Fifth Circuit. In August 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. In June 2024, the U.S. Supreme Court stayed the FIP pending the disposition of petitions for review of the FIP in the U.S. Court of Appeals for the D.C. Circuit and any petition for writ of certiorari to the U.S. Supreme Court. On March 12, 2025, the EPA announced its intent to reconsider the FIP.

The ultimate impact of the FIP and associated legal matters cannot be determined at this time; however, implementation of the stayed FIP and underlying SIPs would likely result in increased compliance costs for the traditional electric operating companies.

Water Quality

In May 2024, the EPA published the final rule revising the Steam Effluent Guidelines (2024 ELG Rule), which establishes more stringent limits for flue gas desulfurization wastewater, bottom ash transport water , and combustion residual leachate to be met no later than December 31, 2029. The 2024 ELG Rule maintains the 2020 ELG rule's permanent cessation of coal combustion (PCCC) subcategory and the existing rule's voluntary incentive program (VIP) compliance option. It also adds a new PCCC subcategory which allows units to cease coal combustion by December 31, 2034 as opposed to meeting the new more stringent requirements. The 2024 ELG Rule also establishes limitations for legacy wastewater. Numerous groups and states filed petitions for review challenging the rule in multiple federal circuit courts, and, in June 2024, the challenges were consolidated in the U.S. Court of Appeals for the Eighth Circuit. On February 28, 2025, the U.S. Court of Appeals for the Eighth Circuit placed the 2024 ELG Rule litigation in abeyance pending additional rulemaking. On December 31, 2025, the EPA published a final rule to extend certain 2024 ELG Rule compliance deadlines (ELG Deadline Extensions Rule), and, subsequently, multiple petitions for review were filed challenging the ELG Deadline Extensions Rule, which have been consolidated in the U.S. Court of Appeals for the Second Circuit. The EPA also indicated in this rulemaking that it will further evaluate whether to reconsider the 2024 ELG Rule technology requirements. The ultimate impacts of the 2024 ELG Rule, the ELG Deadline Extensions Rule, and associated legal matters cannot be determined at this time; however, they may result in significant compliance costs.

In 2021, Alabama Power submitted Notices of Planned Participation (NOPPs) 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 Gaston Unit 5 (880 MWs). However, subsequent to December 31, 2025, as a result of projected future generation needs, a decision was made to convert Plant Barry Unit 5 from coal to natural gas and to continue operating Plant Barry Unit 5 beyond December 31, 2028. As agent for SEGCO, Alabama Power indicated plans to retire Plant Gaston Units 1 through 4 (1,000 MWs) by December 31, 2028. However, upon further analysis, Alabama Power, in conjunction with Georgia Power, now expects to operate Plant Gaston Units 1 through 4 through December 31, 2034. As of December 31, 2025, Alabama Power is in compliance with the 2020 ELG rule generally applicable limits for bottom ash transport water for Plant Gaston Units 1 through 4. On December 30, 2025, pursuant to the 2024 ELG Rule, Alabama Power submitted additional NOPPs to the ADEM for Plant Barry Units 4 and 5, Plant Gaston Unit 5, and Plant Gorgas, opting in to the PCCC compliance subcategory for combustion residual leachate discharges by December 31, 2034. See Notes 2 and 7 to the financial statements under "Georgia Power – Integrated Resource Plans – 2025 IRP" and "SEGCO," respectively, for additional information.

The remaining assets for which Alabama Power has indicated retirement, due to repowering of the unit to natural gas, have net book values totaling approximately $464 million (excluding capitalized asset retirement costs which are recovered through Rate CNP Compliance) at December 31, 2025. 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

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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.

In 2021, Georgia Power submitted NOPPs to the Georgia Environmental Protection Division (EPD) indicating plans to retire 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 2020 ELG rule for Plant Scherer Units 1 and 2 (137 MWs based on 8.4% ownership) through the VIP by no later than December 31, 2028. As of December 31, 2025, Georgia Power is in compliance with the ELG rules for Plant Bowen Units 3 and 4 through the generally applicable requirements; therefore, no NOPP submission was required for these units. Through its 2025 IRP, Georgia Power received approval from the Georgia PSC to extend the operation of Plant Scherer Unit 3 through at least December 31, 2035, as well as Plant Gaston Units 1 through 4 (500 MWs based on 50% ownership through SEGCO) through December 31, 2034. In addition, the 2025 IRP assumes operation of Plant Bowen Units 1 and 2 through at least December 31, 2035 and does not impact the ELG compliance strategy for Plant Bowen as the flue gas desulfurization wastewater system is a common environmental control for all four generating units. On December 31, 2025, Georgia Power submitted a transfer NOPP indicating plans to pursue compliance with the 2020 ELG rule for Plant Scherer Unit 3 through the VIP by December 31, 2028. 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 Notes 2 and 7 to the financial statements under "Georgia Power – Integrated Resource Plans – 2025 IRP" and "SEGCO," respectively, 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 at active electric generating power plants. The CCR Rule requires landfills and surface impoundments to be evaluated against a set of performance criteria and potentially closed if certain criteria are not met. Closure of existing landfills and surface impoundments 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.

In June 2024, the EPA published a final determination to deny the ADEM's CCR permit program. 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 ultimate impact of the EPA's denial of ADEM's CCR permit program cannot be determined at this time; however, it may result in significant compliance costs.

Beginning in January 2022, the EPA issued numerous determinations that stated its 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 determinations may impact closure and groundwater monitoring plans.

In May 2024, the EPA published the final legacy CCR surface impoundments rule (2024 Legacy Rule) which regulates two new categories of federally regulated CCR, legacy surface impoundments and CCR management units (CCRMUs). The 2024 Legacy Rule requires legacy surface impoundments and CCRMUs to meet certain existing regulatory requirements, including a requirement to initiate closure within 42 months after the effective date of the 2024 Legacy Rule for legacy surface impoundments and within 54 months after the effective date of the 2024 Legacy Rule for CCRMUs. Numerous industry groups, electric generators, and states filed petitions for review challenging the 2024 Legacy Rule in the U.S. Court of Appeals for the D.C. Circuit. On February 13, 2025, the U.S. Court of Appeals for the D.C. Circuit placed the 2024 Legacy Rule in abeyance pending additional rulemaking. On March 12, 2025, the EPA announced its intent to undertake several regulatory actions related to the CCR Rule. On February 10, 2026, the EPA published a final rule extending certain deadlines for compliance for owners and operators of CCRMUs. The ultimate impact of any final rule and associated legal matters cannot be determined at this time; however, it may result in significant compliance costs.

Based on compliance requirements for closure and monitoring of landfills and surface impoundments pursuant to state and federal CCR 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 compliance monitoring, closure methodologies and strategies, schedules, and/or costs 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 surface impoundments. The cost estimates for Georgia Power and Mississippi Power are based on a combination of closure-in-place for some surface impoundments and closure by removal for others. Additionally, the closure designs and plans in the States of Alabama and

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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" herein, 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.

Greenhouse Gases

In May 2024, the EPA published the final GHG rules (2024 GHG Rules) to establish GHG emissions standards for existing fossil fuel-fired steam electric generating units and new fossil fuel-fired combustion turbines and combined cycle generation facilities. The 2024 GHG Rules do not include standards for existing fossil fuel-fired combustion turbines or combined cycle generation facilities. Under the 2024 GHG Rules, existing source compliance for steam generating units would begin as early as January 1, 2030, depending on the subcategory for the affected unit, and the standards for new combustion turbines and combined cycles include subcategories for low, intermediate, and base load operations. Compliance with new source standards begins when the unit comes online, with requirements for carbon capture and sequestration (CCS) beginning on January 1, 2032.

Numerous industry groups, electric generators, and states have filed petitions for review challenging the 2024 GHG Rules in the U.S. Court of Appeals for the D.C. Circuit. On April 25, 2025, the U.S. Court of Appeals for the D.C. Circuit placed the litigation over the 2024 GHG Rules in abeyance. On June 17, 2025, the EPA published a proposed rule that includes a primary proposal and an alternative proposal. Under the primary proposal, the EPA would repeal all GHG emissions standards for fossil fuel-fired power plants promulgated under Section 111 of the Clean Air Act based on a finding that GHG emissions from those plants do not meet the prerequisite for regulation under Section 111 that they contribute significantly to dangerous air pollution. Under the alternative proposal, the EPA would repeal all of the GHG emissions guidelines for existing fossil fuel-fired steam generating units as well as the carbon capture and storage requirement for new base load stationary combustion turbines, leaving the remaining emissions standards from the 2024 GHG Rules in place. The ultimate impact of any final rule and associated legal matters cannot be determined at this time; however, if the EPA selects the alternative proposal, it may result in increased compliance costs.

It is unclear what impact the EPA's February 12, 2026 repeal of its 2009 endangerment finding for GHG emissions from motor vehicles might have on the remaining Section 111 emissions standards if the EPA selects the alternative proposal. The EPA acknowledged in the repeal of the 2009 endangerment finding that other Clean Air Act rulemakings, including the Section 111 emissions standards for fossil fuel-fired power plants, have cited the 2009 endangerment finding, and the EPA said it would address any overlapping issues in separate rulemakings.

Internationally, 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. The United States withdrew from the Paris Agreement effective January 27, 2026.

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, 15% natural gas, and 14% nuclear in 2007 to a mix of 20% coal, 51% natural gas, and 19% nuclear in 2025. 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, as well as the addition of over 1,100 MWs of nuclear generating capacity (based on Georgia Power's ownership interest in Plant Vogtle Units 3 and 4) since 2023. In addition, the Southern Company system's capacity mix consists of over 12,700 MWs of renewable and storage facilities through ownership (including 100% of the nameplate capacity of Southern Power's facilities owned with partners) 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.

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The following table provides the Registrants' 2024 and preliminary 2025 Scope 1 GHG emissions based on equity share of facilities:

	2024	Preliminary 2025
	(in million metric tons of CO2 equivalent)
Southern Company(*)	79	83
Alabama Power(*)	30	31
Georgia Power	24	24
Mississippi Power(*)	9	9
Southern Power	12	12
Southern Company Gas	2	2

(*)Includes GHG emissions attributable to acquired assets beginning with the date of the applicable acquisition. See Note 15 to the financial statements for additional information.

Since 2018, Southern Company system management established GHG emissions reductions goals including an intermediate goal of 50% from 2007 levels by 2030 and a long-term goal of net zero by 2050. Based on the preliminary 2025 emissions, the Southern Company system has achieved an estimated GHG emission reduction of 47% since 2007, compared to a 49% reduction in 2024. This increase in emissions is primarily attributed to increased electric generation and changes in fuel mix driven by economic dispatch, as discussed further under RESULTS OF OPERATIONS – "Southern Company – Electricity Business" herein. 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. The natural gas distribution utilities also engage in long-term planning processes in accordance with their state regulatory processes and are investing in programs and efforts to reduce GHG emissions associated with the delivery and use of natural gas, such as advanced leak detection and repair and renewable natural gas. Due primarily to the projected electric load growth, current projections indicate it will be extremely challenging to meet the 2030 goal. The Southern Company system continues to work toward its GHG goals while seeking to ensure reliable and affordable energy for its customers. Achievement of these goals is dependent on various factors, many of which the Southern Company system does not control, including load growth across the Southern Company system's service territory, including projected load growth from large load customers, energy policy and regulations, natural gas prices, customer demand for carbon-free energy, and the development and deployment of low- to no-GHG energy technologies. Southern Company system management expects to continue to economically transition the generating fleet through a diverse portfolio of resources including low-carbon and carbon-free resources; making the necessary related investments in transmission and distribution systems; continuing to implement effective energy efficiency and demand response programs; implementing initiatives to reduce natural gas distribution emissions; continuing research and development with a focus on technologies that lower GHG emissions; and constructively engaging with policymakers, regulators, investors, customers, and other stakeholders to support outcomes leading to a net zero future. There is no guarantee that the Southern Company system will achieve these goals.

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.

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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.

Alabama Power

On November 14, 2025, Alabama Power issued an RFP seeking on-demand dispatchable capacity resources of 100 MWs or greater to meet future energy needs. 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 Southern Company system strategy continues to include developing and constructing new electric generating and battery energy storage facilities, expanding and improving the electric transmission and electric and natural gas distribution systems, and undertaking projects to comply with environmental laws and regulations.

The traditional electric operating companies are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. Major generation construction projects are subject to state PSC approval in order to be included in retail rates, through which the traditional electric operating companies recover their approved investment and a return on investment. Through the 2022 IRP and the 2023 IRP Update, the Georgia PSC has certified resources totaling approximately 13 GWs, approximately nine GWs of which are new generation and battery energy storage facilities that are being, or are expected to be, constructed by Georgia Power. These Georgia Power projects are projected to be placed in service through 2030. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" and " – Other Construction" for additional information.

Alabama Power executed an agreement to build a battery energy storage facility at the former Plant Gorgas site in Walker County, Alabama. The new Gorgas battery facility is designed to have the capacity to store up to 150 MWs of electricity generated by other Alabama Power resources. Construction began in the third quarter 2025, with projected completion by 2027.

Southern Power's construction program includes the Millers Branch solar project and the Kay, Grant Plains, Grant, Wake, and Bethel wind repowering projects. The repowering projects result in accelerated depreciation related to the equipment being replaced that will continue until the projects' CODs, which are projected to occur between the third quarter 2026 and the third quarter 2027. At December 31, 2025, the remaining pre-tax accelerated depreciation is projected to total approximately $490 million in 2026 and $100 million in 2027. The ultimate impact of these matters cannot be determined at this time. 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 approved investment and a return on investment associated with these infrastructure programs through their regulated rates, as approved by their applicable state regulatory agency. 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.

SNG is developing an approximately $3 billion proposed pipeline project, designed to meet customer demand by increasing SNG's existing pipeline capacity by approximately 1.3 billion cubic feet per day. Subject to the satisfaction or waiver of various conditions, including the receipt of all required approvals by regulators, including the FERC, the operator of the joint venture anticipates the project will be completed in 2029. Southern Company Gas' share of the total project costs would be 50%. The ultimate outcome of this matter cannot be determined at this time. See Note 7 to the financial statements under "Southern Company Gas" for additional information on SNG.

See FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements – Capital Expenditures" herein for additional information regarding the Registrants' capital requirements for their construction programs, including estimated totals for each of the next five years.

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Southern Power's Power Sales Agreements

General

Southern Power has PPAs with certain of the traditional electric operating companies, other investor-owned utilities, IPPs, municipalities, electric cooperatives, 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, Fitch, 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 2025, Southern Power continued to be successful in remarketing up to 1,339 MWs of annual generation capacity to load-serving entities, as well as to commercial and industrial customers, through several PPAs extending over the next 20 years. Market demand is being driven by customers securing generation capacity to manage risk, support reliability and operational commitments, replace expiring PPAs and retiring generation, and plan for future growth.

Natural Gas

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 and to provide a return on investment. 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 claim certain deductions and to utilize certain tax credits and net operating losses. 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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Federal Tax Legislation

In 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 CCS 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% CAMT on book income, with material adjustments for pension costs and tax depreciation. The 15% CAMT on book income can be reduced by tax credits.

The OBBB was signed into law on July 4, 2025. It extends many of the Tax Reform Legislation's provisions that were set to expire and makes some of them permanent. The OBBB includes major changes to tax incentives for renewable energy projects. The legislation restricts the ITCs and PTCs for solar and wind power projects, which were originally set to run through 2032 under the IRA. Such projects must now either begin construction by July 2026 or be fully operational by the end of 2027 in order to claim the applicable tax credits. Nuclear, hydropower, and geothermal energy projects maintain tax credits under the new law. Battery energy storage projects retain their full tax credit through 2033, with a gradual phase-out by 2036. The OBBB added new restrictions to tax credits for renewable facilities that are controlled or influenced by a prohibited foreign entity or that receive material assistance from a prohibited foreign entity. Pursuant to an executive order, the U.S. Treasury issued a notice on August 15, 2025, making changes to the start-of-construction guidance for wind and solar projects that begin construction after September 1, 2025. The Southern Company system is implementing the guidance in its plans for future renewable projects. Additionally, the IRS is expected to issue significant guidance on the tax provisions in the OBBB. The Southern Company system is still assessing and will continue to monitor the impacts of the OBBB. The ultimate outcome of this legislation cannot be determined at this time.

For solar projects placed in service in 2022 through 2027 or that begin construction by July 2026, the IRA and the OBBB provide for a 30% ITC and an option to claim a PTC instead of an ITC. Starting in 2023 and through 2033, with a gradual phase-out by 2036, the IRA and the OBBB provide for a 30% ITC for stand-alone battery energy storage projects. For wind projects placed in service in 2022 through 2027 or that have begun construction by July 2026, the IRA and the OBBB provide for a 100% PTC, adjusted for inflation annually. The 2025 PTC rate is 3 cents per KWH on solar and wind projects where PTCs have been elected. To realize the full value of ITCs and PTCs, the IRA requires satisfaction of prevailing wage and apprenticeship requirements.

In April 2024, the IRS issued final regulations related to the transfer of tax credits. Alabama Power, Georgia Power, and Southern Power have entered into purchase and sale agreements with non-affiliated parties to sell ITCs and PTCs at a discount to the generated credit value in 2024, 2025, and 2026. The discount will be recorded as a reduction in tax credits recognized in the financial statements. The Southern Company system continues to explore the ability to efficiently monetize tax credits through third-party transferability agreements. See Note 10 to the financial statements for additional information.

Tax Credits

Southern Company receives ITCs and PTCs in connection with investments in solar, wind, fuel cell, nuclear, hydroelectric, and battery energy storage facilities primarily at Southern Power, Georgia Power, and Alabama 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 and solar facilities, which have had, and may continue to have, a material impact on Southern Power's cash flows and net income. At December 31, 2025, Southern Company and Southern Power had approximately $850 million and $481 million, respectively, of unutilized federal ITCs and PTCs, which are currently projected to be fully utilized by 2031 but could be further delayed. Since 2018, Southern Power has utilized tax equity partnerships for certain 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. On December 31, 2025, Southern Power purchased 100% of the noncontrolling Class A membership interests in the SP Wind tax equity partnership and became the sole owner of SP Wind, and the partnership was dissolved. Beginning in 2026, Southern Power will recognize the full tax benefit, net of applicable transfer discounts, on credits generated by the eight underlying wind facilities as they are generated. See Note 15 under "Southern Power – Purchase of Renewable Facility Interests" for additional information.

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.

In the third quarter 2023 and the second quarter 2024, Georgia Power started generating advanced nuclear PTCs for Plant Vogtle Units 3 and 4, respectively, beginning on each unit's respective in-service date. PTCs are recognized as an income tax benefit

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based on KWH production. In addition, pursuant to the Vogtle Joint Ownership Agreements (as defined in Note 2 to the financial statements under "Georgia Power – Nuclear Construction – Cost and Schedule"), Georgia Power is purchasing advanced nuclear PTCs for Plant Vogtle Units 3 and 4 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.

Alabama Power and Georgia Power have nuclear generating facilities that qualify for Internal Revenue Code §45U PTCs under the IRA. The §45U PTC is available for tax years 2024 to 2032 and is subject to a phase-out. Southern Company, Alabama Power, and Georgia Power each evaluates annually whether it qualifies for the credit. For the 2024 tax year, Southern Company, Alabama Power, and Georgia Power claimed a credit of $373 million, $180 million, and $193 million, respectively, on the consolidated federal tax return, which included the prevailing wage multiplier. This credit, net of the transfer discount, was recorded as a regulatory liability. In November 2025, Southern Company received a full acceptance letter from the IRS for the consolidated 2024 federal income tax return. The estimated total credit amounts for the 2025 tax year are $122 million, $50 million, and $72 million for Southern Company, Alabama Power, and Georgia Power, respectively. Due to uncertainty regarding the acceptance of this credit by the IRS, the amounts for the 2025 tax year have been fully reserved. The ultimate outcome of this matter cannot be determined at this time.

See Note 2 to the financial statements under "Alabama Power – Nuclear Production Tax Credits Order" and "Georgia Power – Rate Plans" and Note 10 to the financial statements under "Unrecognized Tax Benefits" for additional information.

Implementation of the IRA and OBBB provisions related to existing nuclear generating facilities is subject to the issuance of additional guidance by the U.S. Treasury and the IRS. The applicable Registrants are still evaluating the impacts, and the ultimate outcome of this matter cannot be determined at this time.

Corporate Alternative Minimum Tax

On June 2, 2025 and September 30, 2025, the U.S. Treasury and the IRS issued guidance on the application of the CAMT. Southern Company has filed its consolidated 2024 federal income tax return and determined it was not subject to CAMT. Southern Company is still assessing the issued guidance and is not expecting to be subject to CAMT for the 2025 tax year.

Implementation of the IRA and OBBB provisions related to CAMT is subject to the issuance of additional guidance by the U.S. Treasury and the IRS. The Registrants are still evaluating the impacts, and the ultimate outcome of this matter cannot be determined at this time.

Natural Gas Safe Harbor Method

In 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. In April 2024, the IRS issued Revenue Procedure 2024-23, which gives additional implementation guidance on the natural gas safe harbor tax method of accounting for qualifying repair deductions. Southern Company and Southern Company Gas submitted a tax accounting method change for qualifying expenditures with the filing of its consolidated 2024 federal income tax return. The new tax method of accounting resulted in a material net positive cash flow for Southern Company Gas. This method change did not have an impact on the net income of Southern Company and Southern Company Gas. See Note 10 to the financial statements under "Deferred Tax Assets and Liabilities – Tax Credit Carryforwards" for additional information.

Georgia State Tax Legislation

On April 15, 2025, the State of Georgia enacted tax legislation that reduced the corporate income tax rate from 5.39% to 5.19% effective for the 2025 tax year. This legislation reduced the amount of Southern Company's and certain subsidiaries' income tax expense in the State of Georgia and existing state net accumulated deferred tax liabilities, increased regulatory liabilities at Georgia Power and Southern Company Gas, and reduces Georgia Power's ability to utilize certain state tax credits in the State of Georgia. The legislation did not have a material impact on the net income of the applicable Registrants in 2025.

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

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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.

Revenues related to regulated utility operations as a percentage of total operating revenues in 2025 for the applicable Registrants were as follows: 90% for Southern Company, 98% for Alabama Power, 95% for Georgia Power, 99% for Mississippi Power, and 88% 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 the amounts of such regulatory assets and liabilities and could adversely impact the financial statements of the applicable Registrants.

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 except for certain credit utilization and state apportionment results. 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 net operating loss carryforwards that would not otherwise result on a stand-alone basis. Utilization of these carryforwards and the

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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 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 surface impoundments. 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 Plants Hatch and Vogtle). 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 surface impoundments. The cost estimates for Georgia Power and Mississippi Power are based on a combination of closure-in-place for some surface impoundments 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 surface impoundments recorded during 2025 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.

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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.

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 2026	Projected Obligation for Pension Plan at December 31, 2025	Projected Obligation for<br><br>Other Postretirement<br><br>Benefit Plans at December 31, 2025
	(in millions)
Discount rate:
Southern Company	$28/$(27)	$380/$(362)	$31/$(30)
Alabama Power	$7/$(7)	$91/$(87)	$8/$(8)
Georgia Power	$7/$(7)	$108/$(103)	$11/$(10)
Mississippi Power	$1/$(1)	$17/$(16)	$1/$(1)
Southern Company Gas	$2/$(2)	$25/$(23)	$3/$(3)
Salaries:
Southern Company	$16/$(16)	$77/$(75)	$–/$–
Alabama Power	$4/$(4)	$21/$(21)	$–/$–
Georgia Power	$4/$(4)	$20/$(20)	$–/$–
Mississippi Power	$1/$(1)	$3/$(3)	$–/$–
Southern Company Gas	$1/$(1)	$3/$(3)	$–/$–
Long-term return on plan assets:
Southern Company	$42/$(42)	N/A	N/A
Alabama Power	$11/$(11)	N/A	N/A
Georgia Power	$13/$(13)	N/A	N/A
Mississippi Power	$2/$(2)	N/A	N/A
Southern Company Gas	$3/$(3)	N/A	N/A

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

Impairment (Southern Company, Alabama Power, 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

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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, 2025.

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.

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, Alabama Power, 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. See Notes 1 and 15 to the financial statements for additional information, including any recent asset impairments.

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.

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 a normal sale contract. The determination of whether a contract can be designated as a normal sale contract requires judgment,

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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 and any goodwill is recognized as a residual over the fair values of the identifiable net assets acquired. 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 has 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. See Note 7 to the financial statements under "Southern Power – Variable Interest Entities" for additional information.

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 an 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, 2025. 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 surface impoundments, 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 transmission and 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. For the three-year period from 2026 through 2028, each Registrant's projected stock dividends, capital expenditures, and debt maturities, as well as distributions to noncontrolling interests for Southern Power, are expected to exceed its operating cash flows. 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, equity, and/or hybrid securities in the capital markets, and/or through its stock plans and its continuous equity offering program. 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 other sources, and equity contributions from Southern Company. 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.

See Note 11 to the financial statements under "Pension Plans" for information on the Registrants' investments in their qualified pension plans. No mandatory contributions to the qualified pension plans are anticipated during 2026. See Note 6 to the financial statements under "Nuclear Decommissioning" for information on Alabama Power's and Georgia Power's investments in their respective nuclear decommissioning trust funds.

At the end of 2025, the market price of Southern Company's common stock was $87.20 per share (based on the closing price as reported on the NYSE) and the book value was $32.18 per share, representing a market-to-book value ratio of 271%, compared to $82.32, $30.28, and 272%, respectively, at the end of 2024.

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Cash Requirements

Capital Expenditures

Total estimated capital expenditures, including LTSA and nuclear fuel commitments, for the Registrants through 2030 based on their current construction programs are as follows:

	2026		2027		2028		2029		2030
	(in billions)
Southern Company(a)(b)(c)(d)(e)	$	15.9	$	18.5	$	17.1	$	14.6	$	12.0
Alabama Power(a)	2.0		2.1		2.1		2.1		1.9
Georgia Power(b)	10.1		12.7		12.1		9.8		7.7
Mississippi Power(c)	0.4		0.4		0.4		0.3		0.3
Southern Power(d)	0.9		0.5		0.1		0.2		0.1
Southern Company Gas(e)	2.2		2.6		2.4		2.0		2.0

(a)Excludes amounts related to Alabama Power's decision to convert Plant Barry Unit 5 from coal to natural gas totaling $38 million in 2026, $15 million in 2027, and $54 million in 2028. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" herein and Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" for additional information.

(b)Includes expenditures of approximately $3.1 billion, $5.5 billion, $5.1 billion, $3.2 billion, and $0.8 billion for 2026 through 2030, respectively, for construction projects and related transmission investments approved in conjunction with the 2022 IRP, the 2023 IRP Update, and the 2025 IRP. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" and " – Other Construction" for additional information.

(c)Includes amounts contingent upon approval by the Mississippi PSC related to Mississippi Power's decision to convert Plant Daniel Unit 2 from coal to natural gas totaling $28 million in 2028 and $41 million in 2029. See Note 2 to the financial statements under "Mississippi Power – Integrated Resource Plans" for additional information.

(d)Includes $40 million in 2026 related to the Millers Branch solar project and $0.7 billion and $0.4 billion in 2026 and 2027, respectively, related to wind repowering projects. Excludes approximately $0.8 billion per year for 2026 through 2029 and $0.7 billion for 2030 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. See Note 15 to the financial statements under "Southern Power" for additional information regarding the Millers Branch solar project and the wind repowering projects.

(e)Includes gas pipeline investment of approximately $0.3 billion, $0.8 billion, $0.5 billion, and $0.1 billion for 2026 through 2029, respectively. See FUTURE EARNINGS POTENTIAL – "Construction Programs" herein for information regarding this project.

Total estimated capital expenditures, primarily at the traditional electric operating companies, increased significantly since 2023, from $45.2 billion previously estimated for 2024 through 2028 to $78.1 billion currently estimated for 2026 through 2030. The traditional electric operating companies project a significant increase in demand for electricity sales, largely driven by data centers and other large load customers. Serving the projected increased load demand from these new customers while continuing to serve existing customers safely, reliably, and affordably requires investing in generation, transmission, and distribution systems and pricing sales to these new customers such that the related incremental costs are met with adequate incremental revenues from these new customers. Through the 2022 IRP and the 2023 IRP Update, the Georgia PSC has certified resources totaling approximately 13 GWs, approximately nine GWs of which are new generation and battery energy storage facilities that are being, or are expected to be, constructed by Georgia Power. The certified costs of these Georgia Power projects total $19.5 billion, and these projects are projected to be placed in service through 2030. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" and " – Other Construction" for additional information.

These capital expenditures include estimates to comply with environmental laws and regulations, but do not include compliance costs associated with regulation of GHG emissions. See FUTURE EARNINGS POTENTIAL – "Environmental Matters" herein for additional information. At December 31, 2025, 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 surface impoundments and landfills in accordance with state and federal CCR rules, which are reflected in the applicable Registrants' ARO liabilities. The cost estimates for Alabama Power are based on closure-in-place for all surface impoundments. The cost estimates for Georgia Power and Mississippi Power are based on a combination of closure-in-place for some surface impoundments 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 2030 are provided in the table below. Material expenditures in future years for ARO settlements will also be required for surface impoundments, nuclear decommissioning (for Alabama Power and Georgia Power), and other liabilities reflected in the

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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.

	2026		2027		2028		2029		2030
	(in millions)
Southern Company	$	653	$	645	$	520	$	750	$	730
Alabama Power	256		265		209		206		187
Georgia Power	360		341		297		541		540
Mississippi Power	18		14		13		2		2

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; changes in technology; 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, regulation, and/or tariff policy; the cost, availability, and efficiency of construction labor, equipment, and materials; project scope and design changes; abnormal weather; delays in construction due to judicial or regulatory action; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures and AROs will be fully recovered. Additionally, expenditures associated with Southern Power's planned acquisitions may vary due to market opportunities and the execution of its growth strategy. See Note 15 to the financial statements under "Southern Power" for additional information regarding Southern Power's plant acquisitions and construction projects.

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, 2025, 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. Total estimated costs for fuel and purchased power commitments at December 31, 2025 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, 2025. As discussed under "Capital Expenditures" herein, estimated expenditures for nuclear fuel are included in the applicable Registrants' construction programs for the years 2026 through 2030. Nuclear fuel commitments at December 31, 2025 that extend beyond 2030 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.

	2026		2027		2028		2029		2030		Thereafter
	(in millions)
Southern Company(*)	$	3,955	$	3,097	$	2,260	$	1,500	$	1,032	$	3,517
Alabama Power	1,309		1,053		825		456		259		900
Georgia Power(*)	1,494		1,234		918		670		462		1,509
Mississippi Power	520		364		255		194		161		692
Southern Power	698		515		335		192		150		416

(*)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 certified two 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

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with the PPAs total $61 million in 2030 and $2.6 billion thereafter. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans – Certification Requests" for additional information.

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 2026 through 2030. Total estimated payments for LTSA commitments at December 31, 2025 that extend beyond 2030 are provided in the following table and include price escalation based on inflation indices:

	Southern<br>Company		Alabama<br><br>Power		Georgia<br>Power		Mississippi<br><br>Power		Southern<br><br>Power
	(in millions)
LTSA commitments (after 2030)	$	1,239	$	345	$	97	$	50	$	747

In addition, Southern Power has certain other operations and maintenance agreements. Total estimated costs for these commitments at December 31, 2025 are provided in the table below.

	2026		2027		2028		2029		2030		Thereafter
	(in millions)
Southern Power's operations and maintenance agreements	$	68	$	66	$	67	$	60	$	61	$	364

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 39 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2025 and valued at $151 million. 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, 2025 were as follows:

	2026		2027		2028		2029		2030		Thereafter
	(in millions)
Pipeline charges, storage capacity, and gas supply	$	734	$	549	$	548	$	458	$	423	$	4,522

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 other sources, and equity contributions from Southern Company. Operating cash flows provide a substantial portion of the Registrants' cash needs.

The amount, type, and timing of any financings in 2026, 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.

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, 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.

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

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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 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, 2025, the amount of subsidiary retained earnings restricted to dividend totaled $1.8 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, 2025. The following table shows the amount by which current liabilities exceeded current assets at December 31, 2025 for the applicable Registrants:

At December 31, 2025	Southern<br>Company		Georgia<br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
Current liabilities in excess of current assets	$	5,971	$	2,412	$	146	$	548	$	785

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, 2025, unused committed credit arrangements with banks were as follows:

At December 31, 2025	Southern<br>Company<br>parent		Alabama<br><br>Power(a)		Georgia<br><br>Power(b)		Mississippi<br><br>Power		Southern<br><br>Power(c)		Southern<br><br>Company<br><br>Gas(d)		SEGCO		Southern<br>Company
	(in millions)
Unused committed credit	$	2,999	$	1,365	$	2,042	$	275	$	600	$	1,598	$	30	$	8,909

(a)Includes $15 million at Alabama Property Company, a wholly-owned subsidiary of Alabama Power. Alabama Power is not party to this arrangement.

(b)Georgia Power had $26 million of letters of credit outstanding under an uncommitted letter of credit facility at December 31, 2025.

(c)At December 31, 2025, Southern Power also had two continuing letters of credit facilities for standby letters of credit, of which $21 million was unused. In addition, Southern Power Company has $23 million of letters of credit outstanding under an uncommitted letter of credit facility at December 31, 2025. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.

(d)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, 2025, outstanding variable rate demand revenue bonds of the traditional electric operating companies with allocated liquidity support totaled approximately $1.5 billion (comprised of approximately $796 million at Alabama Power, $667 million at Georgia

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Power, and $58 million at Mississippi Power). In addition, at December 31, 2025, Alabama Power and Georgia Power had approximately $280 million and $384 million, respectively, of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months. Alabama Power's $280 million of fixed rate revenue bonds are classified as securities due within one year on its balance sheet as they are not covered by long-term committed credit. All other 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.

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<br>Outstanding						Weighted Average<br>Interest Rate
	December 31,						December 31,
	2025		2024		2023		2025		2024		2023
	(in millions)
Southern Company	$	722	$	1,338	$	2,314	3.9	%	4.8	%	5.7	%
Alabama Power	—		—		40		—		—		5.5
Georgia Power	160		200		1,329		3.9		5.3		5.9
Mississippi Power	—		14		—		—		4.6		—
Southern Power	138		—		138		3.9		—		5.5
Southern Company Gas:
Southern Company Gas Capital	$	209	$	283	$	23	3.9	%	4.7	%	5.5	%
Nicor Gas	216		172		392		3.9		4.6		5.5
Southern Company Gas Total	$	425	$	455	$	415	3.9	%	4.7	%	5.5	%			Short-term Debt During the Period(*)
---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---
	Average Amount<br><br>Outstanding						Weighted Average<br>Interest Rate						Maximum Amount<br><br>Outstanding
	2025		2024		2023		2025		2024		2023		2025		2024		2023
	(in millions)												(in millions)
Southern Company	$	891	$	1,606	$	2,191	4.6	%	5.6	%	5.6	%	$	2,291	$	3,211	$	3,270
Alabama Power	4		50		44		4.2		5.5		5.0		75		250		230
Georgia Power	305		560		1,440		4.8		6.0		5.8		1,025		1,422		2,260
Mississippi Power	25		40		56		4.6		5.4		5.5		144		154		169
Southern Power	43		125		158		4.6		5.4		5.6		285		256		359
Southern Company Gas:
Southern Company Gas Capital	$	249	$	95	$	163	4.6	%	5.3	%	5.3	%	$	540	$	405	$	440
Nicor Gas	56		141		88		4.2		5.3		5.1		271		397		483
Southern Company Gas Total	$	305	$	236	$	251	4.5	%	5.3	%	5.2	%

(*)Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2025, 2024, and 2023.

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Analysis of Cash Flows

Net cash flows provided from (used for) operating, investing, and financing activities in 2025 and 2024 are presented in the following table:

Net cash provided from (used for):	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br><br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
2025
Operating activities	$	9,802	$	2,572	$	4,808	$	414	$	670	$	1,617
Investing activities	(13,959)		(2,814)		(7,933)		(356)		(934)		(1,768)
Financing activities	4,696		223		3,066		(45)		201		122
2024
Operating activities	$	9,788	$	2,895	$	4,793	$	406	$	708	$	1,552
Investing activities	(9,400)		(1,987)		(4,896)		(373)		(330)		(1,711)
Financing activities	(208)		(732)		146		(58)		(354)		168

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

Southern Company

Net cash provided from operating activities increased $14 million in 2025 as compared to 2024 primarily due to higher net income after non-cash adjustments and the timing of storm restoration cost recovery at Georgia Power and customer receivable collections, largely offset by the timing of vendor payments, decreased retail fuel cost recovery, and the timing of tax payments. See Note 2 to the financial statements under "Georgia Power – Storm Damage Recovery" for additional information.

The net cash used for investing activities in 2025 and 2024 was primarily related to the Subsidiary Registrants' construction programs.

The net cash provided from financing activities in 2025 was primarily related to net issuances of long-term debt and issuances of common stock through the settlement of forward sale contracts, partially offset by common stock dividend payments, a reduction in commercial paper borrowings, and Southern Power's purchase of membership interests in SP Wind. The net cash used for financing activities in 2024 was primarily related to common stock dividend payments, a reduction in commercial paper borrowings, and a net decrease in short-term borrowings, partially offset by net issuances of long-term debt. See Notes 8 and 15 to the financial statements under "Equity Distribution Agreement" and "Southern Power – Purchase of Renewable Facility Interests," respectively, for additional information.

Alabama Power

Net cash provided from operating activities decreased $323 million in 2025 as compared to 2024 primarily due to a decrease in fuel cost recovery and customer refunds associated with the nuclear fuel disposal cost award, partially offset by the monetization of §45U PTCs. See Notes 2 and 3 to the financial statements under "Alabama Power – Nuclear Production Tax Credits Order" and "Nuclear Fuel Disposal Costs," respectively, for additional information.

The net cash used for investing activities in 2025 and 2024 was primarily related to gross property additions and, for 2025, the acquisition of the Lindsay Hill Generating Station. See Note 15 to the financial statements under "Alabama Power" for additional information.

The net cash provided from financing activities in 2025 was primarily related to net issuances of senior notes and capital contributions from Southern Company, partially offset by common stock dividend payments. The net cash used for financing activities in 2024 was primarily related to common stock dividend payments, partially offset by capital contributions from Southern Company.

Georgia Power

Net cash provided from operating activities increased $15 million in 2025 as compared to 2024 primarily due to the timing of storm restoration cost recovery and customer receivable collections and an increase in retail revenues associated with base tariff increases, largely offset by the timing of vendor payments and higher income tax payments. See Note 2 to the financial statements under "Georgia Power – Storm Damage Recovery" for additional information relating to storm restoration costs.

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The net cash used for investing activities in 2025 and 2024 was primarily related to gross property additions including costs associated with projects approved through the 2023 IRP Update and the certification requests in September and December 2025. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" and " – Other Construction" for information regarding Georgia Power's current construction projects.

The net cash provided from financing activities in 2025 was primarily related to capital contributions from Southern Company and net issuances of senior notes, partially offset by common stock dividend payments. The net cash provided from financing activities in 2024 was primarily related to capital contributions from Southern Company and net issuances of senior notes, partially offset by common stock dividend payments, a reduction in commercial paper borrowings, and a net decrease in short-term borrowings.

Mississippi Power

Net cash provided from operating activities increased $8 million in 2025 as compared to 2024 primarily due to funds received as part of the Plant Daniel acquisition, lower income tax payments, and the timing of fossil fuel stock purchases, largely offset by decreased fuel cost recovery. See Note 2 to the financial statements under "Mississippi Power – Plant Daniel" for additional information.

The net cash used for investing activities in 2025 and 2024 was primarily related to gross property additions.

The net cash used for financing activities in 2025 was primarily related to common stock dividend payments and a reduction in commercial paper borrowings, partially offset by issuances of senior notes and capital contributions from Southern Company. The net cash used for financing activities in 2024 was primarily related to common stock dividend payments, partially offset by capital contributions from Southern Company and net issuances of senior notes.

Southern Power

Net cash provided from operating activities decreased $38 million in 2025 as compared to 2024 primarily due to a change in the utilization of federal tax credit carryforwards, partially offset by the timing of customer receivable collections.

The net cash used for investing activities in 2025 and 2024 was primarily related to ongoing construction activities. See Note 15 to the financial statements under "Southern Power" for additional information.

The net cash provided from financing activities in 2025 was primarily related to capital contributions from Southern Company, net issuances of senior notes, and an increase in commercial paper borrowings, partially offset by the purchase of membership interests from noncontrolling interests, common stock dividend payments, and net distributions to noncontrolling interests. The net cash used for financing activities in 2024 was primarily related to common stock dividend payments, net distributions to noncontrolling interests, and a reduction in commercial paper borrowings, partially offset by capital contributions from Southern Company.

Southern Company Gas

Net cash provided from operating activities increased $65 million in 2025 as compared to 2024 primarily due to changes in recovery on certain regulatory clauses, due to weather impacts and timing, and timing of payments for natural gas as a result of higher volume and prices, as well as timing of other vendor payments, partially offset by timing of customer receivable collections as a result of weather impacts, higher natural gas prices, and increased base rates in 2025, as well as timing of income tax payments.

The net cash used for investing activities in 2025 and 2024 was primarily related to construction of transmission and distribution assets recovered through base rates.

The net cash provided from financing activities in 2025 was primarily related to net issuances of senior notes and first mortgage bonds, partially offset by common stock dividend payments. The net cash provided from financing activities in 2024 was primarily related to the issuance of senior notes and first mortgage bonds, partially offset by common stock dividend payments.

Significant Balance Sheet Changes

Southern Company

Significant balance sheet changes in 2025 for Southern Company included:

•an increase of $9.7 billion in total property, plant, and equipment primarily related to the Subsidiary Registrants' construction programs;

•an increase of $8.4 billion in long-term debt (including securities due within one year) related to issuances of senior notes and junior subordinated notes, partially offset by repayment of senior notes;

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•an increase of $2.8 billion in total common stockholders' equity primarily related to net income and issuances of common stock largely through the settlement of forward sale contracts, partially offset by common stock dividend payments;

•a decrease of $630 million in under recovered fuel clause revenues primarily due to increased fuel cost recovery at Georgia Power;

•a decrease of $616 million in notes payable due to a reduction in commercial paper borrowings and repayment of short-term bank debt;

•a decrease of $615 million in noncontrolling interests primarily related to Southern Power's purchase of membership interests in SP Wind, net distributions to noncontrolling interests, and net loss attributable to noncontrolling interests;

•an increase of $583 million in prepaid pension costs primarily related to actual returns on plan assets, partially offset by actuarial losses resulting from decreases in the assumed discount rates;

•an increase of $569 million in cash and cash equivalents, as reflected in the statements of cash flows and discussed further under "Analysis of Cash Flow – Southern Company" herein; and

•an increase of $403 million in accumulated deferred income taxes primarily related to an increase in property-related timing differences and federal tax credit carryforwards.

See "Financing Activities" herein and Notes 2, 5, 7, 8, 10, 11, and 15 to the financial statements for additional information.

Alabama Power

Significant balance sheet changes in 2025 for Alabama Power included:

•an increase of $1.3 billion in total property, plant, and equipment primarily related to the construction of transmission and distribution facilities and the acquisition of the Lindsay Hill Generating Station;

•an increase of $906 million 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 $859 million in long-term debt (including securities due within one year) primarily due to net issuances of senior notes; and

•decreases of $379 million and $262 million in AROs and regulatory assets associated with AROs, respectively, primarily related to settlements and cost estimate updates.

See "Financing Activities – Alabama Power" herein and Notes 5, 6, 8, and 15 to the financial statements for additional information.

Georgia Power

Significant balance sheet changes in 2025 for Georgia Power included:

•an increase of $6.8 billion in total property, plant, and equipment primarily related to the construction of generation, transmission, and distribution facilities, including costs associated with projects approved through the 2023 IRP Update and the certification requests in September and December 2025;

•an increase of $3.4 billion in common stockholder's equity primarily due to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company;

•an increase of $3.1 billion in long-term debt (including securities due within one year) primarily due to net issuances of senior notes;

•a decrease of $644 million in under recovered retail fuel clause revenues primarily resulting from increased recovery of deferred fuel expense as ordered in Georgia Power's 2023 fuel cost recovery case; and

•an increase of $426 million in accumulated deferred income taxes primarily related to an increase in property-related timing differences.

See "Financing Activities –Georgia Power" herein and Notes 2, 5, 8, and 10 to the financial statements for additional information.

Mississippi Power

Significant balance sheet changes in 2025 for Mississippi Power included:

•an increase of $171 million in total property, plant, and equipment primarily related to the construction of transmission and distribution facilities;

•an increase of $100 million in common stockholder's equity primarily related to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company;

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•an increase of $93 million in long-term debt (including securities due within one year) primarily due to issuances of senior notes;

•a decrease of $55 million in other cost of removal obligations primarily due to an increase in expenditures related to transmission and other production assets; and

•an increase of $41 million in other deferred credits and liabilities primarily due to contributions in aid of construction.

See "Financing Activities – Mississippi Power" herein and Notes 5 and 8 to the financial statements for additional information.

Southern Power

Significant balance sheet changes in 2025 for Southern Power included:

•an increase of $260 million in long-term debt (including securities due within one year) primarily due to net issuances of senior notes;

•an increase of $162 million in total property, plant, and equipment in service primarily due to an increase in CWIP primarily related to the continued construction of the Millers Branch solar facility and the wind repowering projects, partially offset by the continued depreciation of assets;

•a decrease of $161 million in total stockholders' equity primarily due to the purchase of membership interests from noncontrolling interests, dividends paid to Southern Company, net distributions to noncontrolling interests, and net loss, partially offset by capital contributions from Southern Company;

•an increase of $138 million in notes payable due to an increase in commercial paper borrowings; and

•a decrease of $133 million in accumulated deferred income taxes primarily related to a change in the utilization of ITCs.

See "Financing Activities – Southern Power" and Notes 5, 8, 10, and 15 to the financial statements for additional information.

Southern Company Gas

Significant balance sheet changes in 2025 for Southern Company Gas included:

•an increase of $1.2 billion in total property, plant, and equipment primarily related to the construction of transmission and distribution assets;

•an increase of $743 million in long-term debt (including securities due within one year) due to net issuances of senior notes and first mortgage bonds;

•an increase of $200 million in total accounts receivable primarily related to higher customer billings driven by colder weather, higher natural gas prices, and increased base rates;

•an increase of $175 million in accumulated deferred income taxes primarily due to reversal of CAMT and additional property-related timing differences;

•an increase of $131 million in common stockholder's equity primarily related to net income, partially offset by dividends paid to Southern Company; and

•an increase of $111 million in total accounts payable primarily related to higher natural gas volumes and prices and the timing of vendor payments.

See "Financing Activities – Southern Company Gas" and FUTURE EARNINGS POTENTIAL – "Income Tax Matters" herein and Notes 5, 8, and 10 to the financial statements for additional information.

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Financing Activities

The following table outlines long-term debt financing activities for the year ended December 31, 2025:

	Issuances and Reofferings				Maturities and Redemptions
Company	Senior Notes		Other Long-<br><br>Term Debt			Senior Notes		Revenue<br><br>Bonds		Other Long-<br><br>Term Debt(a)
	(in millions)
Southern Company parent	$	3,650	$	2,365		$	2,895	$	—	$	—
Alabama Power	1,100		5			250		—		3
Georgia Power	3,100		—			700		45		118
Mississippi Power	100		—			—		11		1
Southern Power	1,100		—			900		—		—
Southern Company Gas	850		200			250		—		50
Other(b)	—		—			—		—		13
Elimination(c)	—		—			—		—		(18)
Southern Company	$	9,900	$	2,570		$	4,995	$	56	$	167

(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)Includes repayment by SEGCO of $10 million of its $100 million principal amount long-term bank loan due November 15, 2026, which is guaranteed by Alabama Power. See Note 3 to the financial statements under "Guarantees" for additional information.

(c)Represents reductions in affiliate finance lease obligations at Georgia Power, which are eliminated in Southern Company's consolidated financial statements.

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

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

Southern Company

During 2025, Southern Company issued approximately 22.5 million shares of common stock primarily through forward sale contract settlements and dividend reinvestment and employee equity compensation and savings plans. Proceeds from settlements of the forward sale contracts totaled approximately $1.5 billion. Also during 2025, Southern Company entered into additional forward sale contracts for the issuance of shares of common stock that may be settled through June 2027. See Note 8 to the financial statements under "Equity Distribution Agreement" for additional information.

In addition, in November 2025, Southern Company issued 40 million 2025 Series A Equity Units (2025 Equity Units), initially in the form of corporate units (Corporate Units), at a stated amount of $50 per Corporate Unit, for a total stated amount of $2 billion. Net proceeds from the issuance were $1.965 billion. Each Corporate Unit is comprised of (i) a stock purchase contract, which obligates the holder to purchase from Southern Company, no later than December 15, 2028, a certain number of shares of Southern Company's common stock for $50 in cash, (ii) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2025B Remarketable Senior Notes due 2030, and (iii) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2025C Remarketable Senior Notes due 2033. See Note 8 to the financial statements under "Equity Units" for additional information.

In January 2025, Southern Company issued $565 million aggregate principal amount of Series 2025A 6.50% Junior Subordinated Notes due March 15, 2085.

In February 2025, Southern Company issued $1.8 billion aggregate principal amount of Series 2025B 6.375% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due March 15, 2055.

In May 2025, Southern Company issued $1.65 billion aggregate principal amount of Series 2025A 3.25% Convertible Senior Notes due June 15, 2028 in a private offering. Southern Company used a portion of the proceeds from this issuance to repurchase approximately $781.6 million of the $1.725 billion aggregate principal amount outstanding of its Series 2023A 3.875% Convertible Senior Notes due December 15, 2025 (Series 2023A Convertible Senior Notes) and approximately $328.1 million of the $1.5 billion aggregate principal amount outstanding of its Series 2024A 4.50% Convertible Senior Notes due June 15, 2027

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(Series 2024A Convertible Senior Notes). See Note 8 to the financial statements under "Convertible Senior Notes" herein for additional information.

In October 2025, Southern Company repaid at maturity $500 million aggregate principal amount of its Series 2022A 5.15% Senior Notes.

In November 2025, Southern Company used a portion of the net proceeds from the 2025 Equity Units to repurchase (i) an additional approximately $674.4 million of the remaining approximately $943.4 million aggregate principal amount outstanding of its Series 2023A Convertible Senior Notes and (ii) an additional approximately $342.0 million of the remaining approximately $1.172 billion aggregate principal amount outstanding of its Series 2024A Convertible Senior Notes. See Note 8 to the financial statements under "Equity Units" for additional information.

In December 2025, Southern Company settled at maturity the remaining approximately $269.1 million outstanding of its Series 2023A Convertible Senior Notes. See Note 8 to the financial statements under "Convertible Senior Notes" for additional information.

Subsequent to December 31, 2025, Southern Company redeemed all $1.25 billion aggregate principal amount of its Series 2020B 4.00% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due January 15, 2051.

Alabama Power

During 2025, a subsidiary of Alabama Power borrowed an additional approximately $5 million under a $20 million fixed rate bank loan entered into in December 2023 with a maturity date of December 31, 2030. The aggregate amount outstanding under this loan at December 31, 2025 was approximately $20 million.

In March 2025, Alabama Power issued $500 million aggregate principal amount of Series 2025A 5.10% Senior Notes due April 2, 2035.

In April 2025, Alabama Power repaid at maturity $250 million aggregate principal amount of its Series 2015B 2.80% Senior Notes.

In June 2025, Alabama Power issued $100 million aggregate principal amount of Series 2025B Floating Rate Senior Notes due August 15, 2075.

In July 2025, a subsidiary of Alabama Power repaid $1 million under a $15 million credit line entered into in December 2024 with a maturity date of December 11, 2026.

In September 2025, Alabama Power issued $500 million aggregate principal amount of Series 2025C 4.30% Senior Notes due March 15, 2031.

Georgia Power

In March 2025, Georgia Power issued $400 million aggregate principal amount of Series 2025A Floating Rate Senior Notes due September 15, 2026, $500 million aggregate principal amount of Series 2025B 4.85% Senior Notes due March 15, 2031, and $700 million aggregate principal amount of Series 2025C 5.20% Senior Notes due March 15, 2035.

In May 2025, Georgia Power repaid at maturity $700 million aggregate principal amount of its Series 2023C Floating Rate Senior Notes.

Also in May 2025, Georgia Power entered into a $200 million short-term floating rate bank loan bearing interest based on term SOFR.

In June 2025, Georgia Power extended both of its short-term floating rate bank loans totaling $400 million to long-term term loans, which mature in June 2026.

In July 2025, Georgia Power repaid at maturity its obligations with respect to $45 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), First Series 1995.

In September 2025, Georgia Power issued $250 million aggregate principal amount of additional Series 2025B 4.85% Senior Notes due March 15, 2031, $750 million aggregate principal amount of Series 2025D 4.00% Senior Notes due October 1, 2028, and $500 million aggregate principal amount of Series 2025E 5.50% Senior Notes due October 1, 2055.

Mississippi Power

In March 2025, Mississippi Power issued $50 million aggregate principal amount of Series 2025A 5.01% Senior Notes due March 15, 2030 and $50 million aggregate principal amount of Series 2025B 6.03% Senior Notes due March 15, 2055.

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In July 2025, Mississippi Power repaid at maturity its obligations with respect to approximately $11 million aggregate principal amount of Mississippi Business Finance Corporation Solid Waste Disposal Facilities Revenue Bonds, Series 1995 (Mississippi Power Company Project).

Southern Power

In September 2025, Southern Power issued $550 million aggregate principal amount of Series 2025A 4.25% Senior Notes due October 1, 2030 and $550 million aggregate principal amount of Series 2025B 4.90% Senior Notes due October 1, 2035.

In October 2025, Southern Power redeemed all $500 million aggregate principal amount of its Series 2015C 4.15% Senior Notes due December 1, 2025.

In December 2025, Southern Power redeemed all $400 million aggregate principal amount of its Series 2021A 0.90% Senior Notes due January 15, 2026.

Southern Company Gas

In August 2025, Nicor Gas repaid at maturity $50 million aggregate principal amount of its 1.42% Series First Mortgage Bonds.

In September 2025, Southern Company Gas Capital issued $425 million aggregate principal amount of Series 2025A 4.05% Senior Notes due September 15, 2028 and $425 million aggregate principal amount of Series 2025B 5.10% Senior Notes due September 15, 2035, both guaranteed by Southern Company Gas.

In October 2025, Nicor Gas issued in a private placement $25 million aggregate principal amount of 4.17% Series First Mortgage Bonds due October 1, 2028 and $75 million aggregate principal amount of 4.92% Series First Mortgage Bonds due October 1, 2035. In December 2025, pursuant to the same agreement, Nicor Gas issued in a private placement $50 million aggregate principal amount of 5.59% Series First Mortgage Bonds due December 15, 2055 and $50 million aggregate principal amount of 5.69% Series First Mortgage Bonds due December 15, 2065.

In November 2025, Southern Company Gas Capital repaid at maturity $250 million aggregate principal amount of its 3.875% Senior Notes.

Credit Rating Risk

At December 31, 2025, 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 equipment purchases related to construction of facilities.

The maximum potential collateral requirements under these contracts at December 31, 2025 were as follows:

Credit Ratings	Southern<br><br>Company(*)		Alabama<br><br>Power		Georgia<br><br>Power		Mississippi<br><br>Power		Southern<br><br>Power(*)		Southern<br><br>Company<br><br>Gas
	(in millions)
At BBB and/or Baa2	$	32	$	1	$	—	$	—	$	30	$	—
At BBB- and/or Baa3	445		2		36		—		406		—
At BB+ and/or Ba1 or below	3,774		424		2,503		278		1,347		29

(*)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, 2025.

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

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS

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 22, 2025, Fitch revised the ratings outlook of Georgia Power to stable from positive.

On September 23, 2025, Moody's revised the ratings outlook of Southern Company to negative from stable and the ratings outlook of Georgia Power to stable from positive.

Market Price Risk

The Registrants had no material change in market risk exposure for the year ended December 31, 2025 when compared to the year ended December 31, 2024. 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, 2025 for the applicable Registrants:

At December 31, 2025	Southern<br><br>Company(*)			Alabama<br>Power			Georgia<br>Power			Mississippi<br>Power			Southern Company<br>Gas
	(in millions, except percentages)
Long-term variable interest rate exposure	$	5,318		$	1,141		$	1,584		$	58		$	500
Weighted average interest rate on long-term variable interest rate exposure	4.31		%	3.05		%	3.60		%	2.75		%	4.28		%
Impact on annualized interest expense of 100 basis point change in interest rates	$	53		$	11		$	16		$	1		$	5

(*)Includes $2.0 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, 2025 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.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS

Changes in fair value of energy-related derivative contracts for Southern Company and Southern Company Gas for the years ended December 31, 2025 and 2024 are provided in the table below. At December 31, 2025 and 2024, 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<br><br>Company(a)		Southern<br><br>Company Gas(a)
	(in millions)
Contracts outstanding at December 31, 2023, assets (liabilities), net	$	(304)	$	(49)
Contracts realized or settled	211		7
Current period changes(b)	54		52
Contracts outstanding at December 31, 2024, assets (liabilities), net	(39)		10
Contracts realized or settled	9		(13)
Current period changes(b)	(18)		(7)
Contracts outstanding at December 31, 2025, assets (liabilities), net	$	(48)	$	(10)

(a)Excludes cash collateral held on deposit in broker margin accounts of $33 million, $17 million, and $62 million at December 31, 2025, 2024, and 2023, 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 at December 31, 2025 and 2024 for Southern Company and Southern Company Gas were as follows:

	Southern Company	Southern Company Gas
	mmBtu Volume (in millions)
At December 31, 2025:
Commodity – Natural gas swaps	274	—
Commodity – Natural gas options	157	63
Total hedge volume	431	63
At December 31, 2024:
Commodity – Natural gas swaps	255	—
Commodity – Natural gas options	176	83
Total hedge volume	431	83

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 72 million mmBtu and short natural gas positions of 9 million mmBtu at December 31, 2025 and the net of long natural gas positions of 90 million mmBtu and short natural gas positions of 7 million mmBtu at December 31, 2024.

For the Southern Company system, the weighted average swap contract cost per mmBtu was approximately $0.11 per mmBtu below market prices at December 31, 2025 and was approximately $0.15 per mmBtu below market prices at December 31, 2024. 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.

The Registrants use OTC 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

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS

measurements. The maturities of the energy-related derivative contracts for Southern Company and Southern Company Gas at December 31, 2025 were as follows:

	Fair Value Measurements of Contracts at
	December 31, 2025
	Total<br>Fair Value			Maturity
			2026			2027 – 2028			2029 – 2030			Thereafter
	(in millions)
Southern Company
Level 1(a)	$	(7)		$	(7)		$	—		$	—		$	—
Level 2(b)	(41)			(40)			(3)			2			—
Southern Company total(c)	$	(48)		$	(47)		$	(3)		$	2		$	—
Southern Company Gas
Level 1(a)	$	(7)		$	(7)		$	—		$	—		$	—
Level 2(b)	(3)			(3)			—			—			—
Southern Company Gas total(c)	$	(10)		$	(10)		$	—		$	—		$	—

(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 $33 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 generally enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's, S&P, or Fitch 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. The traditional electric operating companies and Southern Power have received collateral or acceptable substitute guarantees as financial security from counterparties to contracts for certain data centers and other large load customers as described in FUTURE EARNINGS POTENTIAL – "General" herein and PPAs as described in FUTURE EARNINGS POTENTIAL – "Southern Power's Power Sales Agreements" herein. Southern Company Gas' exposure to concentrations of credit risk is discussed herein.

Southern Company Gas

Gas Distribution Operations

Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of the 14 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 2025, the four largest Marketers based on customer count, which includes SouthStar, accounted for 19% of Southern Company Gas' operating revenues and 22% 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.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS

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:
Report of Independent Registered Public Accounting Firm	II-69
Consolidated Statements of Income for the Years Ended December 31,2025, 2024, and 2023	II-71
Consolidated Statements of Comprehensive Income for the Years Ended December 31,2025, 2024, and 2023	II-72
Consolidated Statements of Cash Flows for the Years Ended December 31,2025, 2024, and 2023	II-73
Consolidated Balance Sheets at December 31,2025 and 2024	II-74
Consolidated Statements of Stockholders' Equity for the Years Ended December 31,2025, 2024, and 2023	II-76
Alabama Power:
Report of Independent Registered Public Accounting Firm	II-77
Statements of Income for the Years Ended December 31,2025, 2024, and 2023	II-79
Statements of Comprehensive Income for the Years Ended December 31,2025, 2024, and 2023	II-79
Statements of Cash Flows for the Years Ended December 31,2025, 2024, and 2023	II-80
Balance Sheets at December 31,2025 and 2024	II-81
Statements of Common Stockholder's Equity for the Years Ended December 31,2025, 2024, and 2023	II-83
Georgia Power:
Report of Independent Registered Public Accounting Firm	II-84
Statements of Income for the Years Ended December 31,2025, 2024, and 2023	II-86
Statements of Comprehensive Income for the Years Ended December 31,2025, 2024, and 2023	II-86
Statements of Cash Flows for the Years Ended December 31,2025, 2024, and 2023	II-87
Balance Sheets at December 31,2025 and 2024	II-88
Statements of Common Stockholder's Equity for the Years Ended December 31,2025, 2024, and 2023	II-90
Mississippi Power:
Report of Independent Registered Public Accounting Firm	II-91
Statements of Income for the Years Ended December 31,2025, 2024, and 2023	II-93
Statements of Comprehensive Income for the Years Ended December 31,2025, 2024, and 2023	II-93
Statements of Cash Flows for the Years Ended December 31,2025, 2024, and 2023	II-94
Balance Sheets at December 31,2025 and 2024	II-95
Statements of Common Stockholder's Equity for the Years Ended December 31,2025, 2024, and 2023	II-97
Southern Power and Subsidiary Companies:
Report of Independent Registered Public Accounting Firm	II-98
Consolidated Statements of Income for the Years Ended December 31,2025, 2024, and 2023	II-100
Consolidated Statements of Comprehensive Income for the Years Ended December 31,2025, 2024, and 2023	II-100
Consolidated Statements of Cash Flows for the Years Ended December 31,2025, 2024, and 2023	II-101
Consolidated Balance Sheets at December 31,2025 and 2024	II-102
Consolidated Statements of Stockholders' Equity for the Years Ended December 31,2025, 2024, and 2023	II-104
Southern Company Gas and Subsidiary Companies:
Report of Independent Registered Public Accounting Firm	II-105
Consolidated Statements of Income for the Years Ended December 31,2025, 2024, and 2023	II-109
Consolidated Statements of Comprehensive Income for the Years Ended December 31,2025, 2024, and 2023	II-109
Consolidated Statements of Cash Flows for the Years Ended December 31,2025, 2024, and 2023	II-110
Consolidated Balance Sheets at December 31,2025 and 2024	II-111
Consolidated Statements of Common Stockholder's Equity for the Years Ended December 31,2025, 2024, and 2023	II-113
Combined Notes to Financial Statements	II-114

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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, 2025 and 2024, 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, 2025, 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, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, 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, 2025, 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.

Critical Audit Matter

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,

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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

Critical Audit Matter Description

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.

How the Critical Audit Matter Was Addressed in the Audit

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 certain regulatory assets or liabilities.

•We read and evaluated relevant regulatory orders issued 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.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

February 18, 2026

We have served as Southern Company's auditor since 2002.

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CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2025, 2024, and 2023

Southern Company and Subsidiary Companies

	2025		2024		2023
	(in millions)
Operating Revenues:
Retail electric revenues	$	19,331	$	17,790	$	16,343
Wholesale electric revenues	2,941		2,431		2,467
Other electric revenues	953		896		792
Natural gas revenues	5,044		4,456		4,702
Other revenues	1,284		1,151		949
Total operating revenues	29,553		26,724		25,253
Operating Expenses:
Fuel	4,897		4,096		4,365
Purchased power	980		883		883
Cost of natural gas	1,599		1,196		1,644
Cost of other sales	687		668		560
Other operations and maintenance	7,066		6,518		6,025
Depreciation and amortization	5,501		4,755		4,525
Taxes other than income taxes	1,538		1,540		1,425
Total operating expenses	22,268		19,656		19,427
Operating Income	7,285		7,068		5,826
Other Income and (Expense):
Allowance for equity funds used during construction	340		235		268
Earnings from equity method investments	112		139		144
Interest expense, net of amounts capitalized	(3,238)		(2,743)		(2,446)
Other income (expense), net	500		530		553
Total other income and (expense)	(2,286)		(1,839)		(1,481)
Earnings Before Income Taxes	4,999		5,229		4,345
Income taxes	828		969		496
Consolidated Net Income	4,171		4,260		3,849
Net loss attributable to noncontrolling interests	(170)		(141)		(127)
Consolidated Net Income Attributable to Southern Company	$	4,341	$	4,401	$	3,976
Common Stock Data:
Earnings per share —
Basic	$	3.94	$	4.02	$	3.64
Diluted	3.92		3.99		3.62
Average number of shares of common stock outstanding — (in millions)
Basic	1,103		1,096		1,092
Diluted	1,109		1,102		1,098

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

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2025, 2024, and 2023

Southern Company and Subsidiary Companies

	2025		2024		2023
	(in millions)
Consolidated Net Income	$	4,171	$	4,260	$	3,849
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of<br><br>$8, $(2), and $(17), respectively	26		(5)		(41)
Reclassification adjustment for amounts included in net income,<br><br>net of tax of $(10), $28, and $27, respectively	(33)		80		69
Pension and other postretirement benefit plans:
Benefit plan net gain (loss),<br><br>net of tax of $4, $10, and $(14), respectively	10		23		(39)
Reclassification adjustment for amounts included in net income,<br><br>net of tax of $—, $—, and $—, respectively	—		1		1
Total other comprehensive income (loss)	3		99		(10)
Comprehensive loss attributable to noncontrolling interests	(170)		(141)		(127)
Consolidated Comprehensive Income Attributable to Southern Company	$	4,344	$	4,500	$	3,966

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2025, 2024, and 2023

Southern Company and Subsidiary Companies

	2025		2024		2023
	(in millions)
Operating Activities:
Consolidated net income	$	4,171	$	4,260	$	3,849
Adjustments to reconcile consolidated net income<br>   to net cash provided from operating activities —
Depreciation and amortization, total	6,030		5,266		4,986
Deferred income taxes	618		626		416
Allowance for equity funds used during construction	(340)		(235)		(268)
Pension, postretirement, and other employee benefits	(579)		(556)		(527)
Settlement of asset retirement obligations	(634)		(566)		(617)
Storm damage and reliability reserve accruals	236		163		124
Stock based compensation expense	136		132		137
Loss on extinguishment of debt	252		—		—
Retail fuel cost under recovery – long-term	(176)		(32)		(206)
Storm damage cost recovery – long-term	(275)		(631)		—
Other, net	(36)		(60)		(206)
Changes in certain current assets and liabilities —
-Receivables	(124)		(372)		482
-Retail fuel cost under recovery	645		984		686
-Fossil fuel for generation	68		140		(368)
-Materials and supplies	(24)		(189)		(345)
-Natural gas cost under recovery	—		—		108
-Other current assets	47		(47)		(106)
-Accounts payable	(290)		492		(863)
-Accrued interest	125		30		42
-Accrued taxes	(36)		206		23
-Customer refunds	(75)		83		(157)
-Natural gas cost over recovery	(36)		(21)		214
-Other current liabilities	99		115		149
Net cash provided from operating activities	9,802		9,788		7,553
Investing Activities:
Property additions	(12,737)		(8,955)		(9,095)
Business acquisition	(635)		—		—
Nuclear decommissioning trust fund purchases	(1,702)		(1,551)		(1,142)
Nuclear decommissioning trust fund sales	1,685		1,535		1,121
Proceeds from dispositions	1		369		164
Cost of removal, net of salvage	(655)		(632)		(592)
Change in construction payables, net	301		106		18
Payments pursuant to LTSAs	(159)		(108)		(99)
Other investing activities	(58)		(164)		(43)
Net cash used for investing activities	(13,959)		(9,400)		(9,668)
Financing Activities:
Increase (decrease) in notes payable, net	(414)		(648)		973
Proceeds —
Long-term debt	12,470		6,159		8,972
Short-term borrowings	200		700		350
Common stock	1,623		143		36
Redemptions and repurchases —
Long-term debt	(5,464)		(2,222)		(4,294)
Short-term borrowings	—		(1,020)		(1,630)
Distributions to noncontrolling interests	(200)		(185)		(234)
Purchase of membership interests from noncontrolling interests	(286)		—		—
Payment of common stock dividends	(3,015)		(2,954)		(3,035)
Other financing activities	(218)		(181)		(139)
Net cash provided from (used for) financing activities	4,696		(208)		999
Net Change in Cash, Cash Equivalents, and Restricted Cash	539		180		(1,116)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	1,101		921		2,037
Cash, Cash Equivalents, and Restricted Cash at End of Year	$	1,640	$	1,101	$	921
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $140, $103, and $132 capitalized, respectively)	$	2,692	$	2,538	$	2,184
Income taxes, net (excludes credit transfers)	284		176		132
Noncash transactions —
Accrued property additions at year-end	1,473		1,199		1,027
LTSA credits utilized from the sale of spare parts	6		13		23
Issuance of common stock under dividend reinvestment plan	222		179		—

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

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CONSOLIDATED BALANCE SHEETS

At December 31, 2025 and 2024

Southern Company and Subsidiary Companies

Assets	2025		2024
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,639	$	1,070
Receivables —
Customer accounts	2,251		2,228
Unbilled revenues	931		825
Under recovered fuel clause revenues	316		713
Other accounts and notes	655		597
Accumulated provision for uncollectible accounts	(84)		(74)
Materials and supplies	2,202		2,178
Fossil fuel for generation	735		803
Natural gas for sale	396		388
Prepaid expenses	327		294
Assets from risk management activities, net of collateral	63		39
Regulatory assets – asset retirement obligations	353		353
Other regulatory assets	709		804
Other current assets	424		476
Total current assets	10,917		10,694
Property, Plant, and Equipment:
In service	146,114		137,143
Less: Accumulated depreciation	43,483		40,126
Plant in service, net of depreciation	102,631		97,017
Other utility plant, net	307		410
Nuclear fuel, at amortized cost	897		873
Construction work in progress	10,534		6,389
Total property, plant, and equipment	114,369		104,689
Other Property and Investments:
Goodwill	5,161		5,161
Nuclear decommissioning trusts, at fair value	2,947		2,621
Equity investments in unconsolidated subsidiaries	1,318		1,416
Other intangible assets, net of amortization of $444 and $412, respectively	300		332
Miscellaneous property and investments	714		668
Total other property and investments	10,440		10,198
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,358		1,386
Deferred charges related to income taxes	948		889
Prepaid pension costs	3,257		2,674
Unamortized loss on reacquired debt	187		203
Deferred under recovered retail fuel clause revenues	252		485
Regulatory assets – asset retirement obligations, deferred	5,129		5,458
Other regulatory assets, deferred	7,427		7,037
Other deferred charges and assets	1,436		1,467
Total deferred charges and other assets	19,994		19,599
Total Assets	$	155,720	$	145,180

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

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CONSOLIDATED BALANCE SHEETS

At December 31, 2025 and 2024

Southern Company and Subsidiary Companies

Liabilities and Stockholders' Equity	2025		2024
	(in millions)
Current Liabilities:
Securities due within one year	$	6,220	$	4,718
Notes payable	722		1,338
Accounts payable	3,710		3,701
Customer deposits	475		486
Accrued taxes —
Accrued income taxes	22		57
Other accrued taxes	982		997
Accrued interest	807		682
Accrued compensation	1,418		1,261
Asset retirement obligations	662		731
Liabilities from risk management activities, net of collateral	118		160
Operating lease obligations	197		200
Natural gas cost over recovery	158		193
Other regulatory liabilities	240		369
Other current liabilities	1,157		1,100
Total current liabilities	16,888		15,993
Long-Term Debt	65,649		58,768
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	12,133		11,730
Deferred credits related to income taxes	4,712		4,434
Accumulated deferred ITCs	2,002		2,056
Employee benefit obligations	980		1,011
Operating lease obligations, deferred	1,287		1,253
Asset retirement obligations, deferred	8,939		9,203
Other cost of removal obligations	2,036		2,016
Other regulatory liabilities, deferred	722		692
Other deferred credits and liabilities	1,505		1,350
Total deferred credits and other liabilities	34,316		33,745
Total Liabilities	116,853		108,506
Common Stockholders' Equity:
Common stock, par value $5 per share (Authorized - 1.5 billion shares)	5,554		5,446
(Issued - 1.1 billion shares; Treasury - 1.0 million shares)
Paid-in capital	15,740		14,149
Treasury, at cost	(59)		(59)
Retained earnings	14,856		13,750
Accumulated other comprehensive loss	(75)		(78)
Total common stockholders' equity	36,016		33,208
Noncontrolling interests	2,851		3,466
Total Stockholders' Equity (See accompanying statements)	38,867		36,674
Total Liabilities and Stockholders' Equity	$	155,720	$	145,180
Commitments and Contingent Matters (See notes)

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

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

For the Years Ended December 31, 2025, 2024, and 2023

Southern Company and Subsidiary Companies

	Southern Company Common Stockholders' Equity
	Number of Common Shares		Common Stock								Accumulated<br>Other<br>Comprehensive Income <br>(Loss)			Noncontrolling<br>Interests
	Issued	Treasury	Par Value		Paid-In Capital		Treasury		Retained Earnings				Total
	(in millions)
Balance at December 31, 2022	1,090	(1)	$	5,417	$	13,673	$	(53)	$	11,538	$	(167)		$	4,124	$	34,532
Consolidated net income (loss)	—	—	—		—		—		3,976		—			(127)		3,849
Other comprehensive income (loss)	—	—	—		—		—		—		(10)			—		(10)
Stock issued	2	—	6		30		—		—		—			—		36
Stock-based compensation	—	—	—		73		—		—		—			—		73
Cash dividends of $2.7800 per share	—	—	—		—		—		(3,035)		—			—		(3,035)
Capital contributions from<br><br>noncontrolling interests	—	—	—		—		—		—		—			21		21
Distributions to<br>   noncontrolling interests	—	—	—		—		—		—		—			(236)		(236)
Other	—	—	—		(1)		(6)		3		—			(1)		(5)
Balance at December 31, 2023	1,092	(1)	5,423		13,775		(59)		12,482		(177)			3,781		35,225
Consolidated net income (loss)	—	—	—		—		—		4,401		—			(141)		4,260
Other comprehensive income	—	—	—		—		—		—		99			—		99
Stock issued	6	—	23		299		—		—		—			—		322
Stock-based compensation	—	—	—		56		—		—		—			—		56
Dividends of $2.8600 per share	—	—	—		—		—		(3,133)		—			—		(3,133)
Capital contributions from<br><br>noncontrolling interests	—	—	—		—		—		—		—			11		11
Distributions to <br>   noncontrolling interests	—	—	—		—		—		—		—			(185)		(185)
Other	—	—	—		19		—		—		—			—		19
Balance at December 31, 2024	1,098	(1)	5,446		14,149		(59)		13,750		(78)			3,466		36,674
Consolidated net income (loss)	—	—	—		—		—		4,341		—			(170)		4,171
Other comprehensive income	—	—	—		—		—		—		3			—		3
Issuance of equity units(*)	—	—	—		(173)		—		—		—			—		(173)
Stock issued	22	—	107		1,738		—		—		—			—		1,845
Stock-based compensation	—	—	—		48		—		—		—			—		48
Dividends of $2.9400 per share	—	—	—		—		—		(3,237)		—			—		(3,237)
Capital contributions from<br><br>noncontrolling interests	—	—	—		—		—		—		—			23		23
Distributions to <br>   noncontrolling interests	—	—	—		—		—		—		—			(202)		(202)
Purchase of membership interests<br>   from noncontrolling interests	—	—	—		(16)		—		—		—			(267)		(283)
Other	—	—	1		(6)		—		2		—			1		(2)
Balance at December 31, 2025	1,120	(1)	$	5,554	$	15,740	$	(59)	$	14,856	$	(75)		$	2,851	$	38,867

(*) See Note 8 under "Equity Units" for additional information.

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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and the Board of Directors of Alabama Power Company

Opinion on the Financial Statements

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, 2025 and 2024, 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, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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.

Critical Audit Matter

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

Critical Audit Matter Description

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.

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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.

How the Critical Audit Matter Was Addressed in the Audit

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 certain regulatory assets or liabilities.

•We read and evaluated relevant regulatory orders issued 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.

/s/ Deloitte & Touche LLP

Birmingham, Alabama

February 18, 2026

We have served as Alabama Power's auditor since 2002.

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STATEMENTS OF INCOME

For the Years Ended December 31, 2025, 2024, and 2023

Alabama Power Company

	2025		2024		2023
	(in millions)
Operating Revenues:
Retail revenues	$	7,136	$	6,639	$	6,159
Wholesale revenues, non-affiliates	449		337		424
Wholesale revenues, affiliates	188		139		60
Other revenues	462		439		407
Total operating revenues	8,235		7,554		7,050
Operating Expenses:
Fuel	1,524		1,358		1,299
Purchased power, non-affiliates	235		199		253
Purchased power, affiliates	273		175		251
Other operations and maintenance	2,026		1,895		1,769
Depreciation and amortization	1,510		1,459		1,401
Taxes other than income taxes	498		471		442
Total operating expenses	6,066		5,557		5,415
Operating Income	2,169		1,997		1,635
Other Income and (Expense):
Allowance for equity funds used during construction	69		57		82
Interest expense, net of amounts capitalized	(465)		(448)		(425)
Other income (expense), net	168		157		159
Total other income and (expense)	(228)		(234)		(184)
Earnings Before Income Taxes	1,941		1,763		1,451
Income taxes	425		360		81
Net Income	$	1,516	$	1,403	$	1,370

STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2025, 2024, and 2023

Alabama Power Company

	2025		2024		2023
	(in millions)
Net Income	$	1,516	$	1,403	$	1,370
Other comprehensive income:
Qualifying hedges:
Reclassification adjustment for amounts included in net income,<br><br>net of tax of $1, $1, and $1, respectively	2		2		2
Total other comprehensive income	2		2		2
Comprehensive Income	$	1,518	$	1,405	$	1,372

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

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STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2025, 2024, and 2023

Alabama Power Company

	2025		2024		2023
	(in millions)
Operating Activities:
Net income	$	1,516	$	1,403	$	1,370
Adjustments to reconcile net income<br>   to net cash provided from operating activities —
Depreciation and amortization, total	1,654		1,608		1,554
Deferred income taxes	220		(55)		(242)
Allowance for equity funds used during construction	(69)		(57)		(82)
Pension, postretirement, and other employee benefits	(211)		(213)		(204)
Settlement of asset retirement obligations	(269)		(254)		(270)
Natural disaster reserve and reliability reserve accruals	179		96		70
Retail fuel cost under recovery – long-term	(146)		—		—
Other, net	(55)		103		4
Changes in certain current assets and liabilities —
-Receivables	(34)		(32)		(24)
-Fossil fuel stock	36		55		(165)
-Materials and supplies	(29)		(57)		(105)
-Retail fuel cost under recovery	—		246		376
-Other current assets	18		(32)		(20)
-Accounts payable	(99)		(127)		(162)
-Customer refunds	(108)		87		(39)
-Other current liabilities	(31)		124		18
Net cash provided from operating activities	2,572		2,895		2,079
Investing Activities:
Property additions	(1,935)		(1,881)		(2,022)
Business acquisition	(635)		—		—
Nuclear decommissioning trust fund purchases	(564)		(593)		(301)
Nuclear decommissioning trust fund sales	564		592		300
Cost of removal net of salvage	(175)		(166)		(178)
Change in construction payables, net of joint owner portion	(48)		10		(44)
Other investing activities	(21)		51		49
Net cash used for investing activities	(2,814)		(1,987)		(2,196)
Financing Activities:
Increase (decrease) in notes payable, net	—		(40)		40
Proceeds —
Senior notes	1,100		—		500
Revenue bonds	—		—		326
Short-term borrowings	—		50		—
Other long-term debt	5		8		29
Redemptions and repurchases —
Senior notes	(250)		—		(300)
Revenue bonds	—		(21)		—
Short-term borrowings	—		(50)		—
Other long-term debt	(1)		(22)		—
Capital contributions from parent company	601		527		407
Payment of common stock dividends	(1,219)		(1,182)		(1,141)
Other financing activities	(13)		(2)		(22)
Net cash provided from (used for) financing activities	223		(732)		(161)
Net Change in Cash, Cash Equivalents, and Restricted Cash	(19)		176		(278)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	585		409		687
Cash, Cash Equivalents, and Restricted Cash at End of Year	$	566	$	585	$	409
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $20, $18, and $27 capitalized, respectively)	$	431	$	428	$	397
Income taxes, net	243		387		315
Noncash transactions — Accrued property additions at year-end	100		148		138

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

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BALANCE SHEETS

At December 31, 2025 and 2024

Alabama Power Company

Assets	2025		2024
	(in millions)
Current Assets:
Cash and cash equivalents	$	566	$	585
Receivables —
Customer accounts	470		512
Unbilled revenues	189		187
Affiliated	126		91
Other accounts and notes	113		126
Accumulated provision for uncollectible accounts	(23)		(22)
Fossil fuel stock	303		339
Materials and supplies	732		699
Prepaid expenses	86		63
Other regulatory assets	344		332
Other current assets	80		79
Total current assets	2,986		2,991
Property, Plant, and Equipment:
In service	38,915		36,501
Less: Accumulated provision for depreciation	12,816		11,741
Plant in service, net of depreciation	26,099		24,760
Other utility plant, net	307		410
Nuclear fuel, at amortized cost	290		262
Construction work in progress	1,441		1,377
Total property, plant, and equipment	28,137		26,809
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,542		1,386
Equity investments in unconsolidated subsidiaries	48		48
Miscellaneous property and investments	123		129
Total other property and investments	1,713		1,563
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	86		84
Deferred charges related to income taxes	261		264
Prepaid pension and other postretirement benefit costs	1,016		841
Regulatory assets – asset retirement obligations	1,518		1,780
Other regulatory assets, deferred	1,982		1,815
Other deferred charges and assets	425		391
Total deferred charges and other assets	5,288		5,175
Total Assets	$	38,124	$	36,538

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

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BALANCE SHEETS

At December 31, 2025 and 2024

Alabama Power Company

Liabilities and Stockholder's Equity	2025		2024
	(in millions)
Current Liabilities:
Securities due within one year	$	625	$	655
Accounts payable —
Affiliated	294		299
Other	576		625
Customer deposits	113		113
Accrued taxes	105		78
Accrued interest	134		120
Accrued compensation	275		240
Asset retirement obligations	256		364
Other regulatory liabilities	89		165
Other current liabilities	135		219
Total current liabilities	2,602		2,878
Long-Term Debt	11,388		10,499
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	4,209		4,178
Deferred credits related to income taxes	1,585		1,398
Accumulated deferred ITCs	115		113
Employee benefit obligations	152		148
Operating lease obligations	78		76
Asset retirement obligations, deferred	3,423		3,694
Other regulatory liabilities, deferred	252		271
Other deferred credits and liabilities	326		195
Total deferred credits and other liabilities	10,140		10,073
Total Liabilities	24,130		23,450
Common Stockholder's Equity:
Common stock, par value $40 per share<br><br>(Authorized - 40 million shares; Outstanding - 31 million shares)	1,222		1,222
Paid-in capital	8,263		7,657
Retained earnings	4,512		4,214
Accumulated other comprehensive loss	(3)		(5)
Total common stockholder's equity (See accompanying statements)	13,994		13,088
Total Liabilities and Stockholder's Equity	$	38,124	$	36,538
Commitments and Contingent Matters (See notes)

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

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STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

For the Years Ended December 31, 2025, 2024, and 2023

Alabama Power Company

	Number of<br>Common<br>Shares<br>Issued	Common<br>Stock		Paid-In<br>Capital		Retained<br>Earnings		Accumulated<br>Other<br>Comprehensive<br>Income (Loss)		Total
	(in millions)
Balance at December 31, 2022	31	$	1,222	$	6,710	$	3,764	$	(9)	$	11,687
Net income	—	—		—		1,370		—		1,370
Capital contributions from parent company	—	—		415		—		—		415
Other comprehensive income	—	—		—		—		2		2
Cash dividends on common stock	—	—		—		(1,141)		—		(1,141)
Balance at December 31, 2023	31	1,222		7,125		3,993		(7)		12,333
Net income	—	—		—		1,403		—		1,403
Capital contributions from parent company	—	—		532		—		—		532
Other comprehensive income	—	—		—		—		2		2
Cash dividends on common stock	—	—		—		(1,182)		—		(1,182)
Balance at December 31, 2024	31	1,222		7,657		4,214		(5)		13,088
Net income	—	—		—		1,516		—		1,516
Capital contributions from parent company	—	—		606		—		—		606
Other comprehensive income	—	—		—		—		2		2
Cash dividends on common stock	—	—		—		(1,219)		—		(1,219)
Other	—	—		—		1		—		1
Balance at December 31, 2025	31	$	1,222	$	8,263	$	4,512	$	(3)	$	13,994

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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and the Board of Directors of Georgia Power Company

Opinion on the Financial Statements

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, 2025 and 2024, 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, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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.

Critical Audit Matter

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

Critical Audit Matter Description

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.

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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.

How the Critical Audit Matter Was Addressed in the Audit

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 certain regulatory assets or liabilities.

•We read and evaluated relevant regulatory orders issued 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.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

February 18, 2026

We have served as Georgia Power's auditor since 2002.

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STATEMENTS OF INCOME

For the Years Ended December 31, 2025, 2024, and 2023

Georgia Power Company

	2025		2024		2023
	(in millions)
Operating Revenues:
Retail revenues	$	11,110	$	10,187	$	9,222
Wholesale revenues	525		265		188
Other revenues	996		879		708
Total operating revenues	12,631		11,331		10,118
Operating Expenses:
Fuel	2,040		1,658		1,781
Purchased power, non-affiliates	659		615		517
Purchased power, affiliates	858		745		764
Other operations and maintenance	2,585		2,351		2,015
Depreciation and amortization	2,074		1,774		1,681
Taxes other than income taxes	576		647		541
Total operating expenses	8,792		7,790		7,299
Operating Income	3,839		3,541		2,819
Other Income and (Expense):
Allowance for equity funds used during construction	248		152		165
Interest expense, net of amounts capitalized	(793)		(725)		(626)
Other income (expense), net	159		178		170
Total other income and (expense)	(386)		(395)		(291)
Earnings Before Income Taxes	3,453		3,146		2,528
Income taxes	602		603		448
Net Income	$	2,851	$	2,543	$	2,080

STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2025, 2024, and 2023

Georgia Power Company

	2025		2024		2023
	(in millions)
Net Income	$	2,851	$	2,543	$	2,080
Other comprehensive income:
Qualifying hedges:
Changes in fair value, net of tax of $1, $6, and $(1), respectively	3		18		(2)
Reclassification adjustment for amounts included in net income,<br><br>net of tax of $—, $1, and $2, respectively	1		4		5
Total other comprehensive income	4		22		3
Comprehensive Income	$	2,855	$	2,565	$	2,083

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

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STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2025, 2024, and 2023

Georgia Power Company

	2025		2024		2023
	(in millions)
Operating Activities:
Net income	$	2,851	$	2,543	$	2,080
Adjustments to reconcile net income<br>   to net cash provided from operating activities —
Depreciation and amortization, total	2,376		2,080		1,914
Deferred income taxes	493		380		206
Allowance for equity funds used during construction	(248)		(152)		(165)
Pension, postretirement, and other employee benefits	(289)		(288)		(272)
Settlement of asset retirement obligations	(321)		(270)		(304)
Retail fuel cost under recovery – long-term	—		—		(157)
Storm damage cost recovery – long-term	(275)		(631)		—
Other, net	(95)		(145)		(141)
Changes in certain current assets and liabilities —
-Receivables	33		(268)		(57)
-Retail fuel cost under recovery	645		738		308
-Fossil fuel stock	22		96		(189)
-Materials and supplies	(32)		(81)		(154)
-Other current assets	(58)		(51)		(63)
-Accounts payable	(347)		633		(206)
-Accrued taxes	(125)		212		74
-Customer refunds	33		(4)		(117)
-Other current liabilities	145		1		(5)
Net cash provided from operating activities	4,808		4,793		2,752
Investing Activities:
Property additions	(7,792)		(4,816)		(4,786)
Nuclear decommissioning trust fund purchases	(1,137)		(958)		(841)
Nuclear decommissioning trust fund sales	1,122		942		821
Cost of removal, net of salvage	(324)		(336)		(279)
Change in construction payables, net of joint owner portion	358		68		50
Payments pursuant to LTSAs	(62)		(74)		(49)
Proceeds from dispositions	—		357		59
Other investing activities	(98)		(79)		(54)
Net cash used for investing activities	(7,933)		(4,896)		(5,079)
Financing Activities:
Increase (decrease) in notes payable, net	160		(811)		811
Proceeds —
Senior notes	3,100		2,117		2,450
Short-term borrowings	200		350		350
Revenue bonds	—		—		229
Redemptions and repurchases —
Senior notes	(700)		(400)		(800)
Short-term borrowings	—		(670)		(1,430)
FFB loan	(86)		(86)		(86)
Revenue bonds	(45)		—		—
Capital contributions from parent company	2,700		1,780		2,291
Payment of common stock dividends	(2,209)		(2,051)		(1,855)
Other financing activities	(54)		(83)		(38)
Net cash provided from financing activities	3,066		146		1,922
Net Change in Cash, Cash Equivalents, and Restricted Cash	(59)		43		(405)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	118		75		480
Cash, Cash Equivalents, and Restricted Cash at End of Year	$	59	$	118	$	75
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $78, $57, and $86 capitalized, respectively)	$	717	$	680	$	592
Income taxes, net (excludes credit transfers)	129		(14)		220
Noncash transactions — Accrued property additions at year-end	1,072		739		680

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

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BALANCE SHEETS

At December 31, 2025 and 2024

Georgia Power Company

Assets	2025		2024
	(in millions)
Current Assets:
Cash and cash equivalents	$	59	$	97
Receivables —
Customer accounts, net	993		985
Unbilled revenues	346		341
Under recovered retail fuel clause revenues	310		713
Joint owner accounts	195		101
Affiliated	96		65
Other accounts and notes	61		92
Fossil fuel stock	362		385
Materials and supplies	994		968
Regulatory assets – asset retirement obligations	222		222
Other regulatory assets	335		373
Other current assets	285		262
Total current assets	4,258		4,604
Property, Plant, and Equipment:
In service	59,458		55,036
Less: Accumulated provision for depreciation	15,957		14,806
Plant in service, net of depreciation	43,501		40,230
Nuclear fuel, at amortized cost	606		611
Construction work in progress	6,764		3,197
Total property, plant, and equipment	50,871		44,038
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,405		1,236
Equity investments in unconsolidated subsidiaries	40		43
Miscellaneous property and investments	231		192
Total other property and investments	1,676		1,471
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,120		1,331
Deferred charges related to income taxes	660		596
Prepaid pension costs	1,099		897
Deferred under recovered retail fuel clause revenues	212		453
Regulatory assets – asset retirement obligations, deferred	3,382		3,436
Other regulatory assets, deferred	4,032		3,814
Other deferred charges and assets	767		615
Total deferred charges and other assets	11,272		11,142
Total Assets	$	68,077	$	61,255

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

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BALANCE SHEETS

At December 31, 2025 and 2024

Georgia Power Company

Liabilities and Stockholder's Equity	2025		2024
	(in millions)
Current Liabilities:
Securities due within one year	$	1,370	$	966
Notes payable	160		200
Accounts payable —
Affiliated	992		984
Other	1,728		1,837
Customer deposits	267		256
Accrued taxes	678		803
Accrued interest	234		190
Accrued compensation	327		276
Operating lease obligations	170		169
Asset retirement obligations	360		309
Other regulatory liabilities	52		150
Other current liabilities	332		296
Total current liabilities	6,670		6,436
Long-Term Debt	20,122		17,384
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	4,811		4,385
Deferred credits related to income taxes	2,225		2,047
Accumulated deferred ITCs	354		343
Employee benefit obligations	189		205
Operating lease obligations, deferred	960		1,159
Asset retirement obligations, deferred	5,167		5,106
Other deferred credits and liabilities	545		509
Total deferred credits and other liabilities	14,251		13,754
Total Liabilities	41,043		37,574
Common Stockholder's Equity:
Common stock, without par value<br><br>(Authorized - 20 million shares; Outstanding - 9 million shares)	398		398
Paid-in capital	22,416		19,708
Retained earnings	4,204		3,562
Accumulated other comprehensive income	16		13
Total common stockholder's equity (See accompanying statements)	27,034		23,681
Total Liabilities and Stockholder's Equity	$	68,077	$	61,255
Commitments and Contingent Matters (See notes)

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

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STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

For the Years Ended December 31, 2025, 2024, and 2023

Georgia Power Company

	Number of Common Shares Issued	Common Stock		Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
	(in millions)
Balance at December 31, 2022	9	$	398	$	15,626	$	2,846	$	(12)	$	18,858
Net income	—	—		—		2,080		—		2,080
Capital contributions from parent company	—	—		2,297		—		—		2,297
Other comprehensive income	—	—		—		—		3		3
Cash dividends on common stock	—	—		—		(1,855)		—		(1,855)
Balance at December 31, 2023	9	398		17,923		3,071		(9)		21,383
Net income	—	—		—		2,543		—		2,543
Capital contributions from parent company	—	—		1,785		—		—		1,785
Other comprehensive income	—	—		—		—		22		22
Cash dividends on common stock	—	—		—		(2,051)		—		(2,051)
Other	—	—		—		(1)		—		(1)
Balance at December 31, 2024	9	398		19,708		3,562		13		23,681
Net income	—	—		—		2,851		—		2,851
Capital contributions from parent company	—	—		2,708		—		—		2,708
Other comprehensive income	—	—		—		—		4		4
Cash dividends on common stock	—	—		—		(2,209)		—		(2,209)
Other	—	—		—		—		(1)		(1)
Balance at December 31, 2025	9	$	398	$	22,416	$	4,204	$	16	$	27,034

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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and the Board of Directors of Mississippi Power Company

Opinion on the Financial Statements

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, 2025 and 2024, 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, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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.

Critical Audit Matter

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

Critical Audit Matter Description

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.

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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.

How the Critical Audit Matter Was Addressed in the Audit

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 certain regulatory assets or liabilities.

•We read and evaluated relevant regulatory orders issued 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.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

February 18, 2026

We have served as Mississippi Power's auditor since 2002.

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STATEMENTS OF INCOME

For the Years Ended December 31, 2025, 2024, and 2023

Mississippi Power Company

	2025		2024		2023
	(in millions)
Operating Revenues:
Retail revenues	$	1,085	$	965	$	963
Wholesale revenues, non-affiliates	275		228		272
Wholesale revenues, affiliates	280		218		200
Other revenues	55		52		39
Total operating revenues	1,695		1,463		1,474
Operating Expenses:
Fuel and purchased power	624		477		538
Other operations and maintenance	387		370		362
Depreciation and amortization	211		193		190
Taxes other than income taxes	139		127		124
Total operating expenses	1,361		1,167		1,214
Operating Income	334		296		260
Other Income and (Expense):
Interest expense, net of amounts capitalized	(79)		(77)		(71)
Other income (expense), net	25		27		35
Total other income and (expense)	(54)		(50)		(36)
Earnings Before Income Taxes	280		246		224
Income taxes	65		47		36
Net Income	$	215	$	199	$	188

STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2025, 2024, and 2023

Mississippi Power Company

	2025		2024		2023
	(in millions)
Net Income	$	215	$	199	$	188
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $—, $2, and $—, respectively	(1)		5		—
Total other comprehensive income (loss)	(1)		5		—
Comprehensive Income	$	214	$	204	$	188

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

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STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2025, 2024, and 2023

Mississippi Power Company

	2025		2024		2023
	(in millions)
Operating Activities:
Net income	$	215	$	199	$	188
Adjustments to reconcile net income<br>   to net cash provided from operating activities —
Depreciation and amortization, total	230		209		232
Deferred income taxes	9		16		(13)
Pension, postretirement, and other employee benefits	(20)		(21)		(20)
Settlement of asset retirement obligations	(19)		(17)		(18)
Property damage reserve and reliability reserve accruals	26		35		23
Retail fuel cost under recovery – long-term	(30)		(32)		(50)
Plant acquisition regulatory liability	36		—		—
Other, net	(12)		5		(5)
Changes in certain current assets and liabilities —
-Receivables	(3)		(14)		85
-Fossil fuel stock	10		(9)		(3)
-Materials and supplies	(2)		(13)		(9)
-Prepaid income taxes	11		(11)		—
-Other current assets	(1)		(1)		10
-Accounts payable	(13)		(10)		(81)
-Retail fuel cost over recovery	(10)		55		27
-Wholesale fuel cost over recovery	(20)		15		5
-Other current liabilities	7		—		(2)
Net cash provided from operating activities	414		406		369
Investing Activities:
Property additions	(328)		(311)		(319)
Contributions in aid of construction	58		—		—
Cost of removal net of salvage	(55)		(41)		(32)
Change in construction payables, net	(4)		—		9
Payments pursuant to LTSAs	(20)		(19)		(26)
Other investing activities	(7)		(2)		(2)
Net cash used for investing activities	(356)		(373)		(370)
Financing Activities:
Increase (decrease) in notes payable, net	(14)		14		—
Proceeds — Senior notes	100		250		100
Redemptions —
Senior notes	—		(200)		—
Revenue bonds	(11)		—		—
Capital contributions from parent company	77		68		68
Payment of common stock dividends	(194)		(188)		(185)
Other financing activities	(3)		(2)		(3)
Net cash used for financing activities	(45)		(58)		(20)
Net Change in Cash, Cash Equivalents, and Restricted Cash	13		(25)		(21)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	13		38		59
Cash, Cash Equivalents, and Restricted Cash at End of Year	$	26	$	13	$	38
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest	$	76	$	74	$	66
Income taxes, net	42		51		52
Noncash transactions — Accrued property additions at year-end	38		36		34

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

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BALANCE SHEETS

At December 31, 2025 and 2024

Mississippi Power Company

Assets	2025		2024
	(in millions)
Current Assets:
Cash and cash equivalents	$	26	$	13
Receivables —
Customer accounts, net	50		45
Unbilled revenues	44		39
Affiliated	26		33
Other accounts and notes	22		24
Fossil fuel stock	46		56
Materials and supplies	101		103
Other regulatory assets	49		43
Other current assets	10		28
Total current assets	374		384
Property, Plant, and Equipment:
In service	5,972		5,697
Less: Accumulated provision for depreciation	1,922		1,833
Plant in service, net of depreciation	4,050		3,864
Construction work in progress	238		253
Total property, plant, and equipment	4,288		4,117
Other Property and Investments	143		152
Deferred Charges and Other Assets:
Deferred charges related to income taxes	25		27
Prepaid pension costs	151		124
Deferred under recovered retail fuel clause revenues	40		32
Regulatory assets – asset retirement obligations	229		243
Other regulatory assets, deferred	255		259
Accumulated deferred income taxes	66		82
Other deferred charges and assets	66		74
Total deferred charges and other assets	832		841
Total Assets	$	5,637	$	5,494

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

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BALANCE SHEETS

At December 31, 2025 and 2024

Mississippi Power Company

Liabilities and Stockholder's Equity	2025		2024
	(in millions)
Current Liabilities:
Securities due within one year	$	66	$	12
Notes payable	—		14
Accounts payable —
Affiliated	70		68
Other	77		83
Accrued taxes	125		115
Accrued compensation	49		46
Asset retirement obligations	21		32
Over recovered retail fuel clause revenues	—		32
Other regulatory liabilities	20		5
Other current liabilities	92		95
Total current liabilities	520		502
Long-Term Debt	1,720		1,681
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	491		492
Deferred credits related to income taxes	211		219
Employee benefit obligations	67		65
Asset retirement obligations, deferred	103		116
Other cost of removal obligations	115		170
Other regulatory liabilities, deferred	141		121
Other deferred credits and liabilities	80		39
Total deferred credits and other liabilities	1,208		1,222
Total Liabilities	3,448		3,405
Common Stockholder's Equity:
Common stock, without par value<br><br>(Authorized - 50 million shares; Outstanding - 1 million shares)	38		38
Paid-in capital	4,871		4,791
Accumulated deficit	(2,724)		(2,745)
Accumulated other comprehensive income	4		5
Total common stockholder's equity (See accompanying statements)	2,189		2,089
Total Liabilities and Stockholder's Equity	$	5,637	$	5,494
Commitments and Contingent Matters (See notes)

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

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STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

For the Years Ended December 31, 2025, 2024, and 2023

Mississippi Power Company

	Number of Common Shares Issued	Common<br>Stock		Paid-In Capital		Retained Earnings (Accumulated Deficit)		Accumulated Other Comprehensive Income (Loss)		Total
	(in millions)
Balance at December 31, 2022	1	$	38	$	4,652	$	(2,759)	$	—	$	1,931
Net income	—	—		—		188		—		188
Capital contributions from parent company	—	—		69		—		—		69
Cash dividends on common stock	—	—		—		(185)		—		(185)
Balance at December 31, 2023	1	38		4,721		(2,756)		—		2,003
Net income	—	—		—		199		—		199
Capital contributions from parent company	—	—		70		—		—		70
Other comprehensive income	—	—		—		—		5		5
Cash dividends on common stock	—	—		—		(188)		—		(188)
Balance at December 31, 2024	1	38		4,791		(2,745)		5		2,089
Net income	—	—		—		215		—		215
Capital contributions from parent company	—	—		80		—		—		80
Other comprehensive income (loss)	—	—		—		—		(1)		(1)
Cash dividends on common stock	—	—		—		(194)		—		(194)
Balance at December 31, 2025	1	$	38	$	4,871	$	(2,724)	$	4	$	2,189

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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and the Board of Directors of Southern Power Company and Subsidiary Companies

Opinion on the Financial Statements

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, 2025 and 2024, 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, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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.

Critical Audit Matter

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 Note 1 (Summary of Significant Accounting Policies – Variable Interest Entities) and Note 7 (Consolidated Entities and Equity Method Investments – Southern Power – Variable Interest Entities) to the financial statements

Critical Audit Matter Description

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.

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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.

How the Critical Audit Matter Was Addressed in the Audit

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.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

February 18, 2026

We have served as Southern Power's auditor since 2002.

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CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2025, 2024, and 2023

Southern Power Company and Subsidiary Companies

	2025		2024		2023
	(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	1,743	$	1,606	$	1,597
Wholesale revenues, affiliates	437		371		537
Other revenues	18		37		55
Total operating revenues	2,198		2,014		2,189
Operating Expenses:
Fuel	676		579		706
Purchased power	122		78		116
Other operations and maintenance	528		516		473
Depreciation and amortization	843		522		504
Taxes other than income taxes	48		41		51
Gain on dispositions, net	—		—		(20)
Total operating expenses	2,217		1,736		1,830
Operating Income (Loss)	(19)		278		359
Other Income and (Expense):
Interest expense, net of amounts capitalized	(104)		(117)		(129)
Other income (expense), net	17		13		12
Total other income and (expense)	(87)		(104)		(117)
Earnings (Loss) Before Income Taxes	(106)		174		242
Income taxes (benefit)	(61)		(13)		12
Net Income (Loss)	(45)		187		230
Net loss attributable to noncontrolling interests	(170)		(141)		(127)
Net Income Attributable to Southern Power	$	125	$	328	$	357

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2025, 2024, and 2023

Southern Power Company and Subsidiary Companies

	2025		2024		2023
	(in millions)
Net Income (Loss)	$	(45)	$	187	$	230
Other comprehensive income:
Qualifying hedges:
Changes in fair value, net of tax of $14, $(10), and $(1), respectively	43		(31)		(3)
Reclassification adjustment for amounts included in net income,<br><br>net of tax of $(14), $12, and $4, respectively	(45)		39		11
Pension and other postretirement benefit plans:
Benefit plan net gain (loss),<br><br>net of tax of $1, $2, and $(2), respectively	4		7		(7)
Total other comprehensive income	2		15		1
Comprehensive loss attributable to noncontrolling interests	(170)		(141)		(127)
Comprehensive Income Attributable to Southern Power	$	127	$	343	$	358

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2025, 2024, and 2023

Southern Power Company and Subsidiary Companies

	2025		2024		2023
	(in millions)
Operating Activities:
Net income (loss)	$	(45)	$	187	$	230
Adjustments to reconcile net income<br>   to net cash provided from operating activities —
Depreciation and amortization, total	866		537		524
Deferred income taxes	(34)		(7)		16
Utilization of federal tax credit carryforward	(95)		75		332
Amortization of ITCs	(58)		(58)		(58)
Gain on dispositions, net	—		—		(20)
Other, net	13		36		28
Changes in certain current assets and liabilities —
-Receivables	40		(39)		121
-Other current assets	(19)		(22)		(22)
-Accounts payable	7		(3)		(60)
-Accrued taxes	(8)		16		(12)
-Other current liabilities	3		(14)		17
Net cash provided from operating activities	670		708		1,096
Investing Activities:
Acquisitions, net of cash acquired	—		—		(181)
Property additions	(878)		(344)		(118)
Change in construction payables	(1)		35		21
Proceeds from dispositions	—		—		59
Payments pursuant to LTSAs	(56)		(45)		(50)
Other investing activities	1		24		4
Net cash used for investing activities	(934)		(330)		(265)
Financing Activities:
Increase (decrease) in notes payable, net	140		(129)		(83)
Proceeds — Senior notes	1,100		—		—
Redemptions — Senior notes	(900)		—		(290)
Capital contributions from parent company	619		216		18
Capital contributions from noncontrolling interests	23		11		21
Distributions to noncontrolling interests	(200)		(185)		(234)
Purchase of membership interests from noncontrolling interests	(286)		—		—
Payment of common stock dividends	(279)		(262)		(252)
Other financing activities	(16)		(5)		—
Net cash provided from (used for) financing activities	201		(354)		(820)
Net Change in Cash, Cash Equivalents, and Restricted Cash	(63)		24		11
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	168		144		133
Cash, Cash Equivalents, and Restricted Cash at End of Year	$	105	$	168	$	144
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $25, $7, and $3 capitalized, respectively)	$	88	$	107	$	122
Income taxes, net (excludes credit transfers)	148		(32)		(254)
Noncash transactions —
Accrued property additions at year-end	59		84		59
LTSA credits utilized from the sale of spare parts	6		13		23

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

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CONSOLIDATED BALANCE SHEETS

At December 31, 2025 and 2024

Southern Power Company and Subsidiary Companies

Assets	2025		2024
	(in millions)
Current Assets:
Cash and cash equivalents	$	105	$	159
Receivables —
Customer accounts, net	151		122
Affiliated	35		39
Other	16		90
Materials and supplies	132		107
Other current assets	89		82
Total current assets	528		599
Property, Plant, and Equipment:
In service	15,034		14,961
Less: Accumulated provision for depreciation	5,214		4,540
Plant in service, net of depreciation	9,820		10,421
Construction work in progress	1,080		317
Total property, plant, and equipment	10,900		10,738
Other Property and Investments:
Intangible assets, net of amortization of $188 and $168, respectively	203		223
Net investment in sales-type leases	137		143
Total other property and investments	340		366
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	479		484
Prepaid LTSAs	170		234
Other deferred charges and assets	240		232
Total deferred charges and other assets	889		950
Total Assets	$	12,657	$	12,653

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

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CONSOLIDATED BALANCE SHEETS

At December 31, 2025 and 2024

Southern Power Company and Subsidiary Companies

Liabilities and Stockholders' Equity	2025		2024
	(in millions)
Current Liabilities:
Securities due within one year	$	587	$	500
Notes payable	138		—
Accounts payable —
Affiliated	88		80
Other	93		100
Accrued taxes	9		18
Accrued interest	38		26
Operating lease obligations	31		29
Other current liabilities	92		96
Total current liabilities	1,076		849
Long-Term Debt	2,353		2,180
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	579		712
Accumulated deferred ITCs	1,383		1,440
Operating lease obligations, deferred	510		511
Other deferred credits and liabilities	235		279
Total deferred credits and other liabilities	2,707		2,942
Total Liabilities	6,136		5,971
Common Stockholder's Equity:
Common stock, par value $0.01 per share<br><br>(Authorized - 1 million shares; Outstanding - 1,000 shares)	—		—
Paid-in capital	1,912		1,306
Retained earnings	1,758		1,912
Accumulated other comprehensive income (loss)	—		(2)
Total common stockholder's equity	3,670		3,216
Noncontrolling Interests	2,851		3,466
Total Stockholders' Equity (See accompanying statements)	6,521		6,682
Total Liabilities and Stockholders' Equity	$	12,657	$	12,653
Commitments and Contingent Matters (See notes)

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

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

For the Years Ended December 31, 2025, 2024, and 2023

Southern Power Company and Subsidiary Companies

	Number of Common Shares Issued	Common Stock		Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total Common Stockholder's Equity		Noncontrolling Interests		Total
	(in millions)
Balance at December 31, 2022	—	$	—	$	1,069	$	1,741	$	(18)	$	2,792	$	4,124	$	6,916
Net income (loss)	—	—		—		357		—		357		(127)		230
Capital contributions from parent<br>   company	—	—		19		—		—		19		—		19
Other comprehensive income	—	—		—		—		1		1		—		1
Cash dividends on common<br>   stock	—	—		—		(252)		—		(252)		—		(252)
Capital contributions from<br>   noncontrolling interests	—	—		—		—		—		—		21		21
Distributions to noncontrolling<br>   interests	—	—		—		—		—		—		(236)		(236)
Other	—	—		—		—		—		—		(1)		(1)
Balance at December 31, 2023	—	—		1,088		1,846		(17)		2,917		3,781		6,698
Net income (loss)	—	—		—		328		—		328		(141)		187
Capital contributions from parent<br>   company	—	—		218		—		—		218		—		218
Other comprehensive income	—	—		—		—		15		15		—		15
Cash dividends on common<br>   stock	—	—		—		(262)		—		(262)		—		(262)
Capital contributions from<br>   noncontrolling interests	—	—		—		—		—		—		11		11
Distributions to noncontrolling<br>   interests	—	—		—		—		—		—		(185)		(185)
Balance at December 31, 2024	—	—		1,306		1,912		(2)		3,216		3,466		6,682
Net income (loss)	—	—		—		125		—		125		(170)		(45)
Capital contributions from parent<br>   company	—	—		622		—		—		622		—		622
Other comprehensive income	—	—		—		—		2		2		—		2
Cash dividends on common<br>   stock	—	—		—		(279)		—		(279)		—		(279)
Capital contributions from <br>   noncontrolling interests	—	—		—		—		—		—		23		23
Distributions to noncontrolling<br>   interests	—	—		—		—		—		—		(202)		(202)
Purchase of membership interests<br><br>from noncontrolling interests(*)	—	—		(16)		—		—		(16)		(267)		(283)
Other	—	—		—		—		—		—		1		1
Balance at December 31, 2025	—	$	—	$	1,912	$	1,758	$	—	$	3,670	$	2,851	$	6,521

(*) See Note 15 under "Southern Power – Purchase of Renewable Facility Interests" for additional information.

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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and the Board of Directors of Southern Company Gas and Subsidiary Companies

Opinion on the Financial Statements

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, 2025 and 2024, 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, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, 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 $1,148 million and $1,245 million as of December 31, 2025 and December 31, 2024, respectively, and its earnings from its equity method investment in SNG of $127 million, $146 million, and $139 million for the years ended December 31, 2025, 2024, and 2023, respectively. Those statements were audited by BDO USA, P.C., 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.

Basis for Opinion

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.

Critical Audit Matter

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

Critical Audit Matter Description

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 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

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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 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.

How the Critical Audit Matter Was Addressed in the Audit

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 previously incurred Qualifying Infrastructure Plant capital investments by Nicor Gas. We also tested the effectiveness of management's controls over the initial recognition of certain regulatory assets or liabilities.

•We read and evaluated relevant regulatory orders issued 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.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

February 18, 2026

We have served as Southern Company Gas' auditor since 2016.

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Report of Independent Registered Public Accounting Firm

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, 2025 and 2024, the related consolidated statements of income, members' equity, and cash flows for each of the three years in the period ended December 31, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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.

Critical Audit Matter

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.

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Postretirement Benefits Plan – Fair Value of Investments Measured at Net Asset Value

As discussed in Note 5 to the consolidated financial statements, the fair value of postretirement benefits plan assets on December 31, 2025, was $79 million. Of this amount, $78 million represents the fair value of investments measured at net asset value (NAV).

We identified the assessment of the postretirement benefits plan fair value of investments measured at NAV as a critical audit matter. Estimating the fair value requires management to make certain determination of unobservable inputs. Auditing these elements involved subjective auditor judgment due to the nature and extent of audit effort required, including the extent of specialized skills or knowledge needed to assess sufficiency of audit evidence.

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.

•Utilizing 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 5, 2026

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CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2025, 2024, and 2023

Southern Company Gas and Subsidiary Companies

	2025		2024		2023
	(in millions)
Operating Revenues:
Natural gas revenues (includes revenue taxes of<br><br>$136, $115, and $133, respectively)	$	5,044	$	4,456	$	4,702
Total operating revenues	5,044		4,456		4,702
Operating Expenses:
Cost of natural gas	1,599		1,196		1,644
Other operations and maintenance	1,297		1,235		1,187
Depreciation and amortization	708		650		582
Taxes other than income taxes	272		248		262
Estimated loss on regulatory disallowance	63		—		88
Total operating expenses	3,939		3,329		3,763
Operating Income	1,105		1,127		939
Other Income and (Expense):
Earnings from equity method investments	127		146		140
Interest expense, net of amounts capitalized	(377)		(341)		(310)
Other income (expense), net	59		66		57
Total other income and (expense)	(191)		(129)		(113)
Earnings Before Income Taxes	914		998		826
Income taxes	182		258		211
Net Income	$	732	$	740	$	615

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2025, 2024, and 2023

Southern Company Gas and Subsidiary Companies

	2025		2024		2023
	(in millions)
Net Income	$	732	$	740	$	615
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(1), $(3), and $(18), respectively	(3)		(9)		(45)
Reclassification adjustment for amounts included in net income,<br><br>net of tax of $1, $12, and $19, respectively	3		30		46
Pension and other postretirement benefit plans:
Benefit plan net gain (loss),<br><br>net of tax of $2, $5, and $(7), respectively	4		11		(15)
Reclassification adjustment for amounts included in net income,<br><br>net of tax of $(1), $(1), and $—, respectively	(1)		—		(1)
Total other comprehensive income (loss)	3		32		(15)
Comprehensive Income	$	735	$	772	$	600

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2025, 2024, and 2023

Southern Company Gas and Subsidiary Companies

	2025		2024		2023
	(in millions)
Operating Activities:
Consolidated net income	$	732	$	740	$	615
Adjustments to reconcile net income to net cash<br>   provided from operating activities —
Depreciation and amortization, total	701		643		582
Deferred income taxes	122		132		126
Estimated loss on regulatory disallowance	63		—		96
Other, net	41		3		(74)
Changes in certain current assets and liabilities —
-Receivables	(189)		28		431
-Natural gas for sale, net of temporary LIFO liquidation	(8)		32		19
-Prepaid income taxes	12		63		(11)
-Natural gas cost under recovery	—		—		108
-Other current assets	41		(52)		(17)
-Accounts payable	75		(6)		(276)
-Natural gas cost over recovery	(36)		(21)		214
-Other current liabilities	63		(10)		(51)
Net cash provided from operating activities	1,617		1,552		1,762
Investing Activities:
Property additions	(1,741)		(1,541)		(1,561)
Cost of removal, net of salvage	(99)		(88)		(104)
Change in construction payables, net	(2)		(19)		(38)
Investments in unconsolidated subsidiaries	(74)		(82)		(11)
Returned investment in unconsolidated subsidiaries	148		15		14
Proceeds from dispositions	—		3		42
Other investing activities	—		1		2
Net cash used for investing activities	(1,768)		(1,711)		(1,656)
Financing Activities:
Increase (decrease) in notes payable, net	(31)		40		(153)
Proceeds —
Senior notes	850		450		500
First mortgage bonds	200		275		275
Other long-term debt	—		8		37
Redemptions and repurchases —
Senior notes	(250)		—		—
First mortgage bonds	(50)		—		(50)
Short-term borrowings	—		—		(200)
Medium-term notes	—		—		(350)
Return of capital to parent company	(23)		—		—
Capital contributions from parent company	39		16		373
Payment of common stock dividends	(594)		(605)		(585)
Other financing activities	(19)		(16)		(1)
Net cash provided from (used for) financing activities	122		168		(154)
Net Change in Cash, Cash Equivalents, and Restricted Cash	(29)		9		(48)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	44		35		83
Cash, Cash Equivalents, and Restricted Cash at End of Year	$	15	$	44	$	35
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $16, $21, and $16 capitalized, respectively)	$	372	$	329	$	291
Income taxes, net	29		59		91
Noncash transactions —
Accrued property additions at year-end	112		113		139
Return of capital to parent company	34		—		—

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

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CONSOLIDATED BALANCE SHEETS

At December 31, 2025 and 2024

Southern Company Gas and Subsidiary Companies

Assets	2025		2024
	(in millions)
Current Assets:
Cash and cash equivalents	$	15	$	43
Receivables —
Customer accounts	490		399
Unbilled revenues	341		244
Other accounts and notes	57		45
Accumulated provision for uncollectible accounts	(50)		(33)
Materials and supplies	62		66
Natural gas for sale	396		388
Prepaid expenses	26		45
Other regulatory assets	114		187
Other current assets	66		55
Total current assets	1,517		1,439
Property, Plant, and Equipment:
In service	24,098		22,338
Less: Accumulated depreciation	6,273		5,887
Plant in service, net of depreciation	17,825		16,451
Construction work in progress	863		1,057
Total property, plant, and equipment	18,688		17,508
Other Property and Investments:
Goodwill	5,015		5,015
Equity investments in unconsolidated subsidiaries	1,182		1,279
Other intangible assets, net of amortization of $179 and $173, respectively	3		9
Miscellaneous property and investments	24		25
Total other property and investments	6,224		6,328
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	85		38
Prepaid pension and other postretirement benefit costs	229		191
Other regulatory assets, deferred	517		481
Other deferred charges and assets	127		192
Total deferred charges and other assets	958		902
Total Assets	$	27,387	$	26,177

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

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CONSOLIDATED BALANCE SHEETS

At December 31, 2025 and 2024

Southern Company Gas and Subsidiary Companies

Liabilities and Stockholder's Equity	2025		2024
	(in millions)
Current Liabilities:
Securities due within one year	$	531	$	302
Notes payable	425		455
Accounts payable —
Affiliated	70		75
Other	553		437
Customer deposits	75		98
Accrued taxes	107		85
Accrued interest	100		88
Accrued compensation	137		129
Natural gas cost over recovery	158		193
Other regulatory liabilities	36		7
Other current liabilities	110		149
Total current liabilities	2,302		2,018
Long-term Debt	8,743		8,229
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,971		1,796
Deferred credits related to income taxes	681		755
Employee benefit obligations	78		78
Operating lease obligations	123		30
Other cost of removal obligations	1,921		1,846
Accrued environmental remediation	207		198
Other deferred credits and liabilities	234		231
Total deferred credits and other liabilities	5,215		4,934
Total Liabilities	16,260		15,181
Common Stockholder’s Equity:
Common stock, par value $0.01 per share<br><br>(Authorized - 100 million shares; Outstanding - 100 shares)	—		—
Paid-in capital	10,854		10,863
Retained earnings	222		85
Accumulated other comprehensive income	51		48
Total common stockholder's equity (See accompanying statements)	11,127		10,996
Total Liabilities and Stockholder's Equity	$	27,387	$	26,177
Commitments and Contingent Matters (See notes)

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

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CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

For the Years Ended December 31, 2025, 2024, and 2023

Southern Company Gas and Subsidiary Companies

	Number of Common Shares<br>Issued	Common Stock		Paid-In Capital		Retained Earnings (Accumulated Deficit)		Accumulated<br>Other<br>Comprehensive Income (Loss)		Total
	(in millions)
Balance at December 31, 2022	—	$	—	$	10,445	$	(79)	$	31	$	10,397
Net income	—	—		—		615		—		615
Capital contributions from parent company	—	—		391		—		—		391
Other comprehensive income (loss)	—	—		—		—		(15)		(15)
Cash dividends on common stock	—	—		—		(585)		—		(585)
Balance at December 31, 2023	—	—		10,836		(49)		16		10,803
Net income	—	—		—		740		—		740
Capital contributions from parent company	—	—		27		—		—		27
Other comprehensive income	—	—		—		—		32		32
Cash dividends on common stock	—	—		—		(605)		—		(605)
Other	—	—		—		(1)		—		(1)
Balance at December 31, 2024	—	—		10,863		85		48		10,996
Net income	—	—		—		732		—		732
Return of capital to parent company	—	—		(57)		—		—		(57)
Capital contributions from parent company	—	—		47		—		—		47
Other comprehensive income	—	—		—		—		3		3
Cash dividends on common stock	—	—		—		(594)		—		(594)
Other	—	—		1		(1)		—		—
Balance at December 31, 2025	—	$	—	$	10,854	$	222	$	51	$	11,127

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

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COMBINED NOTES TO FINANCIAL STATEMENTS

Notes to the Financial Statements

for

The Southern Company and Subsidiary Companies

Alabama Power Company

Georgia Power Company

Mississippi Power Company

Southern Power Company and Subsidiary Companies

Southern Company Gas and Subsidiary Companies

Index to the Combined Notes to Financial Statements

Note		Page
1	Summary of Significant Accounting Policies	II-115
2	Regulatory Matters	II-129
3	Contingencies, Commitments, and Guarantees	II-150
4	Revenue from Contracts with Customers	II-155
5	Property, Plant, and Equipment	II-160
6	Asset Retirement Obligations	II-163
7	Consolidated Entities and Equity Method Investments	II-168
8	Financing	II-170
9	Leases	II-180
10	Income Taxes	II-188
11	Retirement Benefits	II-197
12	Stock Compensation	II-226
13	Fair Value Measurements	II-228
14	Derivatives	II-236
15	Acquisitions and Dispositions	II-245
16	Segment and Related Information	II-247

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 table below indicates the Registrants to which each note applies.

	Applicable Notes
Registrant	1	2	3	4	5	6	7	8	9	10	11	12	13	14	15	16
Southern Company	l	l	l	l	l	l	l	l	l	l	l	l	l	l	l	l
Alabama Power	l	l	l	l	l	l	l	l	l	l	l	l	l	l	l	l
Georgia Power	l	l	l	l	l	l	l	l	l	l	l	l	l	l		l
Mississippi Power	l	l	l	l	l	l		l	l	l	l	l	l	l	l	l
Southern Power	l		l	l	l	l	l	l	l	l	l	l	l	l	l	l
Southern Company Gas	l	l	l	l	l	l	l	l	l	l	l	l	l	l		l

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COMBINED NOTES TO FINANCIAL STATEMENTS

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, operates, and manages power generation assets, including battery energy storage 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. 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, which, through its subsidiaries, invests in various projects and insures various risk exposures of Southern Company and its subsidiaries. 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 Plants Hatch and Vogtle. PowerSecure develops distributed energy and resilience solutions and deploys microgrids for commercial, industrial, governmental, and utility customers.

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 an 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 November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (ASU 2023-07), which requires entities to disclose significant segment expenses, other segment items, the title and position of the CODM, and information related to how the CODM assesses segment performance and allocates resources, among certain other required disclosures. Additionally, previous annual disclosures are required in interim periods. The Registrants adopted ASU 2023-07 and applied the guidance retrospectively effective for the fiscal year beginning January 1, 2024. ASU 2023-07 was applied retrospectively for the interim periods beginning January 1, 2025. See Note 16 for additional information and related disclosures.

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures (ASU 2023-09), which requires entities to enhance consistency in income tax disclosures by improving transparency and comparability for stakeholders. Among other changes, ASU 2023-09 requires additional information in the effective tax rate reconciliation, including disaggregation of certain categories, and greater detail about income taxes paid, including disaggregation by jurisdiction. The Registrants adopted ASU 2023-09 and applied the guidance retrospectively effective for the fiscal year beginning January 1, 2025. See Note 10 under "Effective Tax Rate" and "Cash Paid for Income Taxes" for additional information and related disclosures.

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COMBINED NOTES TO FINANCIAL STATEMENTS

In July 2025, the FASB issued ASU 2025-05, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses for Accounts Receivable and Contract Assets (ASU 2025-05), which allows an entity to elect a practical expedient for measuring expected credit losses on current accounts receivable and current contract assets arising from transactions accounted for as revenues from contracts customers. This expedient allows an entity to assume that current economic conditions as of the balance sheet date do not change for the remaining life of the asset. ASU 2025-05 is effective for fiscal years beginning after December 15, 2025 and interim periods within fiscal years beginning after December 15, 2026. As permitted, the Registrants have elected to early adopt the practical expedient as of December 31, 2025 and applied its provisions prospectively to the provision for uncollectable accounts. The adoption of ASU 2025‑05 did not have a material impact on the consolidated results of operations, cash flows or financial condition of the Registrants. See "Provision for Uncollectible Accounts" herein for additional information and disclosures impacted by ASU 2025-05.

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 2025, 2024, and 2023 were as follows:

	Alabama<br>Power		Georgia<br>Power		Mississippi<br>Power		Southern<br>Power		Southern<br><br>Company Gas
	(in millions)
2025	$	855	$	1,364	$	138	$	101	$	313
2024	813		1,197		130		93		290
2023	611		857		113		86		261

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; and other services with respect to business and operations. These costs are primarily included in other operations and maintenance expenses or capitalized to property, plant, and equipment. Costs for these services in 2025, 2024, and 2023 amounted to $275 million, $260 million, and $251 million, respectively, for Alabama Power and $832 million, $835 million, and $899 million, respectively, 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:

	Mississippi<br>Power		Southern<br>Power
	(in millions)
2025	$	19	$	41
2024	8		17
2023	4		13

Georgia Power has entered into a PPA with Mississippi Power, which commenced in 2024, and several PPAs with Southern Power for capacity and energy. Georgia Power's expenses associated with these PPAs are included in purchased power, affiliates on its statements of income. Mississippi Power's and Southern Power's revenues associated with these PPAs are included in wholesale revenues, affiliates on their respective statements of income. See Notes 2 and 9 for additional information.

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SCS (as agent for Alabama Power, Georgia Power, and Southern Power) and certain subsidiaries of 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" for additional information. Transportation costs under these agreements in 2025, 2024, and 2023 were as follows:

	Alabama<br>Power		Georgia<br>Power		Southern<br>Power		Southern<br><br>Company Gas
	(in millions)
2025	$	11	$	105	$	31	$	29
2024	13		103		35		28
2023	12		101		34		28

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, Mississippi Power, and Southern Power for all periods presented.

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 $9 million, $7 million, and $5 million in 2025, 2024, and 2023, respectively. See Notes 2 and 5 under "Mississippi Power – Integrated Resource Plans" and "Joint Ownership Agreements," respectively, 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. During 2025, 2024, and 2023, costs under these agreements were $51 million, $20 million, and $5 million, respectively, for Georgia Power and immaterial for Alabama Power and Mississippi Power.

Southern Company Gas had a $74 million contract with the U.S. General Services Administration to increase energy efficiency at certain federal buildings across Georgia, which was completed in 2025. Southern Company Gas engaged PowerSecure to provide the majority of the construction services under the contract. During 2025, 2024, and 2023, Southern Company Gas paid $1 million, $13 million, and $29 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 $9 million, $25 million, and $33 million for 2025, 2024, and 2023, 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.

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

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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 recognized for estimated deliveries of electricity not yet billed to these customers from the last bill date to the end of the accounting 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

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.

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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

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. 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.

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.

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.

Gas Distribution Operations

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. 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.

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 $(53) million, $43 million, and $20 million in 2025, 2024, and 2023, respectively. These programs primarily consist of:

•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.

Gas Marketing Services

Gas marketing services is comprised of several choice-based natural gas marketers operating in various deregulated jurisdictions. While gas marketing services follows the same general approach to revenue recognition described for Southern Company Gas above, it recognizes revenues on certain 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 long-term contracts described below), Southern Power, and Southern Company Gas each have a diversified base of customers. In 2025, Southern Power's

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largest customer was Georgia Power, which accounted for approximately 10.5% of Southern Power's total revenues. For the other Registrants, 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 which are subject to regulation by the FERC. The contracts with these wholesale customers represented 12.9% of Mississippi Power's total operating revenues in 2025.

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.

Income Taxes

The Registrants use the liability method of accounting for deferred income taxes and provide deferred income taxes for all significant income tax temporary differences. Under current tax law, certain projects are eligible for ITCs. The Registrants use the deferral method to account for federal and state ITCs, whereby the ITCs are recorded as a deferred credit and amortized to income tax expense over the useful life of the respective asset. In accordance with regulatory requirements, certain state ITCs at Georgia Power are recognized as an income tax benefit in the year the credit is generated through the establishment of a regulatory asset.

Furthermore, the federal tax basis of the asset is reduced by 50% of the federal ITCs received, which, together with the deferred credit, results in a net deferred tax asset. The Registrants have elected to recognize the tax benefit of these basis differences as a reduction to income tax expense in the year in which the asset reaches commercial operation. In accordance with regulatory requirements, the traditional electric operating companies and natural gas distribution utilities defer the income tax benefit resulting from these basis differences. In addition, certain projects are eligible for federal and state PTCs, which are recognized as an income tax benefit based on KWH production.

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 2025 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 "Deferred Tax Assets and Liabilities – Tax Credit Carryforwards" and " – Net Operating Loss Carryforwards" for additional information.

In April 2024, the IRS issued final 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 at a discount to the generated credit value. The discount will be recorded as a reduction in tax credits recognized in the financial statements. See Note 10 under "Current and Deferred Income Taxes" for additional information.

Under current tax law, Georgia Power is eligible to generate advanced nuclear PTCs for Plant Vogtle Units 3 and 4, which are recognized as an income tax benefit based on KWH production and are eligible to be transferred. Pursuant to the Vogtle Joint Ownership Agreements (as defined in Note 2 under "Georgia Power – Nuclear Construction – Cost and Schedule"), Georgia Power is purchasing advanced nuclear PTCs for Plant Vogtle Units 3 and 4 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.

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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 $132 million, $112 million, and $129 million in 2025, 2024, and 2023, 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 in 2025, 2024, and 2023 was immaterial for Mississippi Power and was as follows for the other Registrants:

	Southern<br><br>Company		Alabama<br>Power		Georgia<br><br>Power(*)		Southern<br>Power		Southern<br><br>Company Gas
	(in millions)
2025	$	480	$	88	$	327	$	25	$	38
2024	339		76		209		7		47
2023	400		109		251		3		37

(*)See Note 2 under "Georgia Power – Nuclear Construction" for information on the inclusion of a portion of construction costs related to Plant Vogtle Units 3 and 4 in Georgia Power's rate base through each unit's respective in-service date.

The average AFUDC composite rates for 2025, 2024, and 2023 for the applicable traditional electric operating companies and the natural gas distribution utilities were as follows:

	2025		2024		2023
Alabama Power	7.9	%	8.1	%	8.1	%
Georgia Power(*)	7.7	%	7.7	%	7.6	%
Southern Company Gas:
Atlanta Gas Light	7.9	%	7.7	%	7.4	%
Chattanooga Gas	7.1	%	7.1	%	7.1	%
Nicor Gas	4.2	%	5.6	%	4.6	%

(*)Excludes AFUDC related to the construction of Plant Vogtle Units 3 and 4 in 2023 and Plant Vogtle Unit 4 in 2024. See Note 2 under "Georgia Power – Nuclear Construction" for additional information.

Impairment of Long-Lived Assets

The Registrants evaluate long-lived 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 indicator exists 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 to be recorded. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.

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In 2024, Alabama Power discontinued the development of a multi-use commercial facility. Given the decision to discontinue commercial development, Alabama Power performed an impairment test using a comparative market analysis and determined the carrying amount of the asset exceeded its fair value, net of selling costs. This resulted in a pre-tax impairment loss of $36 million ($27 million after tax) reflected in other operations and maintenance on the statements of income.

Goodwill and Other Intangible Assets

Goodwill and other intangible assets not subject to amortization are evaluated for impairment on an annual basis and when events or changes in circumstances necessitate an evaluation for impairment. Other intangible assets subject to amortization are evaluated for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable.

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 2025 and 2023 annual goodwill impairment tests, Southern Company Gas management performed the qualitative assessment and determined that it was more likely than not that the fair value of its reporting units with goodwill exceeded their carrying amounts, and therefore no quantitative assessment was required. For its 2024 annual goodwill impairment test, Southern Company Gas management performed the quantitative assessment, which indicated that the fair value of its reporting units with goodwill exceeded their carrying amounts.

For its 2025 and 2023 annual goodwill impairment tests, PowerSecure management performed the quantitative assessment, which indicated that the fair value of PowerSecure exceeded its carrying amount. For its 2024 annual goodwill impairment test, PowerSecure management performed the qualitative assessment and determined that it was more likely than not that the fair value of PowerSecure exceeded its carrying amount, and therefore no quantitative assessment was required.

At December 31, 2025 and 2024, goodwill was as follows:

	At December 31, 2025		At December 31, 2024
	(in millions)
Southern Company	$	5,161	$	5,161
Southern Company Gas:
Gas distribution operations	$	4,034	$	4,034
Gas marketing services	981		981
Southern Company Gas total	$	5,015	$	5,015

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At December 31, 2025 and 2024, other intangible assets were as follows:

	At December 31, 2025						At December 31, 2024
	Gross<br><br>Carrying<br><br>Amount		Accumulated<br><br>Amortization		Other<br><br>Intangible<br><br>Assets, Net		Gross<br><br>Carrying<br><br>Amount		Accumulated<br><br>Amortization		Other<br><br>Intangible<br><br>Assets, Net
	(in millions)						(in millions)
Southern Company
Subject to amortization:
Customer relationships	$	212	$	(189)	$	23	$	212	$	(182)	$	30
Trade names	64		(64)		—		64		(59)		5
PPA fair value adjustments	390		(188)		202		390		(168)		222
Other	3		(3)		—		3		(3)		—
Total subject to amortization	$	669	$	(444)	$	225	$	669	$	(412)	$	257
Not subject to amortization:
FCC licenses	75		—		75		75		—		75
Total other intangible assets	$	744	$	(444)	$	300	$	744	$	(412)	$	332
Southern Power(*)
PPA fair value adjustments	$	390	$	(188)	$	202	$	390	$	(168)	$	222
Southern Company Gas(*)
Gas marketing services
Customer relationships	$	156	$	(153)	$	3	$	156	$	(150)	$	6
Trade names	26		(26)		—		26		(23)		3
Total other intangible assets	$	182	$	(179)	$	3	$	182	$	(173)	$	9

(*)All subject to amortization.

Amortization associated with other intangible assets in 2025, 2024, and 2023 was as follows:

	2025		2024		2023
	(in millions)
Southern Company(a)	$	32	$	35	$	38
Southern Power(b)	20		20		20
Southern Company Gas
Gas marketing services	6		7		10

(a)Includes $20 million annually recorded as a reduction to operating revenues.

(b)Recorded as a reduction to operating revenues.

At December 31, 2025, the estimated amortization associated with other intangible assets for the next five years is as follows:

	2026		2027		2028		2029		2030
	(in millions)
Southern Company	$	27	$	24	$	24	$	23	$	21
Southern Power	20		20		20		19		19
Southern Company Gas
Gas marketing services	3		—		—		—		—

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

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any noncontrolling interests (including any intangible assets) are recognized and measured at fair value, and goodwill is recognized as a residual over the fair values of the identifiable net assets acquired. 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. See Note 15 for additional information, including recent and proposed acquisitions.

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 accounted for as 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 consolidated statements of income. See Note 15 for additional information, including recent and proposed development projects.

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 covered under LTSAs are treated as noncash transactions in the statements of cash flows. Any payments made prior to the work being performed are recorded as prepayments in other current assets and non-current assets on the balance sheets or reduce existing payables for LTSA-related work already completed. At the time work is performed, an appropriate amount is accrued for future payments or transferred from the prepayment or inventory 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 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.

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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:

	Southern<br>Company		Georgia<br>Power		Southern<br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
At December 31, 2025
Cash and cash equivalents	$	1,639	$	59	$	105	$	15
Restricted cash(*):
Other current assets	1		—		—		—
Total cash, cash equivalents, and restricted cash	$	1,640	$	59	$	105	$	15
At December 31, 2024
Cash and cash equivalents	$	1,070	$	97	$	159	$	43
Restricted cash(*):
Other current assets	31		21		9		1
Total cash, cash equivalents, and restricted cash	$	1,101	$	118	$	168	$	44

(*)For Georgia Power, reflects remaining proceeds at December 31, 2024 from the issuance of solid waste disposal facility revenue bonds in 2022. For Southern Power, reflects remaining proceeds at December 31, 2024 from an arbitration award held to fund future equipment replacement costs. For Southern Company, also reflects collateral of $1 million for life insurance and long-term disability insurance, which was included at Southern Holdings and Southern Company Gas at December 31, 2025 and 2024, respectively.

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 the average cost of 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.

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 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, 2025, the Nicor Gas LIFO inventory balance was $194 million. Based on the average cost of gas purchased in December 2025, the estimated replacement cost of Nicor Gas' inventory at December 31, 2025 was $420 million.

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Provision for Uncollectible Accounts

See "Recently Adopted Accounting Standards" herein for additional information on the adoption of ASU 2025-05 and the practical expedient related to credit losses.

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. The Registrants have elected the practical expedient to assume that current conditions as of the balance sheet date will remain unchanged for the remaining life of the asset when estimating expected credit losses. 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 14 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, and interest rates. 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', Southern Power's, and Southern Company Gas' 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 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, 2025.

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

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.

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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.

The purchase, transportation, storage, and sale of natural gas are accounted for on a weighted average cost, accrual, or LIFO basis, as appropriate, rather than on the fair value basis utilized for the derivatives used to mitigate the natural gas price risk associated with these transactions. 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.

Comprehensive Income

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.

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

	Qualifying<br>Hedges		Pension and<br><br>Other<br><br>Postretirement<br><br>Benefit Plans		Accumulated<br><br>Other<br><br>Comprehensive<br><br>Income (Loss)(*)
	(in millions)
Southern Company
Balance at December 31, 2022	$	(149)	$	(18)	$	(167)
Current period change	28		(38)		(10)
Balance at December 31, 2023	(121)		(56)		(177)
Current period change	75		24		99
Balance at December 31, 2024	(46)		(32)		(78)
Current period change	(7)		10		3
Balance at December 31, 2025	$	(53)	$	(22)	$	(75)
Southern Power
Balance at December 31, 2022	$	(9)	$	(9)	$	(18)
Current period change	8		(7)		1
Balance at December 31, 2023	(1)		(16)		(17)
Current period change	8		7		15
Balance at December 31, 2024	7		(9)		(2)
Current period change	(2)		4		2
Balance at December 31, 2025	$	5	$	(5)	$	—
Southern Company Gas
Balance at December 31, 2022	$	(25)	$	56	$	31
Current period change	1		(16)		(15)
Balance at December 31, 2023	(24)		40		16
Current period change	21		11		32
Balance at December 31, 2024	(3)		51		48
Current period change	—		3		3
Balance at December 31, 2025	$	(3)	$	54	$	51

(*)May not add due to rounding.

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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.

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2. REGULATORY MATTERS

Regulatory Assets and Liabilities

Details of regulatory assets and (liabilities) reflected in the balance sheets at December 31, 2025 and 2024 are provided in the following tables:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Company Gas
	(in millions)
At December 31, 2025
AROs(*)	$	5,482	$	1,644	$	3,604	$	234	$	—
Retiree benefit plans(*)	2,442		630		836		128		31
Remaining net book value of retired assets	1,052		408		631		13		—
Deferred income tax charges	962		261		675		25		—
Storm damage	941		—		912		29		—
Deferred depreciation	784		428		356		—		—
Under recovered regulatory clause revenues	284		232		—		24		28
Software and cloud computing costs	248		92		146		7		3
Environmental remediation(*)	242		—		13		—		229
Vacation pay(*)	242		90		124		12		16
Loss on reacquired debt	203		30		169		4		—
Nuclear outage	106		59		47		—		—
Regulatory clauses	83		52		—		—		31
Qualifying repairs of natural gas distribution systems	65		—		—		—		65
Fuel-hedging (realized and unrealized) losses	50		18		18		14		—
Long-term debt fair value adjustment	44		—		—		—		44
Plant Daniel Units 3 and 4	21		—		—		21		—
Other regulatory assets	225		65		30		40		90
Deferred income tax credits	(4,725)		(1,585)		(2,238)		(211)		(681)
Other cost of removal obligations	(1,022)		15		999		(115)		(1,921)
Reliability reserves	(243)		(184)		—		(59)		—
Over recovered regulatory clause revenues	(213)		—		(31)		—		(182)
Storm/property damage reserves	(118)		(60)		—		(58)		—
Plant Daniel Units 1 and 2 acquisition	(34)		—		—		(34)		—
Other regulatory liabilities	(234)		(17)		(16)		(3)		(61)
Total regulatory assets (liabilities), net	$	6,887	$	2,178	$	6,275	$	71	$	(2,308)

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	Southern<br>Company		Alabama<br>Power		Georgia<br>Power		Mississippi<br>Power		Southern<br>Company<br>Gas
	(in millions)
At December 31, 2024
AROs(*)	$	5,810	$	1,906	$	3,658	$	248	$	—
Retiree benefit plans(*)	2,605		680		892		134		44
Remaining net book value of retired assets	1,198		454		729		15		—
Deferred income tax charges	927		264		634		27		—
Storm damage	859		—		827		32		—
Deferred depreciation	535		286		249		—		—
Environmental remediation(*)	249		—		16		—		233
Vacation pay(*)	224		85		112		12		15
Loss on reacquired debt	219		32		183		4		—
Software and cloud computing costs	200		76		116		4		4
Under recovered regulatory clause revenues	167		119		—		17		31
Regulatory clauses	162		82		—		—		80
Nuclear outage	92		39		53		—		—
Fuel-hedging (realized and unrealized losses)	69		23		29		17		—
Qualifying repairs of natural gas distribution systems	53		—		—		—		53
Long-term debt fair value adjustment	52		—		—		—		52
Plant Daniel Units 3 and 4	23		—		—		23		—
Other regulatory assets	184		42		40		30		72
Deferred income tax credits	(4,536)		(1,398)		(2,149)		(219)		(755)
Other cost of removal obligations	(1,176)		24		816		(170)		(1,846)
Over recovered regulatory clause revenues	(285)		(29)		(52)		—		(204)
Reliability reserves	(188)		(131)		—		(57)		—
Storm/property damage reserves	(122)		(70)		—		(52)		—
Nuclear fuel disposal cost recovery	(100)		(100)		—		—		—
Other regulatory liabilities	(180)		(28)		(14)		(6)		(31)
Total regulatory assets (liabilities), net	$	7,041	$	2,356	$	6,139	$	59	$	(2,252)

(*)Generally not earning a return as they are excluded from rate base or are offset in rate base by a corresponding asset or liability.

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:

AROs and other cost of removal obligations – Generally recorded over the related property lives, which may range up to 64 years for Alabama Power, 58 years for Georgia Power, 75 years for Mississippi Power, and 85 years for Southern Company Gas. AROs and other 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. Georgia Power is recovering CCR ARO expenditures over four-year periods through its ECCR tariff. Mississippi Power is recovering CCR ARO expenditures over a 10-year period ending in 2034 through its ECO Plan. See "Georgia Power – Rate Plans" herein and Note 6 for additional information.

Retiree benefit plans – Recovered and amortized over the average remaining service period, which may range up to 14 years for Alabama Power, Georgia Power, and Mississippi Power and 15 years for 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.

Remaining net book value of retired assets –

Alabama Power: Primarily represents the net book value of Plant Gorgas Unit 10 ($387 million at December 31, 2025) being amortized over a remaining period of 12 years (through 2037) and Plant Barry Unit 4 ($32 million at December 31, 2025) being amortized over a remaining period of nine 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 and Plant Hammond Unit 4 (totaling $348 million and $271 million, respectively, at December 31, 2025) are being amortized over a remaining period of 13 years (through 2038) pursuant to the extension of the 2022 ARP. Balance also includes unusable materials and supplies inventories, for which the Georgia PSC will determine a recovery period in a future base rate case. See "Georgia Power – Rate Plans" herein additional information.

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 remaining period of eight years (through 2033), and the wholesale portion is being amortized over a remaining period of nine years (through 2034). See "Mississippi Power – Environmental Compliance Overview Plan" herein for additional information.

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Deferred income tax charges and credits – Charges are recovered and credits are primarily amortized over the related property lives, which may range up to 64 years for Alabama Power, 58 years for Georgia Power, 75 years for Mississippi Power, and 85 years for Southern Company Gas. See Note 10 for additional information. 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, 2025 include certain tax credits which will be returned to customers in a manner determined by the Alabama PSC, as discussed under "Alabama Power – Nuclear Production Tax Credits Order" herein. Related amounts at December 31, 2024 include excess federal deferred income tax liabilities that were returned for the benefit of customers in 2025, as discussed under "Alabama Power – Excess Accumulated Deferred Income Tax Accounting Order" herein.

Georgia Power: For deferred income tax charges, related amounts include deferred income tax assets related to construction costs for Plant Vogtle Units 3 and 4 ($120 million at December 31, 2025) being recovered over a remaining period of nine years (through 2034). For deferred income tax credits, related amounts at December 31, 2025 include $255 million of deferred income tax benefits for certain tax credits and $39 million of excess state deferred income tax liabilities, which are both expected to be amortized over a period of up to three years (through 2028), and related amounts at December 31, 2024 include $102 million of excess state deferred income tax liabilities that were returned to customers in 2025. See "Georgia Power – Rate Plans" and " – Nuclear Construction – Regulatory Matters" herein for additional information.

Mississippi Power: Related amounts at December 31, 2025 include retail excess federal deferred income tax liabilities of $21 million resulting from the Tax Reform Legislation, the flowback of which will be determined by the Mississippi PSC in a future rate proceeding. See "Mississippi Power – Excess Accumulated Deferred Income Tax Accounting Order" herein for additional information.

Southern Company Gas: Related amounts include deferred income tax liabilities ($26 million at December 31, 2025) being amortized over periods generally not exceeding five years, primarily related to excess state deferred income tax liabilities. See "Southern Company Gas – Rate Proceedings" herein for additional information.

Storm damage – See "Georgia Power – Storm Damage Recovery" herein for additional information. Mississippi Power's balance represents deferred storm costs associated with Hurricanes Ida and Zeta being recovered through PEP over a remaining period of nine years (through 2034).

Deferred depreciation –

Alabama Power: Represents deferred depreciation for Plant Barry Unit 5 ($170 million at December 31, 2025) and Plant Barry common coal assets ($73 million at December 31, 2025) to be amortized until 2036 beginning when Alabama Power utilizes updated deprecation rates which is anticipated to be January 1, 2028 and Plant Gaston Unit 5 coal assets ($185 million at December 31, 2025) to be amortized until 2039 beginning when the assets are retired.

Georgia Power: Represents deferred depreciation for Plant Scherer Units 1 through 3 and Plant Bowen Units 1 and 2 (totaling $209 million and $121 million, respectively, at December 31, 2025) to be amortized over 13 years beginning January 1, 2026 (through 2038), both pursuant to the extension of the 2022 ARP, and Plant Vogtle Unit 3 and common facilities ($26 million at December 31, 2025) being amortized over a remaining period of nine years (through 2034). See "Georgia Power – Rate Plans" herein additional information.

Under and over recovered regulatory clause revenues –

Alabama Power: Balances are recorded monthly and expected to be recovered over periods of up to five years. See "Alabama Power – Rate CNP PPA," " – Rate CNP Compliance," and " – Rate ECR" herein for additional information.

Georgia Power: Related to Demand-Side Management (DSM) tariffs. Balances are recorded monthly. Pursuant to the extension of the 2022 ARP, the Georgia PSC will determine a recovery period in a future base rate case. See "Georgia Power – Rate Plans" herein for additional information.

Mississippi Power: At December 31, 2025, $11 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.

Software and cloud computing costs – 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 2035). 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 following the completion of the projects and is expected to begin no earlier than 2027. For Southern Company Gas, costs are being amortized ratably over the life of the related software, which ranges up to 10 years (through 2035).

Environmental remediation – 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.

Vacation pay – Recorded as earned by employees and recovered as paid, generally within one year. Includes both vacation and banked holiday pay, if applicable.

Loss on reacquired debt – Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue. At December 31, 2025, the remaining amortization periods do not exceed 22 years for Alabama Power, 27 years for Georgia Power, 16 years for Mississippi Power, and two years for Southern Company Gas.

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.

Regulatory clauses –

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.

Qualifying repairs of natural gas distribution systems – Represents deferred costs of certain repairs at Atlanta Gas Light being amortized over 20 years.

Fuel-hedging (realized and unrealized) losses and gains – 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 five years for Mississippi Power. Immaterial amounts for fuel-hedging gains at December 31, 2025 and 2024 are included in other regulatory liabilities. See Note 14 for additional information.

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Long-term debt fair value adjustment – Recovered over the remaining lives of the original debt issuances at acquisition, which range up to 13 years at December 31, 2025.

Plant Daniel Units 3 and 4 – 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, 2025, consists of the $15 million retail portion being amortized through 2046 over the remaining life of the related property and the $7 million wholesale portion being amortized over 10 years (through 2034).

Other regulatory assets – Comprised of numerous immaterial components with remaining amortization periods at December 31, 2025 generally not exceeding 18 years for Alabama Power, nine years for Georgia Power, 10 years for Mississippi Power, and 15 years for Southern Company Gas.

Reliability reserves and storm/property damage reserves – 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 for additional information.

Plant Daniel Units 1 and 2 acquisition – Represents the incremental cost to Mississippi Power to acquire FP&L's 50% ownership interest in Plant Daniel Units 1 and 2. Utilized as related expenses are incurred. See "Mississippi Power – Plant Daniel" herein for additional information.

Nuclear fuel disposal cost recovery – At December 31, 2024, represents award resulting from litigation related to nuclear fuel disposal costs, of which $93 million was returned to customers through bill credits during the months of January, February, and March 2025 and the remaining $7 million was applied to the NDR balance. See "Alabama Power – Rate NDR" herein and Note 3 under "Nuclear Fuel Disposal Costs" for additional information.

Other regulatory liabilities – Comprised of numerous immaterial components with remaining amortization periods at December 31, 2025 generally not exceeding one year for Alabama Power, three years for Georgia Power, one year for Mississippi Power, and 20 years for Southern Company Gas.

Alabama Power

Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power.

On December 5, 2025, the Alabama PSC issued a consent order (December 5th Consent Order) approving a plan to keep retail rates stable through 2027. The related impacts are described under "Rate RSE," "Rate CNP New Plant," "Rate CNP PPA," "Rate CNP Compliance," "Rate ECR," "Rate NDR," and "Nuclear Production Tax Credits Order" herein. Furthermore, the Alabama PSC, as part of its routine oversight of Alabama Power's regulated activities, will monitor factors such as weather, natural disasters, changes in fuel markets, and other significant unforeseen events that may impact this plan. If such events occur, Alabama Power will work with the Alabama PSC to determine a reasonable and responsive course of action under the circumstances.

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. Under the original RGC, Alabama was authorized to procure up to 500 MWs of renewable capacity and energy. In 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. Through December 31, 2025, Alabama Power has procured solar capacity totaling approximately 670 MWs under the RGC.

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.

At December 31, 2025 and 2024, Alabama Power's equity ratio was approximately 53.7% and 53.9%, 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

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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 2024 and increased by 4.87%, or $325 million annually, effective with the billing month of January 2025.

For the years ended December 31, 2023, 2024, and 2025, Alabama Power's WCER exceeded 6.15%, resulting in Alabama Power establishing a current regulatory liability of $15 million, $12 million, and $57 million, respectively, for Rate RSE refunds. The $15 million and $12 million regulatory liability at December 31, 2023 and 2024, respectively, was refunded to customers through bill credits in April 2024 and May 2025, respectively. The December 5th Consent Order required Alabama Power to subsequently apply the $57 million regulatory liability to the NDR on December 31, 2025.

On December 1, 2025, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2026. Projected earnings were within the specified range; therefore, retail rates under Rate RSE remain unchanged for 2026. In addition, pursuant to the December 5th Consent Order, Alabama Power agreed to implement a moratorium on any upward rate adjustments under Rate RSE for 2027.

Jurisdictional Separation Study Order

On June 5, 2025, the Alabama PSC approved an order authorizing Alabama Power to implement changes related to the Jurisdictional Separation Study (JSS) under Rate RSE, which allocates costs between retail and other electric services. For 2026, a revised JSS allocation factor accounts for Alabama Power system capacity previously allocated to wholesale electric services that is being used for retail electric service starting January 1, 2026. In addition, Alabama Power was authorized to establish a regulatory asset to defer certain costs associated with this capacity for 2026, and those costs are estimated to be approximately $100 million. Beginning in 2027, Alabama Power will amortize the regulatory asset on a levelized basis over a period not exceeding 10 years.

Excess Accumulated Deferred Income Tax Accounting Order

In 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 a January 2023 rate increase under Rate CNP Depreciation.

In 2023, the Alabama PSC issued an order modifying its 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 Reform Legislation 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 was flowed 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.

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. In March 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. In December 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.

On August 13, 2025, the Alabama PSC approved Alabama Power's petition for a CCN authorizing Alabama Power to complete the acquisition of the Lindsay Hill Generating Station (879.7 MWs), which had been approved by the FERC on June 6, 2025. The transaction closed on September 30, 2025. As part of the acquisition, Alabama Power assumed an existing power sales agreement under which the full output of the generating facility remains committed to a non-affiliated third party through April 2027. Upon expiration of that agreement, Alabama Power will recover costs associated with the Lindsay Hill Generating Station acquisition

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through Rate CNP New Plant, Rate CNP Compliance, Rate ECR, and Rate RSE. The December 5th Consent Order authorized Alabama Power to delay the effective date of the Rate CNP New Plant cost recovery until January 2028 billings. See Note 15 under "Alabama Power" for additional information.

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 from 2023 through 2025, and, pursuant to the December 5th Consent Order, there will be no adjustments through March 2028 billings. At December 31, 2025 and 2024, Alabama Power had an under recovered Rate CNP PPA balance of $67 million and $84 million, respectively, of which $17 million and $17 million, respectively, is included in other regulatory assets, current and $50 million and $67 million, respectively, is included in other regulatory assets, deferred on Southern Company's and Alabama Power's balance sheets.

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 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 December 2023, November 2024, and November 2025, 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 2023 filing reflected a $23 million, or 0.3%, annual decrease effective with January 2024 billings. The 2024 and 2025 filings reflected a projected under recovered retail revenue requirement of $50 million and $44 million, respectively. In December 2024, the Alabama PSC issued a consent order directing Alabama Power to maintain the 2024 Rate CNP Compliance factors in effect through 2025, and, pursuant to the December 5th Consent Order, Alabama Power will continue to maintain those same factors through the billing month of December 2027. Both consent orders specified that any prior year under collected amounts would be deemed recovered before any current year amounts are recovered and any remaining under recovered amounts would be reflected in the subsequent year's filing.

At December 31, 2025 and 2024, Alabama Power had an under recovered Rate CNP Compliance balance of $18 million and $35 million, respectively, which are included in other regulatory assets, deferred on Southern Company's and Alabama Power's balance sheets.

Rate CNP Depreciation

Rate CNP Depreciation 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. No adjustments to Rate CNP Depreciation have occurred since its implementation effective with January 2023 billings, and no adjustments will occur in 2026.

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.

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In November 2023, the Alabama PSC approved a decrease to Rate ECR of approximately $126 million annually, effective with December 2023 billings. In May 2024, the Alabama PSC approved a decrease to Rate ECR of approximately $135 million annually, effective with July 2024 billings. In December 2024, the Alabama PSC approved an additional reduction to Rate ECR of $218 million annually, effective with January 2025 billings. Pursuant to the December 5th Consent Order, the currently effective energy cost recovery factor of 2.600 cents per KWH will remain in effect for the billing months of January 2026 through December 2027. Beginning with January 2028 billings, the rate will adjust to 5.910 cents per KWH absent a further order from the Alabama PSC.

At December 31, 2025, Alabama Power's under recovered fuel costs totaled $146 million and is included in other regulatory assets, deferred on Southern Company's and Alabama Power's balance sheets. At December 31, 2024, Alabama Power's over recovered fuel costs totaled $29 million and is included in other regulatory liabilities, current on Southern Company's and Alabama Power's 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.

Plant Greene County

Alabama Power jointly owns Plant Greene County Units 1 and 2 with an affiliate, Mississippi Power. See Note 5 under "Joint Ownership Agreements" for additional information. Mississippi Power's 2024 IRP includes a schedule to retire Mississippi Power's 40% ownership interest in Plant Greene County Units 1 and 2 by the end of 2028. Alabama Power currently expects to retire Plant Greene County Units 1 and 2 (300 MWs based on 60% ownership) by the end of 2028. Alabama Power and Mississippi Power have continued to evaluate operating conditions and business needs relevant to the anticipated retirement of Plant Greene County Units 1 and 2. The ultimate outcome of this matter cannot be determined at this time. See "Mississippi Power – Integrated Resource Plans" 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. 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 charge to recover a deficit is $5.00 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 additional accruals of $7 million and $21 million in 2025 and 2024, respectively, and applied the 2025 Rate RSE refund of $57 million to the NDR in accordance with the December 5th Consent Order.

Under Rate NDR, Alabama Power collected approximately $23 million, $12 million, and $12 million in 2025, 2024, and 2023, respectively. Pursuant to orders of the Alabama PSC, Alabama Power applied $7 million of undistributed customer bill credits related to the nuclear fuel disposal costs litigation award to Rate NDR in 2025. Additionally, undistributed customer bill credits of $6 million and $1 million associated with Rate RSE refunds were applied in 2024 and 2023, respectively. Beginning with July 2025 billings, the reserve maintenance charge was suspended and the reserve establishment charge was activated as a result of the NDR balance falling below $50 million. Alabama Power expects to collect approximately $36 million annually under Rate NDR unless the NDR balance exceeds $75 million. At December 31, 2025 and 2024, the NDR balance was $60 million and $70 million, respectively, and is included in other regulatory liabilities, deferred on Southern Company's and Alabama Power's balance sheets. See Note 3 under "Nuclear Fuel Disposal Costs" for additional information regarding the nuclear fuel disposal costs litigation.

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

Based on orders from the Alabama PSC, Alabama Power is authorized to maintain a reliability reserve separate from the NDR and to include certain reliability-related transmission and distribution expenses and generation-related expenses intended to

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maintain reliability between scheduled generating unit maintenance outages. Alabama Power may make accruals to the reliability reserve if the NDR balance exceeds $35 million.

In 2025, Alabama Power utilized $30 million of the reliability reserve for reliability-related transmission, distribution, and generation expenses and accrued $83 million to the reliability reserve in accordance with procedures established in the reliability reserve accounting order. In 2023 and 2024, Alabama Power utilized a net $23 million and $12 million, respectively, from the reliability reserve for reliability-related transmission, distribution, and generation expenses.

Alabama Power notified the Alabama PSC through its annual RSE filing of its intent to utilize $60 million of its reliability reserve balance in 2026.

At December 31, 2025, Alabama Power's reliability reserve balance was $184 million, of which $60 million is included in other regulatory liabilities, current and $124 million is included in other regulatory liabilities, deferred on Southern Company's and Alabama Power's balance sheets. At December 31, 2024, Alabama Power's reliability reserve balance was $131 million and is included in other regulatory liabilities, deferred on Southern Company's and Alabama Power's balance sheets.

Environmental Accounting Order

Based on an order from the Alabama PSC, 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 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.

Alabama Power previously indicated plans to retire Plant Barry Unit 5 (700 MWs) by December 31, 2028. However, subsequent to December 31, 2025, as a result of projected future generation needs, a decision was made to convert Plant Barry Unit 5 from coal to natural gas and to continue operating Plant Barry Unit 5 beyond December 31, 2028. As a result, the unit's net book value of approximately $307 million no longer meets the criteria to be considered probable of abandonment. Accordingly, in the first quarter 2026, approximately $307 million will be reclassified from other utility plant, net to plant in service on Alabama Power's and Southern Company's balance sheets.

Nuclear Production Tax Credits Order

On October 7, 2025, the Alabama PSC issued an order authorizing Alabama Power to establish a regulatory liability for nuclear PTCs received through its nuclear generating facilities pursuant to Internal Revenue Code §45U for tax years 2024 through 2032. The §45U PTCs will be deferred as a regulatory liability until the Alabama PSC provides direction on how to apply them for the benefit of customers. For the 2024 tax year, Alabama Power received $180 million in §45U PTCs on Southern Company's consolidated federal income tax return. Pursuant to the December 5th Consent Order, Alabama Power will utilize the 2024 nuclear PTCs, when monetized, to offset retail cost of service in 2027. In addition, the nuclear PTCs generated in 2025, 2026, and 2027, when monetized, will be used to offset future retail cost of service, including any under recovered balances under Rate CNP and Rate ECR. The §45U PTC is subject to a phase-out. As such, Alabama Power will evaluate annually whether it qualifies for the credit. The ultimate outcome of this matter cannot be determined at this time. See Note 10 under "Unrecognized Tax Benefits" for additional information.

Georgia Power

Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power recovers its costs from the regulated retail business through traditional base tariffs, DSM tariffs, the ECCR tariff, and Municipal Franchise Fee (MFF) tariffs. These tariffs were set under the 2022 ARP for the years 2023 through 2025 and subsequently extended through 2028 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 base rate adjustments for the remaining costs related to Plant Vogtle Units 3 and 4 that became effective May 1, 2024 based on the in-service date of April 29, 2024 for Unit 4. Financing costs on certified construction costs of Plant Vogtle Units 3 and 4 were collected through Georgia Power's NCCR tariff until the inclusion of certified construction costs in rate base. When the base rate adjustments occurred following commercial operation of Unit 4, the NCCR tariff ceased to be collected and financing costs are now included in Georgia Power's general retail revenue requirements. See "Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

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Rate Plans

In November 2023 and December 2024, the Georgia PSC approved the following tariff adjustments under the 2022 ARP effective January 1, 2024 and 2025, respectively:

Tariff	2024		2025
	(millions)
Traditional base(a)	$	275	$	194
ECCR	(99)		126
DSM	10		(22)
MFF	5		9
Total(b)	$	191	$	306

(a)For 2025, net of $122 million related to the Georgia state tax rate reduction.

(b)Totals may not add due to rounding.

On July 1, 2025, the Georgia PSC approved a settlement agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors to extend the 2022 ARP for an additional three-year term through December 31, 2028 (ARP Extension). Under the ARP Extension, base rates will not be adjusted in 2026, 2027, or 2028 (ARP Extension Period) except for reasonable and prudent storm damage costs incurred through December 31, 2025, which will be determined in a separate regulatory proceeding. The ARP Extension includes, among other things, the following modifications to the 2022 ARP:

•Storm damage costs will be included in a separate regulatory proceeding to be filed no later than July 1, 2026 to recover the actual reasonable and prudent storm costs incurred through December 31, 2025. Subject to Georgia PSC approval, new rates would be effective approximately 90 days after the filing is made. The Georgia PSC will determine the period over which any such storm damage costs will be recovered.

•Amortization of regulatory assets and liabilities in the 2022 ARP, which were subsequently included in current rates through annual compliance filings, will continue through the ARP Extension Period. This includes those regulatory asset and liability balances that were projected to be fully amortized through 2025 or during the ARP Extension Period.

•The amounts previously deferred during the 2022 ARP for ITCs and PTCs will be amortized through the ARP Extension Period. The acceleration of amortization during the ARP Extension Period is subject to the Internal Revenue Code normalization rules and other guidance (if any) released by the IRS. Certain amounts of ITCs generated during the ARP Extension Period will be amortized over five years, and additional ITC amounts will be deferred to a regulatory liability during the ARP Extension Period. Sixty percent (60%) of PTC benefits generated (excluding PTCs generated under Internal Revenue Code §45J) during the ARP Extension Period will be credited to income tax expense as generated. The remaining forty percent (40%) will be deferred to a regulatory liability.

•The period for depreciation and amortization related to certain generating plants and net book values of retired generating plants will be 13 years effective January 1, 2026.

In the 2022 ARP, the Georgia PSC approved recovery through the ECCR tariff of estimated CCR ARO compliance costs for 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 a reduction of $60 million in the related amortization for 2024 and an increase of $123 million in the related amortization for 2025. Under the ARP Extension, the amortization will not change for 2026 through 2028. Compliance costs incurred were $300 million, $265 million, and $315 million in 2023, 2024, and 2025, respectively.

Further, under the 2022 ARP and the ARP Extension, Georgia Power's retail ROE is set at 10.50% and its equity ratio is set at 56%. Earnings are evaluated against a retail ROE range of 9.50% to 11.90%. Any earnings above 11.90% retail ROE will be subject to sharing whereby 40% of earnings above the band would be applied to regulatory assets, 40% would be directly refunded to customers, and the remaining 20% would be retained by Georgia Power. There will be no recovery of any earnings shortfall below 9.50% retail ROE on an actual basis. However, if at any time during the term of the 2022 ARP and the ARP Extension Period, Georgia Power projects that its retail earnings will be less than the lower end of the approved retail ROE range 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 retail ROE equal to the lower end of the approved retail ROE range. The Georgia PSC would have 90 days to rule on Georgia Power's request. Any ICR tariff would expire at the earlier of January 1, 2029 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 an ICR tariff, Georgia Power may file a full base rate case. In 2023, 2024, and 2025, Georgia Power's retail ROE was within the allowed retail ROE range.

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Except as provided above, Georgia Power will not file a base rate increase while the ARP Extension is in effect. Georgia Power is required to file a general base rate case by July 1, 2028, in response to which the Georgia PSC would be expected to determine whether the 2022 ARP should be continued, modified, or discontinued.

Integrated Resource Plans

2025 IRP

On July 15, 2025, the Georgia PSC approved Georgia Power's triennial IRP (2025 IRP), as modified by a stipulation among Georgia Power, the staff of the Georgia PSC, and certain intervenors. In the 2025 IRP decision, the Georgia PSC approved the following requests:

•Extended operation of Plant Scherer Unit 3 (614 MWs based on 75% ownership) through at least December 31, 2035 and Plant Gaston Units 1 through 4 (500 MWs based on 50% ownership through SEGCO) through December 31, 2034. See Note 7 under "SEGCO" for additional information.

•Installation of environmental controls and natural gas co-firing at Plant Bowen Units 1 through 4 (3,160 MWs), Plant Scherer Units 1 and 2 (137 MWs based on 8.4% ownership), and Plant Scherer Unit 3 for compliance with both ELG supplemental rules and GHG rules.

•Upgrades to Plant McIntosh Units 10 and 11 (1,319 MWs) for a projected 194 MWs of incremental capacity by 2028 and Plant McIntosh Units 1 through 8 (640 MWs) for a projected 74 MWs of incremental capacity by 2033.

•Upgrades to Plant Vogtle Units 1 and 2 (1,060 MWs based on 45.7% ownership) for a projected 54 MWs of incremental capacity, some of which could be available as early as 2028.

•Investments related to the continued reliable operations of four hydro facilities, as well as the authority to spend up to $25 million to undertake engineering studies related to two additional hydro facilities.

•RFP for at least 1,100 MWs of utility scale and distributed generation renewable resources.

•Issuance of a capacity RFP to procure resources to meet capacity needs in 2032 and 2033.

•Strategic power delivery infrastructure plan necessary to help ensure adequate reliability and serve the projected future load growth projected in Georgia.

•Certification of approximately 187 MWs of wholesale capacity associated with Plant Scherer Unit 3 to be placed in retail rate base, some of which will be available beginning in 2026.

In addition, the 2025 IRP assumes Plant Bowen Units 1 and 2 will operate through at least the end of 2035.

Certification Requests

On September 4, 2025, the Georgia PSC approved Georgia Power's request to certify a Georgia Power-owned battery energy storage facility with a capacity of 200 MWs and a projected COD in 2027.

On December 19, 2025, the Georgia PSC approved Georgia Power's request, as modified by a stipulation between Georgia Power and the staff of the Georgia PSC (Certification Stipulation), to certify the following resources totaling 9,885 MWs:

•18 resources selected from the RFP pursuant to the 2022 IRP final order, totaling 7,999 MWs, which consist of four PPAs (including two affiliate PPAs with Southern Power that are subject to approval by the FERC) with capacity totaling 1,195 MWs commencing between 2028 and 2030, three project sites consisting of five Georgia Power-owned combined cycle units with capacity totaling 3,692 MWs and projected CODs commencing between 2029 and 2030, nine Georgia Power-owned battery energy storage facilities with capacity totaling 2,762 MWs and projected CODs commencing between 2028 and 2030, and two Georgia Power-owned battery energy storage facilities with solar with capacity totaling 350 MWs and projected CODs commencing in 2028.

•Extension of 50 MWs of an existing 750-MW affiliate PPA with Mississippi Power for an additional year through December 31, 2029.

•A 20-year non-affiliate PPA for 930 MWs commencing in 2030 and five 25-year non-affiliate PPAs totaling 646 MWs commencing in 2027.

•Construction of a 260-MW Georgia Power-owned battery energy storage facility with a projected COD in 2027 to be paired with an existing non-affiliate solar PPA.

Pursuant to the Certification Stipulation, Georgia Power has agreed to file its next base rate case in a manner that will ensure the incremental revenue from large load customers has downward pressure, on a levelized basis, of at least $556 million per year for the years 2029, 2030, and 2031.

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The approved certification requests in September and December 2025 associated with these Georgia Power-owned projects and related transmission investments total approximately $16.7 billion, excluding AFUDC.

As required by the 2025 IRP decision, Georgia Power filed with the Georgia PSC on September 17, 2025 an updated load forecast to support the certification requests from the RFP of up to 8,500 MWs.

As included in the 2022 IRP final order, on February 11, 2026, Georgia Power initiated an RFP for up to 500 MWs of capacity for battery energy storage facilities with projected CODs or delivery commencement dates by 2031.

See "2025 IRP" and "Other Construction" herein for additional information.

Transmission Asset Sales

In March 2024, the FERC approved the sale of transmission line assets under the integrated transmission system agreement, with a net book value of $236 million. In April 2024, the sale, with a purchase price of $351 million, was completed resulting in a pre-tax gain of approximately $114 million ($84 million after tax) recorded in 2024.

Fuel Cost Recovery

Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. During 2022, Georgia Power's under recovered fuel balance increased significantly due to higher fuel and purchased power costs. In 2023, the Georgia PSC approved a stipulation 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, Georgia Power is allowed to adjust its fuel cost recovery rates under an interim fuel rider (IFR) 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 (IFR Threshold). On May 14, 2025, Georgia Power submitted an IFR notification and plan informing the Georgia PSC that Georgia Power's under recovered fuel balance exceeded the IFR Threshold. Georgia Power proposed no fuel cost recovery rate change and was required to monitor and report to the Georgia PSC monthly as long as the under recovered fuel balance was above the IFR Threshold. Georgia Power filed an IFR notification and plan monthly through September 2025, each of which also proposed no fuel cost recovery rate change. Between September 30, 2025 and November 30, 2025, Georgia Power's under recovered fuel balance did not exceed the IFR Threshold. On each of January 15, 2026 and February 13, 2026, Georgia Power filed an IFR notification and plan informing the Georgia PSC that Georgia Power's under recovered fuel balance exceeded the IFR Threshold as of December 31, 2025 and January 31, 2026, respectively, and proposed no fuel cost recovery rate change. On February 17, 2026, Georgia Power filed a request with the Georgia PSC to decrease fuel rates by 12.6% effective June 1, 2026, which is expected to reduce annual billings by approximately $388 million. Georgia Power expects the Georgia PSC to make a final decision on this matter on May 28, 2026. The ultimate outcome of this matter cannot be determined at this time.

Georgia Power's under recovered fuel balance totaled $522 million at December 31, 2025, of which $310 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 $212 million 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 $1.2 billion at December 31, 2024, of which $713 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 $453 million 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 to its transmission and distribution facilities resulting from major storms as mandated by the Georgia PSC. Beginning January 1, 2023, Georgia Power is recovering $31 million annually under the 2022 ARP. During September 2024, Hurricane Helene caused significant damage to Georgia Power's transmission and distribution facilities. The incremental restoration costs related to this hurricane totaled approximately $880 million, of which approximately $780 million was deferred in the regulatory asset for storm damage, approximately $75 million was capitalized to property, plant, and equipment, and approximately $25 million was deferred and subsequently billed in 2025 to open access transmission tariff customers. At December 31, 2025 and 2024, Georgia Power's regulatory asset balance related to storm damage was $912 million and $827 million, respectively, of which $31 million for each year is included in other regulatory assets, current

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and $880 million and $795 million, respectively, is included in other regulatory assets, deferred on Southern Company's and Georgia Power's balance sheets.

Pursuant to the ARP Extension, on February 17, 2026, Georgia Power filed a request with the Georgia PSC to recover the reasonable and prudent storm costs incurred through December 31, 2025, which is expected to increase annual recovery by approximately $300 million effective June 1, 2026. The proposed annual recovery included in the filing is expected to fully recover the regulatory asset balance related to storm damage at December 31, 2025 over four years, and the remaining balance at December 31, 2028 will be included in the next rate case. Georgia Power expects the Georgia PSC to make a final decision on this matter on May 28, 2026. The ultimate outcome of this matter cannot be determined at this time. See "Rate Plans" herein for additional information.

The rate of storm damage cost recovery is expected to be further adjusted in future regulatory proceedings as necessary. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's or Georgia Power's net income but do impact the related operating cash flows.

Nuclear Construction

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 placed Plant Vogtle Units 3 and 4 (553 MWs each based on 45.7% ownership) in service on July 31, 2023 and April 29, 2024, respectively. During the third quarter 2025, following the completion of site demobilization efforts, Southern Nuclear evaluated the remaining contractor obligations and reduced the remaining estimate to complete forecast by approximately $33 million. During the fourth quarter 2025, Southern Nuclear finalized the remaining contractor obligations and reduced the remaining estimate to complete forecast, including the impact of joint owner cost-sharing described below, by approximately $27 million. Accordingly, Georgia Power recorded pre-tax credits to income of approximately $33 million ($25 million after tax) and $27 million ($20 million after tax) in the third quarter 2025 and the fourth quarter 2025, respectively, to recognize capital costs previously charged to income. Georgia Power's final net investment in connection with Plant Vogtle Units 3 and 4 is $10.670 billion, which excludes capitalized AFUDC of approximately $440 million accrued through Unit 4's in-service date.

Georgia Power previously reached agreements with MEAG Power, OPC, and Dalton to resolve its respective dispute with each regarding the cost-sharing and tender provisions of the joint ownership agreements, as amended (Vogtle Joint Ownership Agreements). Under the terms of these agreements, among other items, Georgia Power reimbursed a portion of MEAG Power's, OPC's, and Dalton's costs of construction for Plant Vogtle Units 3 and 4 as such costs were incurred and with no further adjustment for force majeure costs, which payments (including amounts paid to date) totaled approximately $86 million, $82 million, and $4.4 million for MEAG Power, OPC, and Dalton, respectively, based on the final project capital cost. Georgia Power also reimbursed 20% of MEAG Power's costs of construction and 66% of each of OPC's and Dalton's costs of construction with respect to amounts over the final project capital cost, with no further adjustment for force majeure costs. Georgia Power recorded pre-tax charges to income through 2024 of $559 million ($418 million after tax) and a pre-tax credit to income in the fourth quarter 2025 of $22 million ($17 million after tax) associated with the cost-sharing provisions of the Vogtle Joint Ownership Agreements, including the settlements with the other Vogtle Owners described above. These charges are included in the total project capital cost and will not be recovered from retail customers.

Regulatory Matters

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 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.

In 2023, the Georgia PSC approved Georgia Power's application to adjust rates to include reasonable and prudent Plant Vogtle Units 3 and 4 costs as modified by the related stipulation (Prudency Stipulation) among Georgia Power, the staff of the Georgia PSC, and certain intervenors.

Under the terms of the approved Prudency Stipulation, Georgia Power is recovering $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 is also recovering projected operations and maintenance

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expenses, depreciation, 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 for Unit 3 and Common Facilities (approved by the Georgia PSC in 2021), Georgia Power included in retail rate base the remaining $5.462 billion of construction and capital costs as well as $647 million of associated retail rate base items effective with the April 29, 2024 in-service date for Unit 4. Annual retail base revenues increased approximately $730 million and the average retail base rates were adjusted by approximately 5% (net of the elimination of the NCCR tariff described below) effective May 1, 2024.

Reductions to the ROE used to calculate the NCCR tariff (pursuant to prior Georgia PSC orders) negatively impacted earnings by approximately $80 million through the second quarter 2024 and $310 million in 2023. Further, as included in the approved Prudency Stipulation, since commercial operation for Unit 4 was not achieved by March 31, 2024, Georgia Power's ROE used to determine the NCCR tariff and calculate AFUDC was reduced to zero effective April 1, 2024, which resulted in a negative impact to earnings of approximately $10 million (for one month) in the second quarter 2024 based on the April 29, 2024 in-service date. Effective May 1, 2024, following commercial operation of Unit 4, Georgia Power's NCCR tariff was eliminated and financing costs are included in Georgia Power's general retail revenue requirements.

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. Unit 3 demonstrated high performance and reliability during the first 14 months of operation leading up to its first refueling outage, which took place in the fall of 2024. Unit 4 also demonstrated high performance and reliability during the first 16 months of operation leading up to its first refueling outage, which took place in the fall of 2025. No customer credits for operations and maintenance expenses or performance-related disallowances were recorded.

The approval of the Prudency Stipulation resolved 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, which totaled approximately $14 million, was also recognized.

Other Construction

At December 31, 2025, Georgia Power had recorded approximately $3.1 billion of combined capital costs, excluding AFUDC, for the projects reflected in the table below approved through the 2023 IRP Update and the approved certification requests in September and December 2025. The total certified amounts related to these projects are approximately $19.5 billion, excluding

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AFUDC. Georgia Power is required to file periodic construction monitoring reports with the Georgia PSC through commercial operation. The ultimate outcome of these matters cannot be determined at this time.

Resource/Project	Approximate Nameplate Capacity<br><br>(MW)	Projected COD
Projects Under Construction at December 31, 2025
Battery Energy Storage
McGrau Ford Phase 1	265	Fourth quarter 2026
Twiggs County	200	Fourth quarter 2027
Wadley	260	Fourth quarter 2027
Plant Bowen Phase 1	250	Fourth quarter 2028
Plant Bowen Phase 2	250	Fourth quarter 2029
South Hall	250	Fourth quarter 2028
Plant Wansley	500	Fourth quarter 2028
Plant Yates Phase 1	320	Fourth quarter 2028
Plant Yates Phase 2	250	Fourth quarter 2028
Thomson	500	Fourth quarter 2029
Hammond Phase 2	193	Fourth quarter 2030
Plant McIntosh	250	Fourth quarter 2030
Various facilities	500	Second quarter 2026 through fourth quarter 2026
Solar with Battery Energy Storage
Laurens County	200	Fourth quarter 2028
Plant Mitchell	150	Fourth quarter 2028
Combined Cycle
Plant Bowen Unit 7	741	Fourth quarter 2029
Plant Bowen Unit 8	741	Second quarter 2030
Plant McIntosh Unit 12	757	Fourth quarter 2030
Plant Wansley Unit 10	727	Fourth quarter 2029
Plant Wansley Unit 11	727	Second quarter 2030
Combustion Turbine
Plant Yates Unit 8(*)	442	Fourth quarter 2026
Plant Yates Unit 9(*)	442	Second quarter 2027
Plant Yates Unit 10(*)	442	Third quarter 2027

(*)Pursuant to the 2023 IRP Update, cost recovery over the certified amount is limited.

Mississippi Power

Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Recoverable 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 preliminary report filing in November of the preceding year and the PEP Evaluation Report, which includes the current year PEP projected filing and the previous year PEP lookback filing, filed in March of the subsequent year. The annual PEP preliminary report filing is an informational report indicating whether a revenue adjustment is needed for the preceding 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.

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In June 2023 and June 2024, the Mississippi PSC approved Mississippi Power's annual retail PEP filings for 2023 and 2024, respectively, with no change in retail rates. On June 17, 2025, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2025, resulting in an annual increase in revenues of approximately 4.0%, or $41 million, primarily due to increases in investment and depreciation. In accordance with the PEP rate schedule, an increase of 2.0% of total retail revenues, or approximately $22 million, became effective with the first billing cycle of April 2025, and the remaining approximately $19 million became effective with the first billing cycle of July 2025.

On November 17, 2025, Mississippi Power submitted its annual preliminary retail PEP filing for 2026 to the Mississippi PSC, which requested a 1.8%, or $20 million, annual increase in revenues. In accordance with the PEP rate schedule, the rate increase became effective with the first billing cycle of January 2026, subject to refund. The Mississippi PSC is expected to render a final decision in the second quarter 2026. The ultimate outcome of this matter cannot be determined at this time.

Integrated Resource Plans

In 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 31, 2028. On July 8, 2025, Mississippi Power extended 50 MWs of its affiliate PPA with Georgia Power for an additional year through December 31, 2029. See "Georgia Power – Integrated Resource Plans – Certification Requests" herein for additional information.

In April 2024, Mississippi Power filed its 2024 IRP with the Mississippi PSC. The Mississippi PSC did not note any deficiencies within the prescribed 120-day review period; therefore, the filing was concluded. The 2024 IRP included a schedule to retire Plant Watson Unit 4 (268 MWs) and Plant Greene County Units 1 and 2 (206 MWs based on 40% ownership) and to retire early Plant Daniel Units 1 and 2 (502 MWs based on 50% ownership), all by the end of 2028, which is consistent with the completion of the initial term of Mississippi Power's affiliate PPA with Georgia Power. On January 9, 2025, Mississippi Power notified the Mississippi PSC of its intent to extend the retirement date of Plant Daniel Unit 2 and potentially extend the retirement dates of other fossil steam units beyond their current 2028 retirement dates in order to serve recently signed economic development loads of approximately 600 MWs. Mississippi Power has since acquired FP&L's 50% ownership interest in Plant Daniel Units 1 and 2 as described under "Plant Daniel" herein. In 2026, in compliance with its IRP requirements, Mississippi Power is expected to file a mid-point update to its 2024 IRP with the Mississippi PSC.

On February 12, 2026, Mississippi Power filed a request with the Mississippi PSC to convert Plant Daniel Unit 2 from a coal-fired unit to a natural gas-fired unit. Conversion of the unit is projected to be completed in 2029.

The remaining net book value of Plant Daniel Units 1 and 2 was approximately $465 million at December 31, 2025, 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 a 2020 order. The Plant Watson and Plant Greene County units are expected to be fully depreciated upon retirement.

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

Plant Daniel

In November 2024, Mississippi Power entered into an agreement with FP&L to acquire FP&L's 50% ownership interest in Plant Daniel Units 1 and 2. On January 7, 2025, the Mississippi PSC approved Mississippi Power's request for (i) the inclusion of the acquired assets and the associated costs at Plant Daniel in Mississippi Power's retail rate base, upon completion of the transaction, (ii) the establishment of a new regulatory liability account in which all of the proceeds to be paid by FP&L will be recorded, and (iii) Mississippi Power's ability to amortize that regulatory liability by charging certain expenditures against it. On June 19, 2025, the Florida PSC issued a final order approving the transfer of FP&L's 50% ownership interest in Plant Daniel Units 1 and 2 to Mississippi Power. On July 30, 2025, Mississippi Power completed the acquisition of FP&L's 50% ownership interest in Plant Daniel Units 1 and 2 and, as part of the acquisition, received approximately $36 million from FP&L, which was recorded as a regulatory liability being amortized to offset incremental costs as authorized by the Mississippi PSC. As part of the agreement, FP&L retained responsibility for environmental remediation and decommissioning liabilities related to its prior ownership interest.

Environmental Compliance Overview Plan

The Mississippi PSC has authorized Mississippi Power to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations.

In April 2023, May 2024, and April 2025, the Mississippi PSC approved Mississippi Power's annual ECO Plan filings, resulting in increases in revenues of approximately $3 million annually effective with the first billing cycle of May 2023, $9 million

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annually effective with the first billing cycle of June 2024, and $6 million annually effective with the first billing cycle of May 2025, respectively.

On February 13, 2026, Mississippi Power submitted its annual ECO Plan filing to the Mississippi PSC, which requested a $2 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. In February 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. On January 7, 2025, the Mississippi PSC approved Mississippi Power's request for no change in retail fuel revenues effective with the first billing cycle of February 2025. The approved filing included the deferral of approximately $25 million of under recovered fuel costs as of October 2024. On January 13, 2026, the Mississippi PSC approved Mississippi Power's request to increase retail fuel revenues by $40 million annually effective with the first billing cycle of February 2026. The approved filing included the deferral of approximately $31 million of under recovered fuel costs as of October 2025, 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, 2025, Mississippi Power had $40 million of deferred under recovered retail fuel clause revenues related to higher recoverable fuel costs and its fuel-hedging program on its balance sheet. At December 31, 2024, Mississippi Power had $32 million of deferred under recovered retail fuel clause revenues primarily associated with its fuel-hedging program and $32 million of over recovered retail fuel clause revenues primarily related to lower recoverable fuel costs on its 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 2024, 2025, and 2026, annual revenues under the wholesale MRA fuel rate decreased $4 million, decreased $19 million, and increased $23 million, respectively. At December 31, 2025 and 2024, wholesale MRA fuel costs were under recovered $6 million and over recovered $19 million, respectively, and were included in other current assets and other current liabilities, respectively, on Mississippi Power's balance sheets. The wholesale MB fuel rate did not change materially in any period presented. The wholesale MB fuel cost recovery was immaterial for both periods presented.

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.

Ad Valorem Tax Adjustment

Mississippi Power annually establishes an ad valorem tax adjustment factor that is approved by the Mississippi PSC. Any changes are not expected to have a significant effect on Mississippi Power's net income but will affect operating cash flows. Effective with the first billing cycle of June 2023, July 2024, and September 2025, the Mississippi PSC approved changes in annual revenues collected through the ad valorem tax adjustment factor resulting in a $7 million decrease, a $5 million decrease, and a $7 million increase, respectively.

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). 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.

Mississippi Power's net retail SRR accrual, which includes carrying costs and previously included amortization of related excess deferred income tax benefits, was $13.5 million in 2025, $12.6 million in 2024, and $11.7 million in 2023. At December 31, 2025 and 2024, the retail property damage reserve balance was $57 million and $52 million, respectively, and is included in other regulatory liabilities, deferred on Mississippi Power's balance sheets.

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In 2023, the Mississippi PSC approved Mississippi Power's annual SRR filing, with no change in retail rates. Mississippi Power's minimum annual SRR accrual was increased from $8.3 million to $11.7 million. In April 2024, the Mississippi PSC approved Mississippi Power's annual SRR filing to the Mississippi PSC, with no change in retail rates. Mississippi Power's minimum annual SRR accrual was increased from $11.7 million to $12.6 million. On June 17, 2025, the Mississippi PSC approved Mississippi Power's annual SRR filing for 2025, with no change in retail rates. Mississippi Power's minimum annual SRR accrual increased from $12.6 million to $13.5 million and the target property damage reserve balance increased from $75 million to $125 million. Mississippi Power will continue to record the minimum annual accrual until the target property damage reserve balance of $125 million is met.

Reliability Reserve Accounting Order

Based on an order from the Mississippi PSC, Mississippi Power is authorized to maintain a retail reliability reserve to offset future generation, transmission, and distribution reliability-related expenditures for use in a future year. Mississippi Power may make accruals to the retail 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 retail reliability reserve during the current year.

During 2025, 2024, and 2023, Mississippi Power accrued $13 million, $21 million, and $11 million, respectively, to the retail reliability reserve. On June 17, 2025, the Mississippi PSC approved Mississippi Power's use of a portion of its retail reliability reserve balance during 2025, through its annual PEP filing. As a result, Mississippi Power utilized the retail reliability reserve in the amount of $10.9 million during 2025 for reliability-related generation, transmission, and distribution expenses. See "Performance Evaluation Plan" herein for information regarding approval of the annual PEP filing.

At December 31, 2025, Mississippi Power's retail reliability reserve balance was $59 million, of which $9 million is included in other regulatory liabilities, current and $50 million is included in other regulatory liabilities, deferred on Mississippi Power's balance sheets. At December 31, 2024, Mississippi Power's retail reliability reserve balance was $57 million and is included in other regulatory liabilities, deferred on Mississippi Power's balance sheets.

Excess Accumulated Deferred Income Tax Accounting Order

On January 13, 2026, the Mississippi PSC approved an accounting order authorizing Mississippi Power to accelerate the amortization of approximately $21 million of a regulatory liability associated with certain federal excess accumulated deferred income taxes resulting from the Tax Reform Legislation. The flowback will be determined in a future rate proceeding. The ultimate outcome of this matter cannot be determined at this time.

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, 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 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, 2025, Mississippi Power is serving approximately 394 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.

In May 2024, the FERC issued an order accepting Mississippi Power's request for an $8 million increase in annual wholesale base revenues under the MRA tariff, effective May 29, 2024, subject to refund. On April 3, 2025, the FERC approved a settlement agreement filed by Mississippi Power and Cooperative Energy in December 2024. The settlement agreement provided for (i) a $1 million increase in annual wholesale base revenues and a refund to customers of approximately $4 million, (ii) a rate escalation of 2.5% on an annual basis in periods subsequent to December 31, 2024 and continuing through the end of the SSA on December 31, 2035, and (iii) a waiver of rights by Mississippi Power and Cooperative Energy to file for any changes in non-fuel rates through the end of the term of the SSA.

Southern Company Gas

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

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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 price levels for natural gas and general economic conditions that may impact customers' ability to pay for natural gas consumed. 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, 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:

	Nicor<br><br>Gas	Atlanta Gas<br><br>Light	Virginia<br><br>Natural Gas	Chattanooga<br><br>Gas
Authorized ROE at December 31, 2025	9.60%	10.25%	9.85%	9.80%
Weather normalization mechanisms(a)			ü	ü
Decoupled, including straight-fixed-variable rates(b)	ü	ü	ü
Regulatory infrastructure program rate(c)		ü	ü	ü
Bad debt rider(d)	ü		ü	ü
Energy efficiency plan(e)	ü		ü
Annual base rate adjustment mechanism(f)		ü		ü
Year of last base rate case decision	2025	2019	2025	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, Virginia Natural Gas has a separate rate rider that provides 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 2025 for all gas distribution operations were $1.9 billion.

The following table and discussions provide updates on the infrastructure replacement programs and capital projects at the natural gas distribution utilities at December 31, 2025. These programs are risk-based and designed to update and replace cast iron, bare

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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 2025		Capital Expenditures Since Project Inception		Pipe<br>Installed Since<br>Project Inception	Scope of<br>Program	Program Duration	Last<br>Year of Program
			(in millions)				(miles)	(miles)	(years)
Virginia Natural Gas	SAVE	Rider	$	72	$	633	620	938	18	2029
Atlanta Gas Light	System Reinforcement Rider	Rider	131		410		43	N/A	6	2027
Chattanooga Gas	Pipeline Replacement Program	Rate Base	13		41		37	73	10	2031
			$	216	$	1,084	700	1,011

Virginia Natural Gas

The SAVE program, an accelerated infrastructure replacement program, allows Virginia Natural Gas to continue replacing aging pipeline infrastructure. The program included authorized annual investments of $70 million in each of 2023 and 2024, with a total potential variance of up to $5 million allowed for the program, for a maximum total investment over the previous six-year term (2019 through 2024) of $365 million.

In June 2024, the Virginia Commission approved the extension of the existing SAVE program through 2029. The extension of the program 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.

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 2025, Virginia Natural Gas is recovering program costs incurred prior to January 1, 2025 through base rates. Program costs incurred subsequent to January 1, 2025 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.

Atlanta Gas Light

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 recovered through rates related to allowed, but not incurred, costs were 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 expected to be fully recovered through GRAM and base rates by the end of 2027. The Georgia PSC reviewed 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 $25 million annually for strategic economic development projects approved by the Georgia PSC.

The Georgia PSC also approved a new System Reinforcement Rider for authorized large pressure improvement and system reliability projects. Capital investments for the years 2022 through 2024 related to the System Reinforcement Rider totaled $279 million.

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 (i-CDP).

Chattanooga Gas

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.

In June 2025, the Tennessee Public Utilities Commission approved an extension of Chattanooga Gas' pipeline replacement program from seven to 10 years.

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Nicor Gas

Illinois legislation allowed Nicor Gas to provide more widespread safety and reliability enhancements to its distribution system through 2023 and stipulated that rate increases to customers as a result of any infrastructure investments did 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 recovered program costs incurred through a separate rider and base rates. See "Rate Proceedings – Nicor Gas" herein for additional information.

In 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 2023 of $38 million ($28 million after tax) associated with the disallowance of capital investments placed in service in 2019. The disallowances are reflected on the statements of income as an $8 million reduction to revenues and $30 million in estimated loss on regulatory disallowance. Later in 2023, the Illinois Commission denied a rehearing request filed by Nicor Gas, and Nicor Gas filed a notice of appeal with the Illinois Appellate Court. In November 2024, the Illinois Appellate Court upheld the Illinois Commission's review of the QIP capital investments by Nicor Gas for calendar year 2019 under the QIP rider apart from one immaterial item. In December 2024, Nicor Gas filed a petition for leave to appeal $14 million of the 2019 QIP disallowances with the Illinois Supreme Court, which was denied on March 26, 2025. This matter is now concluded and had no impact on the financial statements for the period ended December 31, 2025.

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
		(in millions)
2015 – 2018	Complete	$	1,246		$	—
2019	Complete	415			32			June 2023
2020	Filed March 2021	402		(a)
2021	Filed March 2022	392		(a)
2022	Filed March 2023	408		(a)	6		(b)	November 2023
2023	Filed March 2024	365		(a)	25		(b)	November 2023
		$	3,228		$	63

(a)Capital investments are subject to the required QIP annual review proceeding; years 2020 through 2023 are pending with the Illinois Commission.

(b)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.

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, 2025 and 2024, the over recovered balance was $158 million and $193 million, respectively, which is included in natural gas cost over recovery on Southern Company's and Southern Company Gas' balance sheets.

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Rate Proceedings

Nicor Gas

In 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 an ROE of 9.51% and an equity ratio of 50.00%.

In connection with Nicor Gas' 2023 general base rate case proceeding, the Illinois Commission disallowed $127 million of capital investments that have been completed or were planned to be completed through December 31, 2024. This amount is comprised of $31 million for capital investments placed in service in 2022 and 2023 under the Investing in Illinois program and $96 million for other transmission and distribution capital investments. Nicor Gas recorded a pre-tax charge to income in 2023 of $58 million ($44 million after tax) associated with the disallowances. The disallowances are reflected on the statements 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. In January 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 2023 base rate case decision. In February 2024, Nicor Gas filed a notice of appeal with the Illinois Appellate Court related to the Illinois Commission's rate case ruling. On December 1, 2025, the Illinois Appellate Court upheld the Illinois Commission's decision regarding certain capital investment disallowances in Nicor Gas' 2023 general base rate case proceeding. On December 22, 2025, Nicor Gas filed a petition for rehearing with the Illinois Appellate Court specifically addressing $43 million of the base rate case disallowances.

On November 19, 2025, the Illinois Commission approved a $168 million annual base rate increase for Nicor Gas, which became effective December 2, 2025. The base rate increase was based on an ROE of 9.60% and an equity ratio of 50.00%.

Additionally, the Illinois Commission excluded $120 million of capital investments included in the base rate case filing that have been incurred or are expected to be incurred through December 31, 2026. Nicor Gas analyzed the Illinois Commission's order and recorded a pre-tax charge to income in the fourth quarter 2025 of $63 million ($47 million after tax) associated with excluded capital investments that have been incurred. The disallowances are reflected on the statements of income in estimated loss on regulatory disallowance.

On January 6, 2026, 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 19, 2025 base rate case decision. On January 14, 2026, Nicor Gas filed a petition for review with the Illinois Appellate Court related to the Illinois Commission's rate case ruling. It remains Nicor Gas' position that it has met its evidentiary burden to demonstrate that the amount and the timing of such capital investments are prudent and reasonable and that such capital investments should be included in base rates.

On January 9, 2026, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $221 million increase in annual base rate revenues. The requested increase is based on a projected test year for the 12-month period ending December 31, 2027, an ROE of 10.35%, and an equity ratio of 54.6%. The Illinois Commission is expected to rule on the requested increase within the 11-month statutory time limit, after which rate adjustments will be effective.

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

Atlanta Gas Light

The Georgia PSC evaluates Atlanta Gas Light's earnings against an 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%.

In 2021, Atlanta Gas Light filed its 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.

Also in 2021, the Georgia PSC approved a stipulation between Atlanta Gas Light and the staff of the Georgia PSC, under which, for the years 2022 through 2024, Atlanta Gas Light would incrementally reduce its combined GRAM and System Reinforcement Rider request by 10% through Atlanta Gas Light's GRAM mechanism, which resulted in a reduction of $7 million for 2023 and $9 million for 2024. The stipulation also provided for $1.7 billion of total capital investment for the years 2022 through 2024.

In December 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. In December 2024, the Georgia PSC approved Atlanta Gas Light's annual

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GRAM filing, which included annual base rate increases of $72 million, $73 million, and $74 million effective January 1, 2025, 2026, and 2027, respectively.

In July 2024, the Georgia PSC approved a stipulation related to Atlanta Gas Light's 2024 i-CDP, 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 cost to implement the programs. The i-CDP allows capital investments totaling approximately $0.6 billion annually for the years 2025 through 2027 with related revenue requirement recovery through either the annual GRAM filing or the System Reinforcement Rider surcharge adjustment. Additionally, the Georgia PSC approved a surcharge recovery mechanism for capital projects related to municipal, county, and Georgia Department of Transportation infrastructure work. Rate changes associated with the new surcharge will be based on requests filed annually on September 1. If approved, new rates will become effective January 1 of the following year.

Virginia Natural Gas

In 2023, the Virginia Commission approved a stipulation related to Virginia Natural Gas' 2022 general base rate case filing, which allowed for a $48 million increase in annual base rate revenues based on an 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 implemented September 1, 2023 and the interim rates were completed during the fourth quarter 2023.

On December 17, 2025, the Virginia Commission approved a stipulation related to Virginia Natural Gas' August 2024 general base rate case filing. The approved stipulation provides for a $40 million increase in annual base rate revenues, including the recovery of investments under the SAVE program, an ROE of 9.85%, and an equity ratio of 49.35%. Interim rates became effective January 1, 2025, subject to refund, based on Virginia Natural Gas' original requested increase of approximately $63 million. Refunds to customers related to the difference between the approved rates implemented December 31, 2025 and the interim rates will be administered during the first quarter 2026.

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 2027.

	December 31, 2025		December 31, 2024
	(in millions)
Atlanta Gas Light	$	4	$	11
Virginia Natural Gas	9		10
Chattanooga Gas	7		7
Total	$	20	$	28

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 each of these matters cannot be determined at this time.

Southern Company

On July 11, 2025, a purported class action complaint was filed in the U.S. District Court for the District of Maryland against two nuclear consulting companies and all U.S. commercial nuclear power operators, or affiliated entities, including Southern Company. The purported class of plaintiffs includes all persons employed in nuclear power generation by the defendants, including nuclear operators, nuclear engineers, and nuclear technicians, from May 1, 2003 to the present. The complaint alleges that, since at least May 2003, the nuclear power industry conspired to fix and suppress employee compensation for nuclear power generation employees in violation of federal antitrust law. Although not named as defendants, other entities are accused of having

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participated in the plaintiffs' alleged conspiracy. The plaintiffs seek to recover, among other relief, unspecified monetary damages, including treble damages and attorneys' fees, and injunctive relief. On October 15, 2025, Southern Company moved to dismiss the complaint. On November 6, 2025, the plaintiffs filed an amended complaint naming Southern Nuclear, among others, as a defendant. On December 19, 2025, Southern Company and Southern Nuclear filed a motion to dismiss the amended complaint. An adverse outcome could have a material impact on Southern Company's financial statements.

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. In 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 were 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. Later in 2023, the plaintiff, a former SCS employee, filed an amended complaint, again alleging certain violations of the False Claims Act. The plaintiff sought to recover all damages incurred personally and on behalf of the federal government caused by the defendants' alleged violations, as well as treble damages and attorneys' fees, among other relief. In February 2024, the defendants moved to dismiss the amended complaint. In August 2024, the court granted the defendants' motion in part and denied it in part, dismissing the plaintiff's False Claims Act count along with its accompanying treble damages and attorneys' fees but allowing the employment retaliation claim to proceed. In October 2024, the plaintiff requested interlocutory appeal of the court's decision, which was denied on February 25, 2025, and the defendants asserted counterclaims for conversion and misappropriation of trade secrets. In November 2024, the defendants filed a motion for judgment on the pleadings on the plaintiff's employment retaliation claim. In December 2024, the plaintiff filed a motion to dismiss the defendants' counterclaims. On July 15, 2025, the court denied the plaintiff's motion to dismiss the defendants' counterclaims and the defendants' motion for judgment on the pleadings. On August 6, 2025, the plaintiff asserted a counterclaim against the defendants. On September 8, 2025, the defendants renewed their motion for judgment on the pleadings. On November 12, 2025, the parties reached an agreement in principle to resolve the lawsuit. On January 20, 2026, the court entered an order dismissing the lawsuit. The resolution does not have a material impact on Southern Company's or Mississippi Power's financial statements.

Alabama Power

In 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 surface impoundment 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. Later in 2022, Alabama Power filed a motion to dismiss the case. In January 2024, the lawsuit was dismissed without prejudice by the U.S. District Court judge. In February 2024, the plaintiff filed a motion to reconsider, which was denied by the U.S. District Court judge in July 2024. In August 2024, the plaintiff filed a notice of appeal in the U.S. Court of Appeals for the Eleventh Circuit challenging the denial of the motion to reconsider the order of dismissal.

In 2023, the EPA issued a Notice of Potential Violations (NOPV) associated with Alabama Power's plan to close the Plant Barry surface impoundment. In September 2024, Alabama Power reached a settlement with the EPA resolving two of the three allegations in the NOPV related to the groundwater monitoring system and the emergency action plan at the Plant Barry surface impoundment. The settlement did not resolve the EPA's allegation relating to Alabama Power's plan to close the Plant Barry surface impoundment. Alabama Power has affirmed to the EPA its position that it is in compliance with CCR requirements.

On July 29, 2025, Coosa Riverkeeper filed a citizen suit in the U.S. District Court for the Northern District of Alabama alleging that Alabama Power's closure of the Plant Gadsden surface impoundment utilizing a closure-in-place methodology violates the RCRA and regulations governing CCR. Among other relief requested, Coosa Riverkeeper seeks declaratory judgment that Alabama Power is in violation of RCRA and regulations governing CCR, and preliminary and injunctive relief to require

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Alabama Power to close the CCR unit and operate a groundwater monitoring system in a different manner to satisfy RCRA and the regulations governing CCR requirements. On September 29, 2025, Alabama Power filed a motion to dismiss the citizen suit.

These matters could have a material impact on Alabama Power's and Southern Company's financial statements, including ARO estimates and cash flows. See Note 6 for a discussion of Alabama Power's ARO liabilities.

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 all periods presented, Georgia Power recovered approximately $5 million through the ECCR tariff for environmental remediation.

Southern Company Gas is subject to environmental remediation liabilities associated with former manufactured gas plant sites. Southern Company Gas' accrued environmental remediation liability at December 31, 2025 and 2024 was based on the estimated cost of environmental investigation and remediation associated with these sites.

At December 31, 2025 and 2024, 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, 2025 or 2024.

	Southern<br><br>Company		Georgia<br><br>Power		Southern<br><br>Company Gas
	(in millions)
At December 31, 2025:
Environmental remediation liability:
Other current liabilities	$	34	$	14	$	20
Accrued environmental remediation	207		—		207
Under recovered environmental remediation costs:
Other regulatory assets, current	$	28	$	5	$	23
Other regulatory assets, deferred	214		8		206
At December 31, 2024:
Environmental remediation liability:
Other current liabilities	$	37	$	13	$	24
Accrued environmental remediation	198		—		198
Under recovered environmental remediation costs:
Other regulatory assets, current	$	37	$	5	$	32
Other regulatory assets, deferred	212		11		201

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

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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 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 June 2024 and August 2024, the Court of Federal Claims entered final judgments on damages in the third and fourth round of lawsuits against the U.S. government, respectively, awarding Alabama Power a total of approximately $100 million and Georgia Power a total of approximately $121 million (based on its ownership interests), which represent claims for the period from January 1, 2011 through December 31, 2019.

In December 2024, the Alabama PSC directed Alabama Power to return the award, which was reflected as a regulatory liability at December 31, 2024, to customers through bill credits during the months of January, February, and March 2025. During the third quarter 2024, Georgia Power credited the award to accounts where the original costs were charged, which reduced rate base, fuel, and cost of service for the benefit of customers, as previously authorized by the Georgia PSC. As a result of this regulatory treatment, there was no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income.

On September 5, 2025, Alabama Power and Georgia Power filed their fifth 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, 2020 through December 31, 2024. 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, 2025 for any potential recoveries from the pending lawsuits.

The final outcome of this matter 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 $16.3 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 $500 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.

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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, 2025 under the NEIL policies would be $61 million and $84 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, cash flows, 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

Mississippi Power

Kemper County Energy Facility

In 2023, 2024, and 2025, 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 $17 million pre-tax ($12 million after tax) in 2023, $12 million pre-tax ($9 million after tax) in 2024, and $13 million pre-tax ($10 million after tax) in 2025. The pre-tax charges are included in other operations and maintenance expenses on the statements of income. Dismantlement of the abandoned gasifier-related assets was completed at the end of 2025. Site restoration activities for the mine are substantially complete, and any additional costs are expected to be immaterial. See "General Litigation Matters – Southern Company and Mississippi Power" herein for information regarding litigation associated with the Kemper County energy facility.

Department of Revenue Audit

On March 31, 2025, the Mississippi Department of Revenue (Mississippi DOR) completed an audit of sales and use taxes paid by Mississippi Power from October 2019 to July 2024 and entered a final assessment, indicating a total amount due of $29 million, including associated penalties and interest. Mississippi Power did not agree with the audit findings and filed an administrative appeal with the Mississippi DOR on May 29, 2025. On November 4, 2025, Mississippi Power and the Mississippi DOR reached a settlement agreement on an assessment of approximately $13 million including associated penalties and interest, $11 million of which was previously paid by Mississippi Power. On November 5, 2025, Mississippi Power made a final $2 million payment. This matter is now concluded.

Pursuant to an accounting order approved by the Mississippi PSC on January 13, 2026, Mississippi Power deferred $9 million of the agreed-upon assessment related to taxes and associated interest to a regulatory asset for disposition in a future rate proceeding.

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 consolidated statements of income and in purchased power, non-affiliates in Georgia Power's statements of

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income. Georgia Power's capacity payments related to this commitment totaled $3 million, $4 million, and $3 million in 2025, 2024, and 2023, respectively. At December 31, 2025, Georgia Power's estimated long-term obligations related to this commitment totaled $34 million, consisting of $2 million annually for 2026 through 2030 and $24 million thereafter.

See Note 9 for information regarding PPAs accounted for as leases.

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, 2025, the capitalization of SEGCO consisted of $49 million of equity and $70 million of long-term debt that matures in November 2026, on which the annual interest requirement is derived from a variable rate index. SEGCO had no short-term debt outstanding at December 31, 2025. 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, with Georgia Power's railcar leases being terminated as of June 2024.

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. Included in the wholesale electric revenues of the traditional electric operating companies and Southern Power are revenues associated with affiliate transactions. These revenues are generated through long-term PPAs or short-term energy sales made in accordance with the IIC, as approved by the FERC. Amounts related to these affiliate revenues are eliminated in consolidation for Southern Company. See Note 1 under "Affiliate Transactions" and "Revenues" for additional information. See Notes 9 and 14 for additional information on revenue accounted for under lease and derivative accounting guidance, respectively.

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The following table disaggregates revenue from contracts with customers for the periods presented:

	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br><br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
2025
Operating revenues
Retail electric revenues
Residential	$	8,601	$	3,209	$	5,064	$	328	$	—	$	—
Commercial	6,995		2,071		4,582		342		—		—
Industrial	4,045		1,704		1,984		357		—		—
Other	123		10		104		9		—		—
Total retail electric revenues	19,764		6,994		11,734		1,036		—		—
Natural gas distribution revenues
Residential	2,164		—		—		—		—		2,164
Commercial	527		—		—		—		—		527
Transportation	1,424		—		—		—		—		1,424
Industrial	44		—		—		—		—		44
Other	295		—		—		—		—		295
Total natural gas distribution revenues	4,454		—		—		—		—		4,454
Wholesale electric revenues
PPA energy revenues	1,430		248		245		13		966		—
PPA capacity revenues	637		134		146		69		356		—
Non-PPA revenues	299		194		64		484		220		—
Total wholesale electric revenues	2,366		576		455		566		1,542		—
Other natural gas revenues
Gas marketing services	569		—		—		—		—		569
Other	12		—		—		—		—		12
Total other natural gas revenues	581		—		—		—		—		581
Other revenues	1,777		265		805		55		18		—
Total revenue from contracts with customers	28,942		7,835		12,994		1,657		1,560		5,035
Other revenue sources(*)	611		400		(363)		38		638		9
Total operating revenues	$	29,553	$	8,235	$	12,631	$	1,695	$	2,198	$	5,044

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	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br><br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
2024
Operating revenues
Retail electric revenues
Residential	$	8,276	$	3,133	$	4,835	$	308	$	—	$	—
Commercial	6,585		2,042		4,219		324		—		—
Industrial	3,892		1,742		1,808		342		—		—
Other	124		13		102		9		—		—
Total retail electric revenues	18,877		6,930		10,964		983		—		—
Natural gas distribution revenues
Residential	1,753		—		—		—		—		1,753
Commercial	417		—		—		—		—		417
Transportation	1,295		—		—		—		—		1,295
Industrial	34		—		—		—		—		34
Other	316		—		—		—		—		316
Total natural gas distribution revenues	3,815		—		—		—		—		3,815
Wholesale electric revenues
PPA energy revenues	1,059		206		94		4		778		—
PPA capacity revenues	641		108		136		63		400		—
Non-PPA revenues	226		139		5		375		230		—
Total wholesale electric revenues	1,926		453		235		442		1,408		—
Other natural gas revenues
Gas marketing services	507		—		—		—		—		507
Other	18		—		—		—		—		18
Total other natural gas revenues	525		—		—		—		—		525
Other revenues	1,621		240		721		52		37		—
Total revenue from contracts with customers	26,764		7,623		11,920		1,477		1,445		4,340
Other revenue sources(*)	(40)		(69)		(589)		(14)		569		116
Total operating revenues	$	26,724	$	7,554	$	11,331	$	1,463	$	2,014	$	4,456

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	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br><br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
2023
Operating revenues
Retail electric revenues
Residential	$	7,309	$	2,904	$	4,105	$	300	$	—	$	—
Commercial	5,860		1,928		3,624		308		—		—
Industrial	3,613		1,721		1,558		334		—		—
Other	112		12		91		9		—		—
Total retail electric revenues	16,894		6,565		9,378		951		—		—
Natural gas distribution revenues
Residential	1,981		—		—		—		—		1,981
Commercial	505		—		—		—		—		505
Transportation	1,184		—		—		—		—		1,184
Industrial	45		—		—		—		—		45
Other	324		—		—		—		—		324
Total natural gas distribution revenues	4,039		—		—		—		—		4,039
Wholesale electric revenues
PPA energy revenues	1,107		234		87		20		790		—
PPA capacity revenues	624		156		51		45		376		—
Non-PPA revenues	250		65		35		407		409		—
Total wholesale electric revenues	1,981		455		173		472		1,575		—
Other natural gas revenues
Gas marketing services	528		—		—		—		—		528
Other	31		—		—		—		—		31
Total other natural gas revenues	559		—		—		—		—		559
Other revenues	1,355		213		578		39		55		—
Total revenue from contracts with customers	24,828		7,233		10,129		1,462		1,630		4,598
Other revenue sources(*)	425		(183)		(11)		12		559		104
Total operating revenues	$	25,253	$	7,050	$	10,118	$	1,474	$	2,189	$	4,702

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

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Contract Balances

The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers at December 31, 2025 and 2024:

	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br><br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
Accounts Receivable
At December 31, 2025	$	3,139	$	716	$	1,278	$	115	$	132	$	864
At December 31, 2024	3,048		783		1,244		113		106		660
Contract Assets
At December 31, 2025	$	294	$	3	$	160	$	—	$	—	$	67
At December 31, 2024	323		3		184		—		—		72
Contract Liabilities
At December 31, 2025	$	213	$	6	$	75	$	—	$	2	$	—
At December 31, 2024	140		11		34		—		2		3

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 received cash advances totaling $68 million from a third-party financial institution to fund work performed. 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, 2025 and 2024, Southern Company's unregulated distributed generation business had contract assets of $63 million and $67 million, respectively, and contract liabilities of $132 million and $95 million, respectively, for outstanding performance obligations, all of which are expected to be satisfied within one year.

Revenues recognized in 2025 and 2024, which were included in contract liabilities at December 31, 2024 and 2023, respectively, were $102 million and $98 million, respectively, for Southern Company, $24 million and immaterial, respectively, for Georgia Power, 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

Southern Company's subsidiaries 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. 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, 2025 are expected to be recognized as follows:

	2026		2027		2028		2029		2030		Thereafter
	(in millions)
Southern Company	$	1,060	$	583	$	408	$	385	$	389	$	2,685
Alabama Power	48		5		4		1		1		6
Georgia Power	65		45		35		21		21		76
Mississippi Power(*)	66		69		73		12		—		—
Southern Power(*)	350		348		358		368		367		2,603

(*)Includes performance obligations related to affiliate PPAs with Georgia Power. See Note 1 under "Affiliate Transactions" for additional information.

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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, 2025 and 2024:

At December 31, 2025:	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br><br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
Electric utilities:
Generation	$	63,533	$	17,912	$	27,192	$	2,969	$	14,986	$	—
Transmission	17,814		7,057		9,651		1,064		—		—
Distribution	31,718		11,058		19,083		1,577		—		—
General/other	6,854		2,888		3,532		362		48		—
Electric utilities' plant in service	119,919		38,915		59,458		5,972		15,034		—
Southern Company Gas:
Natural gas transportation and distribution	20,177		—		—		—		—		20,177
Storage facilities	1,954		—		—		—		—		1,954
Other	1,967		—		—		—		—		1,967
Southern Company Gas plant in service	24,098		—		—		—		—		24,098
Other plant in service	2,097		—		—		—		—		—
Total plant in service	$	146,114	$	38,915	$	59,458	$	5,972	$	15,034	$	24,098		At December 31, 2024:	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br><br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
---	---	---	---	---	---	---	---	---	---	---	---	---
	(in millions)
Electric utilities:
Generation	$	61,292	$	16,801	$	26,089	$	2,946	$	14,920	$	—
Transmission	16,280		6,449		8,800		989		—		—
Distribution	28,678		10,373		16,887		1,418		—		—
General/other	6,547		2,878		3,260		344		41		—
Electric utilities' plant in service	112,797		36,501		55,036		5,697		14,961		—
Southern Company Gas:
Natural gas transportation and distribution	18,896		—		—		—		—		18,896
Storage facilities	1,748		—		—		—		—		1,748
Other	1,694		—		—		—		—		1,694
Southern Company Gas plant in service	22,338		—		—		—		—		22,338
Other plant in service	2,008		—		—		—		—		—
Total plant in service	$	137,143	$	36,501	$	55,036	$	5,697	$	14,961	$	22,338

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

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operating cycle, or 18 months for Plant Vogtle Units 1 through 4 and 24 months for Plant Hatch Units 1 and 2. Georgia Power's amortization period begins the month the refueling outage starts.

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, 2025 and 2024, deferred cloud implementation costs, net of amortization, which are included in other current assets and other deferred charges and assets on the Registrants' balance sheets, were as follows:

	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br><br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
Deferred cloud implementation costs, net:
At December 31, 2025	$	231	$	73	$	87	$	10	$	9	$	21
At December 31, 2024	321		92		111		13		12		35

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. Amortization of deferred cloud implementation costs recognized in 2025, 2024, and 2023 was immaterial for Mississippi Power, Southern Power, and Southern Company Gas and was as follows for the other Registrants:

	Southern Company		Alabama Power		Georgia Power
	(in millions)
2025	$	53	$	17	$	20
2024	56		17		22
2023	46		11		19

See Note 2 under "Regulatory Assets and Liabilities" 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.

Depreciation and Amortization

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 2025, 2024, and 2023 were as follows:

	2025		2024		2023
Alabama Power	4.0	%	4.2	%	4.1	%
Georgia Power	3.4	%	3.4	%	3.8	%
Mississippi Power	3.6	%	3.3	%	3.4	%
Southern Company Gas	3.0	%	2.9	%	2.7	%

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. On April 1, 2025, the Mississippi PSC approved a stipulation between Mississippi Power and the Mississippi Public Utilities Staff for an $8 million increase in total annual depreciation effective January 1, 2025. 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.

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At December 31, 2025 and 2024, accumulated depreciation for Southern Company and Southern Company Gas consisted of utility plant in service totaling $42.3 billion and $38.9 billion, respectively, for Southern Company and $6.0 billion and $5.6 billion, respectively, for Southern Company Gas, as well as other plant in service totaling $1.2 billion and $1.2 billion, respectively, for Southern Company and $265 million and $252 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 10 years for transportation equipment, five to 40 years for storage facilities, and up to 78 years for other assets. Useful lives for the assets of Southern Company's other non-utility subsidiaries range up to 40 years.

Southern Power

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 consolidated 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. In 2025 and 2024, Southern Power recorded accelerated depreciation related to equipment being replaced associated with wind repowering projects of $307 million and $9 million, respectively. See Note 15 under "Southern Power – Wind Repowering Projects" for additional information.

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Joint Ownership Agreements

At December 31, 2025, the Registrants' percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation were as follows:

Facility (Type)	Percent<br>Ownership			Plant in Service		Accumulated<br>Depreciation		CWIP
				(in millions)
Alabama Power
Plant Greene County (natural gas) Units 1 and 2	60.0	%	(a)	$	190	$	163	$	2
Plant Miller (coal) Units 1 and 2	91.8		(b)	2,181		901		19
Georgia Power
Plant Hatch (nuclear) Units 1 and 2	50.1	%	(c)	$	1,477	$	593	$	137
Plant Vogtle (nuclear) Units 1 and 2	45.7		(c)	3,598		2,326		240
Plant Vogtle (nuclear) Units 3 and 4	45.7		(c)	7,979		250		86
Plant Scherer (coal) Units 1 and 2	8.4		(c)	286		152		11
Plant Scherer (coal) Unit 3	75.0		(c)	1,323		793		56
Rocky Mountain (pumped storage)	25.4		(d)	186		166		18
Mississippi Power
Plant Greene County (natural gas) Units 1 and 2	40.0	%	(a)	$	119	$	94	$	1
Southern Company Gas
Dalton Pipeline (natural gas pipeline)	50.0	%	(e)	$	273	$	36	$	1

(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 Jacksonville Electric Authority. 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)Jointly owned with OPC, which is the operator of the plant.

(e)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 $130 million at December 31, 2025, 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.

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

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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 state and federal CCR rules, principally surface impoundments. 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 Plants Hatch and Vogtle). 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<br><br>Company		Alabama<br><br>Power		Georgia<br><br>Power		Mississippi<br><br>Power		Southern<br><br>Power(*)
	(in millions)
Balance at December 31, 2023	$	10,317	$	4,158	$	5,665	$	168	$	150
Liabilities incurred	130		8		120		—		2
Liabilities settled	(566)		(254)		(270)		(17)		—
Accretion expense	400		153		232		5		7
Cash flow revisions	(347)		(7)		(332)		(8)		—
Balance at December 31, 2024	$	9,934	$	4,058	$	5,415	$	148	$	159
Liabilities incurred	6		—		6		—		—
Liabilities settled	(634)		(269)		(321)		(19)		—
Accretion expense	393		154		223		6		7
Cash flow revisions	(98)		(264)		204		(11)		—
Balance at December 31, 2025	$	9,601	$	3,679	$	5,527	$	124	$	166

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

Following initial criticality for Plant Vogtle Unit 4 on February 14, 2024, Georgia Power recorded AROs of approximately $118 million. See "Nuclear Decommissioning" herein and Note 2 under "Georgia Power – Nuclear Construction" for additional information.

In September 2024, Georgia Power completed updated decommissioning cost site studies for Plants Hatch and Vogtle Units 1 through 4. The estimated cost of decommissioning based on the studies resulted in a decrease in Georgia Power's ARO liability of $389 million. See "Nuclear Decommissioning" herein for additional information.

In November 2024, Georgia Power recorded a net increase of approximately $60 million to its AROs related to the CCR Rule and the related state rule resulting from changes in estimates, including higher future inflation rates and the timing of closure activities.

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In June 2025, Alabama Power recorded a net decrease of approximately $257 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.

Also in June 2025, Mississippi Power, as a joint owner of Alabama Power's Plant Greene County Units 1 and 2, recorded a net decrease of approximately $13 million to its AROs related to the CCR Rule and the related Alabama state rule resulting from changes in estimates, including lower future inflation rates, higher discount rates, and timing of closure activities.

In November 2025, Georgia Power recorded a net increase of approximately $200 million to its AROs related to the CCR Rule and related state rule resulting from higher inflation rates, changes in estimates, and timing of closure activities.

The cost estimates for AROs related to the disposal of CCR are based on information at December 31, 2025 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 surface impoundments. The cost estimates for Georgia Power and Mississippi Power are based on a combination of closure-in-place for some surface impoundments 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.

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Investment securities in the Funds at December 31, 2025 and 2024 were as follows:

	Southern<br><br>Company		Alabama<br>Power		Georgia<br>Power
	(in millions)
At December 31, 2025:
Equity securities	$	1,609	$	963	$	646
Debt securities	1,082		363		719
Other securities	254		214		40
Total investment securities in the Funds	$	2,945	$	1,540	$	1,405
At December 31, 2024:
Equity securities	$	1,413	$	848	$	565
Debt securities	976		335		641
Other securities	232		202		30
Total investment securities in the Funds	$	2,621	$	1,385	$	1,236

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 2025, 2024, and 2023 are shown in the table below.

	Southern<br><br>Company		Alabama<br>Power		Georgia<br>Power
	(in millions)
Fair value increases
2025	$	348	$	191	$	157
2024	229		143		86
2023	281		157		124
Unrealized gains
At December 31, 2025	$	216	$	111	$	105
At December 31, 2024	113		64		49
At December 31, 2023	241		119		122

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 $11 million and $12 million at December 31, 2025 and 2024, 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.

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At December 31, 2025 and 2024, the accumulated provisions for the external decommissioning trust funds were as follows:

	2025		2024
	(in millions)
Alabama Power
Plant Farley	$	1,540	$	1,385
Georgia Power
Plant Hatch	$	825	$	735
Plant Vogtle Units 1 and 2	519		460
Plant Vogtle Units 3 and 4	61		41
Total	$	1,405	$	1,236

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, 2025 based on the most current studies were as follows:

	Alabama Power		Georgia Power(*)
	Plant<br>Farley		Plant<br><br>Hatch		Plant Vogtle<br><br>Units 1 and 2		Plant Vogtle<br><br>Unit 3 and 4
Most current study year	2023		2024		2024		2024
Decommissioning periods:
Beginning year	2037		2034		2047		2062
Completion year	2087		2088		2092		2074
	(in millions)
Site study costs:
Radiated structures	$	1,402	$	795	$	674	$	599
Spent fuel management	513		306		255		88
Non-radiated structures	133		77		107		89
Total site study costs	$	2,048	$	1,178	$	1,036	$	776

(*)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 2.3% for Plant Vogtle Units 3 and 4 and an estimated trust earnings rate of 7.0% for Plant Farley, 4.5% for Plants Hatch and Vogtle Units 1 and 2, and 4.3% for Plant Vogtle Units 3 and 4.

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.

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, including the ARP Extension Period, 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 annual decommissioning cost for ratemaking is $8 million for Plant Vogtle Unit 3. Effective May 1, 2024, as approved under the

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Prudency Stipulation, Georgia Power's annual decommissioning cost for ratemaking is $8 million for Plant Vogtle Unit 4. 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.

Southern Company

At December 31, 2025 and 2024, Southern Holdings had equity method investments totaling $124 million and $128 million, respectively, primarily related to investments in venture capital funds focused on energy and utility investments. The net loss from these investments totaled $18 million for the year ended December 31, 2025. Earnings/losses from these investments were immaterial for the years ended December 31, 2024 and 2023.

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 was previously expected to occur by December 31, 2028. However, upon further analysis, Alabama Power, in conjunction with Georgia Power, now expects to operate Plant Gaston Units 1 through 4 through December 31, 2034. See Note 2 under "Georgia Power – Integrated Resource Plans – 2025 IRP" 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 an ROE. The share of purchased power included in purchased power, affiliates in the statements of income totaled $130 million in 2025, $115 million in 2024, and $112 million in 2023 for Alabama Power and $133 million in 2025, $118 million in 2024, and $115 million in 2023 for Georgia Power.

SEGCO paid dividends of $24 million in 2025, $20 million in 2024, and $25 million in 2023, 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.

Southern Power

Variable Interest Entities

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

SP Solar

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

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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.

At December 31, 2025 and 2024, SP Solar had total assets of $5.2 billion and $5.4 billion, respectively, total liabilities of $360 million and $372 million, respectively, and noncontrolling interests of $0.9 billion and $1.0 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.

Southern Power consolidates SP Solar, as the primary beneficiary, since it controls the most significant activities of the entity, including operating and maintaining its assets. Certain transfers and sales of the assets in the VIE 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.

SP Wind

SP Wind was owned by Southern Power and three financial investors through December 31, 2025. A wholly-owned subsidiary of Southern Power owned 100% of the Class B membership interests and the three financial investors owned 100% of the Class A membership interests. In July 2025, Southern Power notified the Class A members of its intent to exercise the option to purchase all Class A membership interests in the SP Wind tax equity partnership under the terms of the limited liability agreement. On December 31, 2025, Southern Power purchased 100% of the noncontrolling Class A membership interests for approximately $282 million. Subsequent to the transaction, Southern Power became the sole owner of SP Wind and its portfolio of eight operating wind facilities, and the partnership was dissolved. See Note 15 under "Southern Power – Purchase of Renewable Facility Interests" for additional information.

Prior to this transaction, SP Wind qualified as a VIE since the structure of the arrangement was similar to a limited partnership and the Class A members did not have substantive kick-out rights against Southern Power. At December 31, 2024, SP Wind had total assets of $2.0 billion, total liabilities of $177 million, and noncontrolling interests of $35 million.

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, 2025 and 2024, the other VIEs had total assets of $1.6 billion, total liabilities of $236 million and $224 million, respectively, and noncontrolling interests of $617 million and $691 million, respectively. Under the terms of the partnership agreements, distributions of all available cash are required each month or quarter and additional distributions require partner consent.

Equity Method Investments

During 2023, Southern Power sold its remaining equity method investments in wind projects and received proceeds totaling $50 million. Earnings (loss) from these investments, including the gains associated with the sales, were immaterial for 2023.

Southern Company Gas

The carrying amounts of Southern Company Gas' equity method investments at December 31, 2025 and 2024 were as follows:

Investment Balance	At December 31, 2025		At December 31, 2024
	(in millions)
SNG	$	1,148	$	1,245
Other	34		34
Total	$	1,182	$	1,279

The earnings from Southern Company Gas' equity method investment related to SNG were $127 million in 2025, $146 million in 2024, and $139 million in 2023. The earnings from Southern Company Gas' other equity method investments were immaterial for all periods presented.

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8. FINANCING

Long-term Debt

Details of long-term debt at December 31, 2025 and 2024 are provided in the following table:

	At December 31, 2025		Balance Outstanding at<br>December 31,
	Maturity	Weighted Average<br>Interest Rate	2025		2024
			(in millions)
Southern Company
Senior notes(a)	2026-2075	4.38%	$	49,922	$	44,862
Junior subordinated notes	2027-2085	4.82%	9,922		7,389
FFB loans(b)	2026-2044	2.88%	4,617		4,703
Revenue bonds(c)	2026-2063	3.14%	3,323		3,379
First mortgage bonds(d)	2026-2065	3.93%	2,925		2,775
Medium-term notes	2026-2027	7.03%	84		84
Other long-term debt	2026-2045	4.56%	603		209
Finance lease obligations(e)			768		287
Unamortized fair value adjustment			249		275
Unamortized debt premium (discount), net			(56)		(58)
Unamortized debt issuance expenses			(488)		(419)
Total long-term debt			71,869		63,486
Less: Amount due within one year(a)			6,220		4,718
Total long-term debt excluding amount due within one year			$	65,649	$	58,768
Alabama Power
Senior notes	2026-2075	4.02%	$	10,725	$	9,875
Revenue bonds(c)	2026-2063	3.11%	1,300		1,300
Other long-term debt	2026-2030	5.32%	65		61
Finance lease obligations(e)			12		4
Unamortized debt premium (discount), net			(20)		(19)
Unamortized debt issuance expenses			(69)		(67)
Total long-term debt			12,013		11,154
Less: Amount due within one year			625		655
Total long-term debt excluding amount due within one year			$	11,388	$	10,499
Georgia Power
Senior notes	2026-2074	4.48%	$	13,692	$	11,292
Junior subordinated notes	2077	5.00%	270		270
FFB loans(b)	2026-2044	2.88%	4,617		4,703
Revenue bonds(c)	2026-2062	3.16%	1,923		1,968
Other long-term debt	2026	4.59%	400		—
Finance lease obligations(e)			734		261
Unamortized debt premium (discount), net			(17)		(21)
Unamortized debt issuance expenses			(127)		(123)
Total long-term debt			21,492		18,350
Less: Amount due within one year			1,370		966
Total long-term debt excluding amount due within one year			$	20,122	$	17,384

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	At December 31, 2025		Balance Outstanding at<br>December 31,
	Maturity	Weighted Average<br>Interest Rate	2025		2024
			(in millions)
Mississippi Power
Senior notes	2026-2055	4.40%	$	1,675	$	1,575
Revenue bonds(c)	2027-2052	2.94%	101		111
Finance lease obligations(e)			19		14
Unamortized debt premium (discount), net			1		2
Unamortized debt issuance expenses			(10)		(9)
Total long-term debt			1,786		1,693
Less: Amount due within one year			66		12
Total long-term debt excluding amount due within one year			$	1,720	$	1,681
Southern Power
Senior notes(a)	2026-2046	4.65%	$	2,963	$	2,695
Unamortized debt premium (discount), net			(6)		(4)
Unamortized debt issuance expenses			(17)		(11)
Total long-term debt			2,940		2,680
Less: Amount due within one year(a)			587		500
Total long-term debt excluding amount due within one year			$	2,353	$	2,180
Southern Company Gas
Senior notes	2026-2051	4.46%	$	5,999	$	5,375
First mortgage bonds(d)	2026-2065	3.93%	2,925		2,775
Medium-term notes	2026-2027	7.03%	84		84
Other long-term debt	2026-2045	3.81%	68		68
Unamortized fair value adjustment			249		275
Unamortized debt premium (discount), net			(11)		(9)
Unamortized debt issuance expenses			(40)		(37)
Total long-term debt			9,274		8,531
Less: Amount due within one year			531		302
Total long-term debt excluding amount due within one year			$	8,743	$	8,229

(a)Includes a fair value gain (loss) related to Southern Power's foreign currency hedge on its euro-denominated senior notes of $23 million at December 31, 2025, which is also included in amount due within one year, and $(45) million at December 31, 2024.

(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.

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

	Southern<br><br>Company(a)		Alabama<br><br>Power(b)		Georgia<br><br>Power(c)		Mississippi<br><br>Power		Southern<br><br>Power(d)		Southern<br><br>Company<br><br>Gas
	(in millions)
2026	$	6,211	$	628	$	1,371	$	66	$	564	$	530
2027	3,407		552		1,017		11		—		154
2028	5,464		108		1,619		358		—		600
2029	1,993		1		862		2		—		150
2030	4,103		651		704		52		550		150

(a)See notes (b), (c), and (d) below.

(b)Alabama Power's 2026 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 that began in 2024 and $100 million aggregate principal amount of Series 2025B Floating Rate Senior Notes due August 15, 2075 that are repayable at the option of the holders at certain dates beginning in 2026. 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, 2025.

(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. Georgia Power's 2026 maturities include approximately $117 million aggregate principal amount of Series 2024C Floating Rate Senior Notes due November 15, 2074 that are repayable at the option of the holders at certain dates that began in 2025. As a result, the senior notes are classified as securities due within one year on the balance sheets of Southern Company and Georgia Power at December 31, 2025.

(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.

In 2021, Georgia Power made the final borrowings under the FFB Credit Facilities and no further borrowings are permitted. During 2025, Georgia Power made principal amortization payments of $86 million under the FFB Credit Facilities. At December 31, 2025 and 2024, Georgia Power had $4.6 billion and $4.7 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 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) loss of necessary governmental approvals for operation of Plant Vogtle Units 3 and 4; (ii) loss of regulation by the Georgia PSC; (iii) cost disallowances by the Georgia PSC that could have a material adverse effect on Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facilities; (iv) certain material casualty losses or a governmental taking of Plant Vogtle Units 3 and 4; or (v) loss of access to the intellectual property rights necessary to operate Plant Vogtle Units 3 and 4. 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.

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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.

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, 2025 and 2024. 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 (2019 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 2019 Equity Units and Southern Company issued approximately 25.2 million shares of common stock and received proceeds of $1.725 billion. In August 2024, Southern Company repaid at maturity the $862.5 million 2019A RSNs. At December 31, 2025 and 2024, the 2019B RSNs were included on Southern Company's consolidated balance sheets in long-term debt.

In November 2025, Southern Company issued 40 million 2025 Series A Equity Units (2025 Equity Units), initially in the form of corporate units (Corporate Units), at a stated amount of $50 per Corporate Unit, for a total of $2 billion. Net proceeds from the issuance were approximately $1.965 billion. Southern Company used a portion of the net proceeds to repurchase (i) approximately $674.4 million aggregate principal amount of the Series 2023A 3.875% Convertible Senior Notes due December 15, 2025 (Series 2023A Convertible Senior Notes) and (ii) approximately $342.0 million aggregate principal amount of the Series 2024A 4.50% Convertible Senior Notes due June 15, 2027 (Series 2024A Convertible Senior Notes). See "Convertible Senior Notes" herein for additional information regarding the repurchase of convertible senior notes.

Each Corporate Unit is comprised of (i) a stock purchase contract, which obligates the holder to purchase from Southern Company, no later than December 15, 2028, a certain number of shares of Southern Company's common stock for $50 in cash (Stock Purchase Contract), (ii) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2025B Remarketable Senior Notes due 2030 (Series 2025B RSNs), and (iii) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2025C Remarketable Senior Notes due 2033 (together with the Series 2025B RSNs, the 2025 RSNs). Southern Company has agreed to remarket the 2025 RSNs in 2028, at which time each interest rate on the 2025 RSNs will reset at the applicable market rate. Holders may choose to either remarket their 2025 RSNs, receive the proceeds, and use those funds to settle the related Stock Purchase Contract or retain the 2025 RSNs and use other funds to settle the related Stock Purchase Contract. If the remarketing is unsuccessful, holders will have the right to put their 2025 RSNs to Southern Company at a price equal to the principal amount. The Corporate Units carry an annual distribution rate of 7.125% of the stated amount, which is comprised of a quarterly interest payment on the 2025 RSNs of 4.15% per year and a quarterly contract adjustment payment of 2.975% per year.

Each Stock Purchase Contract obligates the holder to purchase, and Southern Company to sell, for $50 a number of shares of Southern Company common stock determined based on the applicable market value (as determined under the related Stock Purchase Contract) in accordance with the conversion ratios set forth below (subject to anti-dilution adjustments):

•If the applicable market value equals or exceeds $116.44, 0.4294 shares.

•If the applicable market value is less than $116.44 but greater than $93.15, a number of shares equal to $50 divided by the applicable market value.

•If the applicable market value is less than or equal to $93.15, 0.5368 shares.

A holder's ownership interest in the 2025 RSNs is pledged to Southern Company to secure the holder's obligation under the related Stock Purchase Contract. If a holder of a Stock Purchase Contract chooses at any time to have its 2025 RSNs released from the pledge, such holder's obligation under such Stock Purchase Contract must be secured by a U.S. Treasury security equal to the aggregate principal amount of the 2025 RSNs. At the time of issuance, the 2025 RSNs were recorded on Southern

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Company's consolidated balance sheet as long-term debt and the present value of the contract adjustment payments of $173 million was recorded as a liability, representing the obligation to make contract adjustment payments, with an offsetting reduction to paid-in capital. The liability balance at December 31, 2025 was $173 million, of which $59 million was classified as current. The difference of $12 million between the face value and present value of the contract adjustment payments will be accreted to interest expense on the consolidated statements of income over the three-year period ending in 2028. The liability recorded for the contract adjustment payments is considered non-cash and excluded from the consolidated statements of cash flow. To settle the Stock Purchase Contracts, Southern Company will be required to issue a maximum of approximately 21.5 million shares of common stock (subject to anti-dilution adjustments and a make-whole adjustment if certain fundamental changes occur).

Convertible Senior Notes

In February 2023, Southern Company issued $1.5 billion aggregate principal amount of 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.

In May 2024, Southern Company issued $1.5 billion aggregate principal amount of Series 2024A Convertible Senior Notes.

In May 2025, Southern Company issued $1.65 billion aggregate principal amount of Series 2025A 3.25% Convertible Senior Notes due June 15, 2028 (Series 2025A Convertible Senior Notes). Southern Company used a portion of the proceeds from the Series 2025A Convertible Senior Notes to repurchase approximately $781.6 million of the $1.725 billion aggregate principal amount then outstanding of the Series 2023A Convertible Senior Notes and approximately $328.1 million of the $1.5 billion aggregate principal amount then outstanding of the Series 2024A Convertible Senior Notes, in each case, through privately negotiated transactions with a limited number of holders thereof.

In November 2025, using a portion the net proceeds from the 2025 Equity Units, Southern Company repurchased approximately an additional $674.4 million of the remaining approximately $943.4 million aggregate principal amount outstanding of the Series 2023A Convertible Senior Notes and approximately an additional $342.0 million of the remaining approximately $1.172 billion aggregate principal amount outstanding of the Series 2024A Convertible Senior Notes, in each case, through privately negotiated transactions with a limited number of holders thereof. See "Equity Units" herein for additional information.

Southern Company evaluated these repurchases and determined that all of the repurchased notes were accounted for as extinguishment of debt. As a result of these transactions, Southern Company recognized a total loss on extinguishment of debt of $252 million during 2025 within interest expense in the consolidated statements of income.

On December 15, 2025, the Series 2023A Convertible Senior Notes matured and Southern Company settled its related conversion obligations to holders by (i) paying cash in respect of the approximately $269.1 million aggregate principal amount remaining outstanding and (ii) issuing approximately 255 thousand shares of common stock for the excess of its conversion obligation over such principal amount. These shares were recognized at par value in paid-in capital on Southern Company's balance sheets.

Interest on the Series 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes is payable semiannually. The Series 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes will mature on June 15, 2027 and 2028, respectively, unless earlier converted or repurchased, but are not redeemable at the option of Southern Company. Both the Series 2024A Convertible Senior Notes and the Series 2025A 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.

Under the following circumstances, holders may convert their Series 2024A Convertible Senior Notes and their Series 2025A Convertible Senior Notes at their option prior to the close of business on the business day preceding March 15, 2027 and 2028, respectively:

•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 applicable conversion price of the Series 2024A Convertible Senior Notes or the Series 2025A Convertible Senior Notes, as the case may be, 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 applicable trading price per $1,000 principal amount of Series 2024A Convertible Senior Notes or Series 2025A Convertible Senior Notes, as the case may be, 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 applicable conversion rate on each such trading day; or

•upon the occurrence of certain corporate events specified in the respective supplemental indentures governing the Series 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes.

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On or after March 15, 2027 and 2028, for the Series 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes, respectively, a holder may convert all or any portion of its Series 2024A Convertible Senior Notes or its Series 2025A Convertible Senior Notes, as the case may be, at any time prior to the close of business on the second scheduled trading day immediately preceding the applicable maturity date regardless of the foregoing conditions.

Southern Company will settle conversions of the Series 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes by paying cash up to the aggregate principal amount of the Series 2024A Convertible Senior Notes and the Series 2025A 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 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes being converted. The Series 2024A Convertible Senior Notes are initially convertible at a rate of 10.8166 shares of common stock per $1,000 principal amount converted, which is approximately equal to $92.45 per share of common stock. The Series 2025A Convertible Senior Notes are initially convertible at a rate of 8.8077 shares of common stock per $1,000 principal amount converted, which is approximately equal to $113.54 per share of common stock. These conversion rates 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 respective supplemental indentures governing the Series 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes), Southern Company will, in certain circumstances, increase the applicable 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, other than an excluded fundamental change (each as defined in the respective supplemental indentures governing the Series 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes), holders of the Series 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes may require Southern Company to purchase all or a portion of their Series 2024A Convertible Senior Notes and their Series 2025A 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 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes to be purchased plus any accrued and unpaid interest.

Equity Distribution Agreement

In May 2024, Southern Company established an at-the-market program by entering into an equity distribution agreement pursuant to which it may sell, from time to time, up to an aggregate of 50 million shares of its common stock, including through forward sale contracts.

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The table below reflects shares of Southern Company common stock sold and settled under separate forward sale contracts with forward purchasers during the years ended December 31, 2025 and 2024.

Shares Sold	Initial Forward<br><br>Price Per Share	To be Settled On or<br><br>Before	Forward Price<br><br>Per Share Settled	Shares Issued to<br><br>Settle	Settlement Date
Sold during 2024
1,000,000	$86.5645	December 31, 2025	$86.8151	1,000,000	December 3, 2025
1,000,000	$87.9658	December 31, 2025	$88.1348	1,000,000	December 3, 2025
143,920	$83.3293	December 31, 2025	$83.0276	143,920	December 3, 2025
Sold during 2025
292,694	$83.3293	December 31, 2025	$83.0276	292,694	December 3, 2025
563,386	$87.9027	December 31, 2025	$88.0621	563,386	December 3, 2025
1,000,000	$88.7502	June 30, 2026	$88.8612	1,000,000	December 3, 2025
1,000,000	$88.7739	June 30, 2026	$88.8319	1,000,000	December 3, 2025
1,000,000	$91.2856	June 30, 2026	$91.3995	1,000,000	December 3, 2025
1,000,000	$89.1444	June 30, 2026	$89.1404	1,000,000	December 3, 2025
1,000,000	$88.8490	June 30, 2026	$88.8107	1,000,000	December 3, 2025
1,000,000	$88.8903	June 30, 2026	$88.7905	1,000,000	December 3, 2025
1,000,000	$90.9196	June 30, 2026	$90.8230	1,000,000	December 3, 2025
1,255,000	$91.0566	June 30, 2026	$90.9450	1,255,000	December 3, 2025
1,324,942	$88.7048	December 31, 2026	$88.7684	1,324,942	December 3, 2025
2,277,113	$88.3227	December 31, 2026	$88.2914	2,277,113	December 3, 2025
3,130,641(*)	$88.2823	December 31, 2026	$88.1976	2,060,000	December 3, 2025
3,255,866	$89.4692	December 31, 2026	N/A	N/A	N/A
3,850,000	$90.6617	December 31, 2026	N/A	N/A	N/A
2,470,306	$94.5394	June 30, 2027	N/A	N/A	N/A
2,314,487	$92.7805	June 30, 2027	N/A	N/A	N/A
1,590,200	$93.4524	June 30, 2027	N/A	N/A	N/A
4,000,000	$90.8141	June 30, 2027	N/A	N/A	N/A
2,346,903	$91.1610	June 30, 2027	N/A	N/A	N/A
2,876,034	$92.2437	June 30, 2027	N/A	N/A	N/A
3,015,668	$93.4521	June 30, 2027	N/A	N/A	N/A
911,448	$94.2411	June 30, 2027	N/A	N/A	N/A

(*)The total number of shares sold under this forward sale contract is 3,130,641, of which 2,060,000 shares were settled in December 2025. The remaining 1,070,641 shares sold under this contract are subject to be settled at a future date.

As of December 31, 2025, Southern Company had entered into separate forward sale contracts with forward purchasers for a total of 44,618,608 shares of common stock, all of which had been sold by the forward sellers. Of these shares, 16,917,055 shares had been settled under the forward sale contracts in the form of shares at the initial forward price adjusted for interest earned and dividends paid from the forward sale date to the settlement date. The net proceeds from the settlement of these shares were approximately $1.5 billion.

The total number of shares sold remaining under the forward sale contracts subject to be settled at a future date is 27,701,553. Each initial forward price is subject to adjustment under certain specified circumstances as specified in the respective forward sale contracts. Southern Company may settle each of the forward transactions in shares, cash, or net shares.

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Bank Credit Arrangements

At December 31, 2025, committed credit arrangements with banks were as follows:

	Expires
Company	2026		2027		2029		2030		Total		Unused		Expires<br><br>within<br><br>One Year
	(in millions)
Southern Company parent(a)	$	—	$	500	$	—	$	2,500	$	3,000	$	2,999	$	—
Alabama Power(b)	15		—		650		700		1,365		1,365		15
Georgia Power(c)	—		—		—		2,050		2,050		2,042		—
Mississippi Power(a)	—		125		—		150		275		275		—
Southern Power(a)(d)	—		—		—		600		600		600		—
Southern Company Gas(e)	—		—		—		1,600		1,600		1,598		—
SEGCO	30		—		—		—		30		30		30
Southern Company	$	45	$	625	$	650	$	7,600	$	8,920	$	8,909	$	45

(a)Arrangement expiring in 2030 represents a $3.25 billion combined arrangement for Southern Company, Mississippi Power, and Southern Power allowing for flexible sublimits. Pursuant to the combined facility, the allocations among Southern Company, Mississippi Power, and Southern Power may be adjusted.

(b)Includes $15 million expiring in 2026 at Alabama Property Company, a wholly-owned subsidiary of Alabama Power, of which $15 million was unused at December 31, 2025. Alabama Power is not party to this arrangement.

(c)Georgia Power had $26 million of letters of credit outstanding under an uncommitted letter of credit facility at December 31, 2025.

(d)Does not include Southern Power Company's $75 million and $100 million continuing letter of credit facilities for standby letters of credit, expiring in 2027 and 2028, respectively, of which $17 million and $4 million, respectively, was unused at December 31, 2025. In addition, Southern Power Company had $23 million of letters of credit outstanding under an uncommitted letter of credit facility at December 31, 2025. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.

(e)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 2030. Southern Company Gas' committed credit arrangement expiring in 2030 also includes $800 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 2030, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. 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 accelerated. Southern Company's, 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, 2025, 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, 2025, outstanding variable rate demand revenue bonds of the traditional electric operating companies with allocated liquidity support totaled approximately $1.5 billion (comprised of approximately $796 million at Alabama Power, $667 million at Georgia Power, and $58 million at Mississippi Power). In addition, at December 31, 2025, Alabama Power and Georgia Power had approximately $280 million and $384 million, respectively, of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months. Alabama Power's $280 million of fixed rate revenue bonds are classified as securities due

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within one year on its balance sheets as they are not covered by long-term committed credit. All other 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, 2025 and 2024, 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.

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, 2025				Notes Payable at December 31, 2024
	Amount<br>Outstanding		Weighted Average<br>Interest Rate		Amount<br>Outstanding		Weighted Average<br>Interest Rate
	(in millions)				(in millions)
Southern Company
Commercial paper	$	722	3.9	%	$	1,138	4.7	%
Short-term bank debt	—		—		200		5.3
Total	$	722	3.9	%	$	1,338	4.8	%
Georgia Power
Commercial paper	$	160	3.9	%	$	—	—	%
Short-term bank debt	—		—		200		5.3
Total	$	160	3.9	%	$	200	5.3	%
Mississippi Power
Commercial paper	$	—	—	%	$	14	4.6	%
Southern Power
Commercial paper	$	138	3.9	%	$	—	—	%
Southern Company Gas
Commercial paper:
Southern Company Gas Capital	$	209	3.9	%	$	283	4.7	%
Nicor Gas	216		3.9		172		4.6
Total	$	425	3.9	%	$	455	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.

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Outstanding Classes of Capital Stock

Southern Company

Common Stock

Stock Issued

During 2025, Southern Company issued approximately 22.5 million shares of common stock primarily through forward sale contract settlements and dividend reinvestment and employee equity compensation and savings plans.

See "Equity Units" and "Equity Distribution Agreement" herein for additional information.

Shares Reserved

At December 31, 2025, a total of 203 million shares were reserved for issuance pursuant to the Southern Investment Plan, employee savings plans, the Equity and Incentive Compensation Plan (which includes performance share units and restricted stock units as discussed in Note 12), an at-the-market program (including forward sale contracts), and the convertible senior notes (as discussed under "Convertible Senior Notes" herein). Of the shares reserved, 23 million shares are available for awards under the Equity and Incentive Compensation Plan at December 31, 2025.

Diluted Earnings Per Share

For Southern Company, the difference in computing basic and diluted earnings per share (EPS) is attributable to awards outstanding under stock-based compensation plans, forward sale contracts pursuant to the equity distribution agreement, convertible senior notes, and the 2025 Equity Units. EPS dilution resulting from stock-based compensation plans and the forward sale contracts is determined using the treasury stock method, and EPS dilution resulting from the convertible senior notes is determined using the net share settlement method. See Note 12 and "Convertible Senior Notes," "Equity Distribution Agreement," and "Equity Units" herein for additional information. Shares used to compute diluted EPS were as follows:

	Average Common Stock Shares
	2025	2024	2023
	(in millions)
As reported shares	1,103	1,096	1,092
Effect of stock-based compensation	5	6	6
Effect of forward sale contracts	1	—	—
Diluted shares	1,109	1,102	1,098

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

For 2025 and 2024, the dilution resulting from convertible senior notes was immaterial.

Alabama Power

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

Georgia Power

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

Mississippi Power

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, 2025, consolidated retained earnings included $7.5 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.

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See Note 7 under "Southern Power" for information regarding the distribution requirements for certain Southern Power subsidiaries.

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, 2025, the amount of Southern Company Gas' subsidiary retained earnings available for dividend payment totaled $1.8 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 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, 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.

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:

	Southern<br>Company		Alabama<br>Power		Georgia<br>Power		Mississippi<br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
At December 31, 2025
Electric generating units(*)	$	1,064	$	53	$	1,793	$	—	$	—	$	—
Real estate/land	931		3		37		1		541		111
Communication towers	134		3		5		—		—		20
Railcars	74		39		26		9		—		—
Other	49		6		3		19		—		—
Total	$	2,252	$	104	$	1,864	$	29	$	541	$	131
At December 31, 2024
Electric generating units(*)	$	672	$	56	$	1,509	$	—	$	—	$	—
Real estate/land	834		3		45		2		540		20
Communication towers	118		2		4		—		—		21
Railcars	64		31		29		4		—		—
Other	52		2		2		16		—		—
Total	$	1,740	$	94	$	1,589	$	22	$	540	$	41

(*)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

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real estate leases have remaining terms of up to 18 years while the land leases have remaining terms of up to 41 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 15 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 three and 22 years. Georgia Power has several PPAs with Southern Power that Georgia Power accounts for as leases with a lease obligation of $782 million and $893 million at December 31, 2025 and 2024, 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 both the Georgia PSC and the FERC. Amounts related to the affiliate PPAs are eliminated in consolidation for Southern Company.

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 existed primarily in railcar leases at Alabama Power and Georgia Power. The remaining railcar leases containing residual value guarantees expired in 2023 for Alabama Power and in June 2024 for Georgia Power. The amounts probable of being paid under those guarantees were included in the lease payments, and all such amounts were immaterial at December 31, 2024.

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 ROU asset.

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Balance sheet amounts recorded for operating and finance leases were as follows:

	Southern<br><br>Company		Alabama<br>Power		Georgia<br>Power		Mississippi<br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
At December 31, 2025
Operating Leases
Operating lease ROU assets, net	$	1,358	$	86	$	1,120	$	9	$	479	$	85
Operating lease obligations - current	$	197	$	14	$	170	$	4	$	31	$	8
Operating lease obligations - non-current	1,287		78		960		6		510		123
Total operating lease obligations(*)	$	1,484	$	92	$	1,130	$	10	$	541	$	131
Finance Leases
Finance lease ROU assets, net	$	742	$	12	$	710	$	18	$	—	$	—
Finance lease obligations - current	$	16	$	3	$	29	$	1	$	—	$	—
Finance lease obligations - non-current	752		9		705		18		—		—
Total finance lease obligations	$	768	$	12	$	734	$	19	$	—	$	—
At December 31, 2024
Operating Leases
Operating lease ROU assets, net	$	1,386	$	84	$	1,331	$	8	$	484	$	38
Operating lease obligations - current	$	200	$	14	$	169	$	4	$	29	$	11
Operating lease obligations - non-current	1,253		76		1,159		4		511		30
Total operating lease obligations(*)	$	1,453	$	90	$	1,328	$	8	$	540	$	41
Finance Leases
Finance lease ROU assets, net	$	254	$	4	$	227	$	14	$	—	$	—
Finance lease obligations - current	$	9	$	1	$	20	$	1	$	—	$	—
Finance lease obligations - non-current	278		3		241		13		—		—
Total finance lease obligations	$	287	$	4	$	261	$	14	$	—	$	—

(*)Includes operating lease obligations related to PPAs at Southern Company, Alabama Power, and Georgia Power totaling $486 million, $53 million, and $1.1 billion, respectively, at December 31, 2025 and $567 million, $55 million, and $1.3 billion, respectively, at December 31, 2024.

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.

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Lease costs for 2025, 2024, and 2023, which includes both amounts recognized as operations and maintenance expense and amounts capitalized as part of the cost of another asset, were as follows:

	Southern<br>Company		Alabama<br>Power		Georgia<br>Power		Mississippi<br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
2025
Lease cost
Operating lease cost(*)	$	271	$	19	$	248	$	5	$	34	$	21
Finance lease cost:
Amortization of ROU assets	13		1		22		1		—		—
Interest on lease obligations	11		—		12		—		—		—
Total finance lease cost	24		1		34		1		—		—
Short-term lease costs	45		22		15		—		—		—
Variable lease cost	52		—		79		—		6		—
Total lease cost	$	392	$	42	$	376	$	6	$	40	$	21
2024
Lease cost
Operating lease cost(*)	$	248	$	19	$	190	$	4	$	27	$	12
Finance lease cost:
Amortization of ROU assets	20		2		23		1		—		—
Interest on lease obligations	15		—		15		1		—		—
Total finance lease cost	35		2		38		2		—		—
Short-term lease costs	37		15		15		—		—		—
Variable lease cost	48		(1)		77		—		4		—
Total lease cost	$	368	$	35	$	320	$	6	$	31	$	12
2023
Lease cost
Operating lease cost(*)	$	252	$	16	$	192	$	5	$	34	$	12
Finance lease cost:
Amortization of ROU assets	24		2		19		1		—		—
Interest on lease obligations	14		—		17		—		—		—
Total finance lease cost	38		2		36		1		—		—
Short-term lease costs	40		16		16		—		—		—
Variable lease cost	47		—		74		—		4		—
Total lease cost	$	377	$	34	$	318	$	6	$	38	$	12

(*)Includes operating lease costs related to PPAs at Southern Company, Alabama Power, and Georgia Power totaling $113 million, $5 million, and $222 million, respectively, in 2025, $108 million, $5 million, and $168 million, respectively, in 2024, and $112 million, $4 million, and $174 million, respectively, in 2023.

Georgia Power has variable lease payments that are based on the amount of energy produced by certain renewable generating facilities subject to PPAs, including $49 million, $45 million, and $42 million in 2025, 2024, and 2023, respectively, from finance leases which are included in purchased power on Georgia Power's statements of income, of which $23 million, $22 million, and $21 million was included in purchased power, affiliates in 2025, 2024, and 2023, respectively.

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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:

	Southern<br>Company		Alabama<br>Power		Georgia<br>Power		Mississippi<br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
2025
Other information
Cash paid for amounts included in the measurements of lease obligations:
Operating cash flows from operating leases	$	270	$	19	$	257	$	4	$	33	$	13
Operating cash flows from finance leases	11		—		17		—		—		—
Financing cash flows from finance leases	21		2		32		1		—		—
ROU assets obtained under operating leases	168		16		18		6		2		61
ROU assets obtained under finance leases	509		10		513		6		—		—
2024
Other information
Cash paid for amounts included in the measurements of lease obligations:
Operating cash flows from operating leases	$	243	$	19	$	186	$	4	$	33	$	12
Operating cash flows from finance leases	15		—		21		—		—		—
Financing cash flows from finance leases	11		2		23		1		—		—
ROU assets obtained under operating leases	146		11		609		—		10		1
Reassessment of ROU assets under operating leases	(7)		—		—		—		(7)		—
ROU assets obtained under finance leases	1		—		44		—		—		—
2023
Other information
Cash paid for amounts included in the measurements of lease obligations:
Operating cash flows from operating leases	$	253	$	17	$	199	$	5	$	33	$	12
Operating cash flows from finance leases	15		—		22		—		—		—
Financing cash flows from finance leases	18		2		16		1		—		—
ROU assets obtained under operating leases	100		30		26		1		7		7
ROU assets obtained under finance leases	3		3		18		—		—		—

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	Southern<br>Company		Alabama<br>Power		Georgia<br>Power		Mississippi<br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
At December 31, 2025
Weighted-average remaining lease term in years:
Operating leases	16.0		9.7		7.0		4.6		31.4		10.9
Finance leases	19.8		3.4		18.1		10.1		N/A		N/A
Weighted-average discount rate:
Operating leases	4.88	%	5.07	%	4.82	%	4.58	%	4.96	%	5.30	%
Finance leases	5.38	%	4.38	%	5.68	%	3.78	%	N/A		N/A
At December 31, 2024
Weighted-average remaining lease term in years:
Operating leases	16.4		10.2		7.9		4.3		32.3		6.8
Finance leases	16.0		2.7		10.1		10.9		N/A		N/A
Weighted-average discount rate:
Operating leases	4.73	%	5.04	%	4.73	%	3.83	%	4.88	%	3.84	%
Finance leases	4.86	%	4.05	%	5.8	%	2.74	%	N/A		N/A

Maturities of lease liabilities are as follows:

	At December 31, 2025
	Southern<br>Company		Alabama<br>Power		Georgia<br>Power		Mississippi<br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
Maturity Analysis
Operating leases:
2026	$	233	$	18	$	221	$	4	$	33	$	9
2027	217		15		218		2		29		15
2028	202		11		216		2		30		16
2029	168		9		195		1		30		15
2030	118		9		111		1		30		16
Thereafter	1,294		56		378		1		954		110
Total	2,232		118		1,339		11		1,106		181
Less: Present value discount	748		26		209		1		565		50
Operating lease obligations	$	1,484	$	92	$	1,130	$	10	$	541	$	131
Finance leases:
2026	$	33	$	3	$	47	$	2	$	—	$	—
2027	32		2		47		2		—		—
2028	44		2		59		2		—		—
2029	65		1		82		2		—		—
2030	67		1		63		2		—		—
Thereafter	1,130		6		985		14		—		—
Total	1,371		15		1,283		24		—		—
Less: Present value discount	603		3		549		5		—		—
Finance lease obligations	$	768	$	12	$	734	$	19	$	—	$	—

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.

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At December 31, 2025, Georgia Power has one affiliate PPA with Southern Power that has not yet commenced and will be accounted for as a lease. The PPA has a term of 10 years and is expected to commence in 2028. The estimated total obligation associated with this PPA is $63 million.

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 Alabama Power and Georgia Power, these arrangements also include PPAs related to electric generating units accounted for as operating leases with remaining terms of one year and up to 14 years, respectively. 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 13 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 21 years and PPAs related to battery energy storage facilities accounted for as sales-type leases with remaining terms of up to 16 years. Southern Company Gas is the lessor in operating leases related to gas pipelines with remaining terms of up to 17 years. For Southern Company, these arrangements also include PPAs related to fuel cells accounted for as operating leases with remaining terms of up to eight years.

Lease income for 2025, 2024, and 2023 was as follows:

	Southern<br>Company		Alabama<br><br>Power		Georgia<br><br>Power		Mississippi<br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
2025
Lease income - interest income on sales-type leases	$	23	$	—	$	—	$	14	$	9	$	—
Lease income - operating leases	145		7		29		3		148		36
Variable lease income	408		1		—		—		442		—
Total lease income	$	576	$	8	$	29	$	17	$	599	$	36
2024
Lease income - interest income on sales-type leases	$	24	$	—	$	—	$	15	$	9	$	—
Lease income - operating leases	136		9		28		3		88		36
Variable lease income	417		1		—		—		450		—
Total lease income	$	577	$	10	$	28	$	18	$	547	$	36
2023
Lease income - interest income on sales-type leases	$	24	$	—	$	—	$	14	$	10	$	—
Lease income - operating leases	164		35		29		2		85		37
Variable lease income	406		1		—		—		437		—
Total lease income	$	594	$	36	$	29	$	16	$	532	$	37

As part of its acquisition of the Lindsay Hill Generating Station, Alabama Power assumed an existing power sales agreement under which the full output of the generating facility remains committed to a non-affiliated third party through April 2027. These revenues are included above as lease income from operating leases. See Note 15 under "Alabama Power" for additional information.

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 is included in wholesale revenues for Alabama Power, Georgia Power, and Southern Power. Scheduled payments to be received under outdoor lighting contracts' initial terms, tolling arrangements, and PPAs accounted for as leases are presented in the following maturity analyses.

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The undiscounted cash flows expected to be received for in-service leased assets under the leases are as follows:

	At December 31, 2025
	Southern<br><br>Company		Mississippi<br><br>Power		Southern<br>Power
	(in millions)
2026	$	39	$	23	$	15
2027	38		22		15
2028	37		21		15
2029	36		20		15
2030	34		19		15
Thereafter	270		114		155
Total undiscounted cash flows	$	454	$	219	$	230
Net investment in sales-type lease(*)	286		130		152
Difference between undiscounted cash flows and discounted cash flows	$	168	$	89	$	78

(*)For Mississippi Power, included in other current assets ($10 million and $10 million at December 31, 2025 and 2024, respectively) and other property and investments ($120 million and $129 million at December 31, 2025 and 2024, respectively) on the balance sheets. For Southern Power, included in other current assets ($15 million and $15 million at December 31, 2025 and 2024, respectively) and net investment in sales-type leases ($137 million and $143 million at December 31, 2025 and 2024, respectively) on the balance sheets.

The undiscounted cash flows to be received under operating leases and contracts accounted for as operating leases are as follows:

	At December 31, 2025
	Southern<br>Company		Alabama<br>Power		Southern<br>Power		Southern<br><br>Company Gas
	(in millions)
2026	$	119	$	6	$	148	$	35
2027	111		5		150		28
2028	111		4		161		28
2029	116		4		164		28
2030	115		3		103		28
Thereafter	554		34		400		299
Total	$	1,126	$	56	$	1,126	$	446

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 contracts accounted for as operating leases at Georgia Power and Mississippi Power are immaterial.

Southern Company Leveraged Lease

At December 31, 2025, a subsidiary of Southern Holdings had one leveraged lease agreement, which relates to energy generation, with an expected remaining term of six years. Southern Company receives 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.

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 in July 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

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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 except for certain credit utilization and state apportionment results. 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:

	2025
	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company Gas
	(in millions)
Federal —
Current	$	139	$	110	$	99	$	57	$	71	$	28
Deferred	399		192		346		(6)		(133)		98
Total federal	538		302		445		51		(62)		126
State —
Current	94		95		32		(1)		(3)		32
Deferred	196		28		125		15		4		24
Total state	290		123		157		14		1		56
Total	$	828	$	425	$	602	$	65	$	(61)	$	182			2024
---	---	---	---	---	---	---	---	---	---	---	---	---
	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company Gas
	(in millions)
Federal —
Current	$	221	$	357	$	200	$	32	$	(112)	$	84
Deferred	387		(111)		211		2		106		86
Total federal	608		246		411		34		(6)		170
State —
Current	152		103		52		(1)		6		42
Deferred	209		11		140		14		(13)		46
Total state	361		114		192		13		(7)		88
Total	$	969	$	360	$	603	$	47	$	(13)	$	258

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	2023
	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br>Power		Mississippi<br>Power		Southern<br><br>Power		Southern<br><br>Company Gas
	(in millions)
Federal —
Current	$	54	$	242	$	205	$	49	$	(320)	$	62
Deferred	299		(257)		195		(26)		334		68
Total federal	353		(15)		400		23		14		130
State —
Current	41		82		37		1		(1)		24
Deferred	102		14		11		12		(1)		57
Total state	143		96		48		13		(2)		81
Total	$	496	$	81	$	448	$	36	$	12	$	211

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 or transferred 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 were $95 million for 2025 and were immaterial for 2024 and 2023. See "Cash Paid for Income Taxes" and "Deferred Tax Assets and Liabilities" herein for additional information.

Under current tax law, certain projects are eligible for ITCs. The Registrants use the deferral method to account for federal and state ITCs, whereby the ITCs are recorded as a deferred credit and amortized to income tax expense over the useful life of the respective asset. In accordance with regulatory requirements, certain state ITCs at Georgia Power are recognized as an income tax benefit in the year the credit is generated through the establishment of a regulatory asset. ITCs amortized in 2025, 2024, and 2023 were immaterial for the traditional electric operating companies and Southern Company Gas and were as follows for Southern Company and Southern Power:

	Southern Company		Southern Power
	(in millions)
2025	$	84	$	58
2024	109		58
2023	84		58

When Southern Company recognizes tax credits, the tax basis of the asset is reduced by 50% of the ITCs received, which, together with the deferred credit, results 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.

Georgia Power's 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 $31 million in 2025, $44 million in 2024, and $49 million in 2023.

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 $33 million in 2025, $32 million in 2024, and $26 million in 2023.

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Cash Paid for Income Taxes

The following table disaggregates income taxes paid, excluding credit transfers, (net of refunds) by federal, state, and foreign taxes for the periods presented:

	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br><br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company Gas
	(in millions)
2025
Federal	$	170	$	150	$	53	$	43	$	162	$	9
State	114		93		76		(1)		(14)		20
Total cash taxes paid	$	284	$	243	$	129	$	42	$	148	$	29
2024
Federal	$	123	$	289	$	(21)	$	51	$	(22)	$	53
State	53		98		7		—		(10)		6
Total cash taxes paid (received)	$	176	$	387	$	(14)	$	51	$	(32)	$	59
2023
Federal	$	78	$	256	$	178	$	52	$	(252)	$	71
State	51		59		42		—		(2)		20
Foreign	3		—		—		—		—		—
Total cash taxes paid (received)	$	132	$	315	$	220	$	52	$	(254)	$	91

Income taxes paid (net of refunds) exceeded 5% of total income taxes paid (net of refunds) in the following jurisdictions for the periods presented:

	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br><br>Power	Mississippi<br><br>Power	Southern<br><br>Power	Southern<br><br>Company Gas
	(in millions)
2025
State —
Alabama	$	92	$	91	$ (*)	$ (*)	$ (*)	$ (*)
Georgia	(*)		(*)		74	(*)	(11)	(*)
Oklahoma	(*)		(*)		(*)	(*)	(9)	(*)
Illinois	20		(*)		(*)	(*)	(*)	20
2024
State —
Alabama	$	99	$	98	$ (*)	$ (*)	$ (*)	$ (*)
Georgia	(35)		(*)		7	(*)	6	7
Oklahoma	(18)		(*)		(*)	(*)	(18)	(*)
2023
State —
Alabama	$	60	$	57	$ (*)	$ (*)	$ (*)	$ (*)
Georgia	(13)		(*)		42	(*)	(*)	8
Oklahoma	(9)		(*)		(*)	(*)	(*)	(*)
Illinois	13		(*)		(*)	(*)	(*)	13

(*)Jurisdiction is either not applicable or below the threshold for the period presented.

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Southern Power, in 2025, paid back $95 million and, in 2024 and 2023, received $71 million and $332 million, respectively, of cash related to federal ITCs under renewable energy initiatives. See "Deferred Tax Assets and Liabilities" herein for additional information.

Alabama Power, Georgia Power, and Southern Power have entered into transferability agreements with non-affiliated parties to sell ITCs and PTCs at a discount to the generated credit value in 2024, 2025, and 2026. During 2025, Alabama Power, Georgia Power, and Southern Power received cash of $80 million, $64 million, and $24 million, respectively, from credits transferred. During 2024, Georgia Power and Southern Power received cash of $11 million and $24 million, respectively, from credits transferred. The discount is recorded as a reduction in tax credits recognized in the financial statements and does not have a material impact on results of operations. The Southern Company system continues to explore the ability to efficiently monetize its tax credits through third-party transfer agreements.

Pursuant to the Vogtle Joint Ownership Agreements, Georgia Power paid $156 million in 2025, $131 million in 2024, and $39 million in 2023 to the other Vogtle Owners for advanced nuclear PTCs for Plant Vogtle Unit 3 and 4, which were utilized and not reflected as a reduction to current income tax expense. The gains recognized in all periods were recorded in income tax benefit and were immaterial.

Effective Tax Rate

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

A reconciliation of the federal statutory income tax rate to the effective income tax (benefit) rate is as follows:

	2025
	Southern<br><br>Company				Alabama<br><br>Power				Georgia<br>Power				Mississippi<br><br>Power				Southern<br><br>Power				Southern<br><br>Company Gas
	(in millions, except percentages)
Federal statutory rate	$	1,050	21.0	%	$	408	21.0	%	$	725	21.0	%	$	59	21.0	%	$	(22)	(21.0	%)	$	192	21.0	%
State and local income tax, net of federal income tax effect(*)	254		5.1		97		5.0		149		4.3		11		4.0		1		1.0		44		4.8
Tax credits —
Amortization of ITCs	(56)		(1.1)		(2)		(0.1)		(2)		(0.1)		—		—		(46)		(43.7)		—		—
Federal PTCs	(166)		(3.3)		—		—		(137)		(4.0)		—		—		(28)		(26.8)		—		—
Other	(2)		—		(1)		—		(1)		—		—		—		—		—		—		—
Nontaxable or nondeductible items —
AFUDC equity	(67)		(1.3)		(14)		(0.7)		(52)		(1.5)		—		—		—		—		—		—
Other	19		0.4		12		0.6		21		0.6		2		0.6		—		—		(5)		(0.5)
Changes in unrecognized tax benefits	(26)		(0.5)		—		—		(26)		(0.7)		—		—		—		—		—		—
Other adjustments —
Noncontrolling interests	36		0.7		—		—		—		—		—		—		36		33.9		—		—
Federal flowback of excess deferreds	(170)		(3.4)		(58)		(3.0)		(57)		(1.7)		(5)		(1.9)		—		—		(45)		(4.9)
Other	(44)		(1.0)		(17)		(0.9)		(18)		(0.5)		(2)		(0.5)		(2)		(1.2)		(4)		(0.5)
Effective income tax (benefit) rate	$	828	16.6	%	$	425	21.9	%	$	602	17.4	%	$	65	23.2	%	$	(61)	(57.8	%)	$	182	19.9	%

(*)The following states made up the majority (greater than 50%) of the tax effect in this category: for Southern Company and Georgia Power, Georgia; for Alabama Power, Alabama; for Mississippi Power, Mississippi; for Southern Power, Alabama, California, Delaware, Georgia, North Carolina, Oklahoma, and Tennessee; and for Southern Company Gas, Illinois.

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	2024
	Southern<br><br>Company				Alabama<br>Power				Georgia<br>Power				Mississippi<br><br>Power				Southern<br>Power				Southern<br><br>Company Gas
	(in millions, except percentages)
Federal statutory rate	$	1,098	21.0	%	$	370	21.0	%	$	661	21.0	%	$	52	21.0	%	$	36	21.0	%	$	209	21.0	%
State and local income tax, net of federal income tax effect(*)	305		5.8		89		5.0		184		5.9		11		4.4		(4)		(2.3)		62		6.2
Foreign tax effects	6		0.1		—		—		—		—		—		—		—		—		—		—
Effect of cross-border tax laws	(1)		—		—		—		—		—		—		—		—		—		—		—
Tax credits —
Amortization of ITCs	(61)		(1.2)		(1)		(0.1)		(7)		(0.2)		—		—		(46)		(26.4)		—		—
Federal PTCs	(147)		(2.8)		(1)		(0.1)		(116)		(3.7)		—		—		(30)		(17.2)		—		—
Other	(3)		(0.1)		(1)		—		(1)		—		—		—		—		—		—		—
Nontaxable or nondeductible items —															—
AFUDC equity	(44)		(0.8)		(12)		(0.7)		(32)		(1.0)		—		—		—		—		—		—
Other	30		0.6		12		0.7		26		0.8		1		0.6		1		0.2		1		0.1
Changes in unrecognized tax benefits —
State changes in unrecognized tax benefits from prior periods, net of federal income tax effect	(25)		(0.5)		—		—		(33)		(1.0)		—		—		—		—		8		0.8
Other adjustments —
Noncontrolling interests	30		0.6		—		—		—		—		—		—		30		17.1		—		—
Federal flowback of excess deferreds	(206)		(3.9)		(94)		(5.3)		(70)		(2.2)		(16)		(6.5)		—		—		(22)		(2.2)
Other	(13)		(0.3)		(2)		(0.1)		(9)		(0.4)		(1)		(0.3)		—		—		—		(0.1)
Effective income tax (benefit) rate	$	969	18.5	%	$	360	20.4	%	$	603	19.2	%	$	47	19.2	%	$	(13)	(7.6	%)	$	258	25.8	%

(*)The following states made up the majority (greater than 50%) of the tax effect in this category: for Southern Company and Georgia Power, Georgia; for Alabama Power, Alabama; for Mississippi Power, Mississippi; for Southern Power, Georgia and Oklahoma; and for Southern Company Gas, Illinois.

	2023
	Southern<br><br>Company				Alabama<br><br>Power				Georgia<br><br>Power				Mississippi<br><br>Power				Southern<br><br>Power				Southern<br><br>Company Gas
	(in millions, except percentages)
Federal statutory rate	$	912	21.0	%	$	305	21.0	%	$	531	21.0	%	$	47	21.0	%	$	51	21.0	%	$	174	21.0	%
State and local income tax, net of federal income tax effect(*)	117		2.7		75		5.2		45		1.8		11		4.9		(2)		(0.7)		62		7.6
Tax credits —
Amortization of ITCs	(56)		(1.3)		(1)		(0.1)		(2)		(0.1)		—		—		(46)		(19.0)		—		—
Federal PTCs	(52)		(1.2)		—		—		(35)		(1.4)		—		—		(18)		(7.4)		—		—
Other	(4)		(0.1)		(2)		(0.1)		(2)		(0.1)		—		—		—		—		—		—
Nontaxable or nondeductible items —
AFUDC equity	(48)		(1.1)		(17)		(1.2)		(31)		(1.2)		—		—		—		—		—		—
Other	23		0.5		14		1.0		21		0.8		1		0.5		1		0.4		1		0.1
Changes in unrecognized tax benefits	(5)		(0.1)		—		—		(6)		(0.2)		—		—		—		—		2		0.2
Other adjustments —
Noncontrolling interests	27		0.6		—		—		—		—		—		—		27		11.1		—		—
Federal flowback of excess deferreds	(401)		(9.2)		(287)		(19.8)		(64)		(2.6)		(23)		(10.2)		—		—		(22)		(2.6)
Other	(17)		(0.4)		(6)		(0.4)		(9)		(0.2)		—		—		(1)		(0.3)		(6)		(0.7)
Effective income tax rate	$	496	11.4	%	$	81	5.6	%	$	448	17.8	%	$	36	16.2	%	$	12	5.1	%	$	211	25.6	%

(*)The following states made up the majority (greater than 50%) of the tax effect in this category: for Southern Company and Alabama Power, Alabama; for Georgia Power, Georgia; for Mississippi Power, Mississippi; for Southern Power, Georgia and Oklahoma; and for Southern Company Gas, Illinois.

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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:

	At December 31, 2025
	Southern<br>Company		Alabama<br>Power		Georgia<br>Power		Mississippi<br>Power		Southern<br>Power		Southern<br>Company<br>Gas
	(in millions)
Deferred tax liabilities —
Accelerated depreciation	$	10,234	$	2,641	$	4,035	$	363	$	1,345	$	1,675
Property basis differences	3,090		1,394		1,099		177		—		418
Employee benefit obligations	1,223		434		501		66		15		64
AROs	710		422		242		—		—		—
Under recovered fuel and natural gas costs	195		45		135		15		—		—
Regulatory assets —
AROs	1,809		590		1,191		28		—		—
Employee benefit obligations	699		190		221		34		—		33
Remaining book value of retired assets	395		229		161		5		—		—
Storm damage reserves	236		—		236		—		—		—
Premium on reacquired debt	53		8		44		1		—		—
Other	644		141		211		32		26		175
Total deferred income tax liabilities	19,288		6,094		8,076		721		1,386		2,365
Deferred tax assets —
AROs	2,519		1,012		1,433		28		—		—
ITC and PTC carryforwards	1,427		31		683		2		481		—
Employee benefit obligations	837		188		261		47		17		77
Estimated loss on plants under construction	679		—		679		—		—		—
Estimated loss on regulatory disallowance	38		—		—		—		—		38
Other state deferred tax attributes	346		—		25		211		48		12
Federal effect of net state deferred tax liabilities	460		201		141		—		24		114
Other property basis differences	159		—		73		—		73		—
State effect of federal deferred taxes	136		136		—		—		—		—
Other partnership basis differences	149		—		—		—		149		—
Regulatory liability associated with the Tax Reform Legislation (not subject to normalization)	18		18		—		—		—		—
Long-term debt fair value adjustment	67		—		—		—		—		67
Other comprehensive losses	51		2		—		—		—		—
Other	780		297		237		49		44		92
Total deferred income tax assets	7,666		1,885		3,532		337		836		400
Valuation allowance	(445)		—		(267)		(41)		(29)		(6)
Net deferred income tax assets	7,221		1,885		3,265		296		807		394
Net deferred income taxes (assets)/liabilities	$	12,067	$	4,209	$	4,811	$	425	$	579	$	1,971
Recognized in the balance sheets:
Accumulated deferred income taxes – assets	$	(66)	$	—	$	—	$	(66)	$	—	$	—
Accumulated deferred income taxes – liabilities	$	12,133	$	4,209	$	4,811	$	491	$	579	$	1,971

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	At December 31, 2024
	Southern<br>Company		Alabama<br>Power		Georgia<br>Power		Mississippi<br>Power		Southern<br>Power		Southern<br>Company<br>Gas
	(in millions)
Deferred tax liabilities —
Accelerated depreciation	$	9,828	$	2,583	$	3,810	$	344	$	1,309	$	1,575
Property basis differences	3,025		1,497		918		192		—		412
Employee benefit obligations	1,067		362		470		54		13		60
AROs	727		458		221		—		—		—
Under recovered fuel and natural gas costs	318		13		305		—		—		—
Regulatory assets —
AROs	1,886		658		1,193		35		—		—
Employee benefit obligations	746		191		237		35		—		35
Remaining book value of retired assets	360		168		187		5		—		—
Storm damage reserves	216		—		216		—		—		—
Premium on reacquired debt	57		8		48		1		—		—
Other	678		171		187		61		1		201
Total deferred income tax liabilities	18,908		6,109		7,792		727		1,323		2,283
Deferred tax assets —
AROs	2,613		1,116		1,414		35		—		—
CAMT carryforwards	40		—		18		—		—		104
ITC and PTC carryforwards	1,380		48		719		—		384		—
Employee benefit obligations	897		196		279		49		16		87
Estimated loss on plants under construction	773		—		773		—		—		—
Estimated loss on regulatory disallowance	20		—		—		—		—		20
Other state deferred tax attributes	366		—		26		224		49		16
Federal effect of net state deferred tax liabilities	402		197		100		—		23		107
Other property basis differences	176		—		75		—		85		—
State effect of federal deferred taxes	126		126		—		—		—		—
Other partnership basis differences	60		—		—		—		60		—
Regulatory liability associated with the Tax Reform Legislation (not subject to normalization)	18		18		—		—		—		—
Long-term debt fair value adjustment	73		—		—		—		—		73
Other comprehensive losses	48		3		—		—		1		—
Other	601		227		160		50		20		86
Total deferred income tax assets	7,593		1,931		3,564		358		638		493
Valuation allowance	(333)		—		(157)		(41)		(27)		(6)
Net deferred income tax assets	7,260		1,931		3,407		317		611		487
Net deferred income taxes (assets)/liabilities	$	11,648	$	4,178	$	4,385	$	410	$	712	$	1,796
Recognized in the balance sheets:
Accumulated deferred income taxes – assets	$	(82)	$	—	$	—	$	(82)	$	—	$	—
Accumulated deferred income taxes – liabilities	$	11,730	$	4,178	$	4,385	$	492	$	712	$	1,796

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, certain tax credits deferred for future customer benefit, and unamortized ITCs. See Note 2 for each Registrant's related balances at December 31, 2025 and 2024.

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Tax Credit Carryforwards

Federal ITC/PTC carryforwards at December 31, 2025 were as follows:

	Southern<br><br>Company		Alabama<br>Power		Georgia<br>Power		Southern<br>Power
	(in millions)
Federal ITC/PTC carryforwards	$	850	$	31	$	152	$	481
Tax year(s) in which federal ITC/PTC carryforwards expire(*)	2031-2045		2032-2045		2031-2045		2035-2045
Year by which federal ITC/PTC carryforwards are expected to be utilized	2031		2031		2031		2031

(*)The federal ITC/PTC carryforwards at Alabama Power and Georgia Power expiring in 2031-2034 are immaterial to their respective financial statements.

The estimated tax credit utilization reflects the various transactions described in Note 15 and could be impacted by numerous factors, including the acquisition or construction of additional renewable projects, changes in taxable income projections, transfer of eligible credits, potential income tax rate changes, and remaining final guidance on the IRA. In the third quarter 2023 and the second quarter 2024, Georgia Power started generating advanced nuclear PTCs for Plant Vogtle Units 3 and 4, respectively, beginning on each unit's respective in-service date. In addition, pursuant to the Vogtle Joint Ownership Agreements, Georgia Power is purchasing advanced nuclear PTCs for Plant Vogtle Unit 3 and 4 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, 2025, Southern Company and Georgia Power also had approximately $483 million and $438 million, respectively, in net state investment and other net state tax credit carryforwards for the State of Georgia that will expire between tax years 2025 and 2033 and are not expected to be fully utilized. Southern Company and Georgia Power have a net state valuation allowance of $248 million and $211 million, respectively, associated with these carryforwards, both of which increased during 2025 by $87 million.

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

Net Operating Loss Carryforwards

At December 31, 2025, the net state income tax benefit of state and local NOL carryforwards and associated valuation allowances for Southern Company's subsidiaries were as follows:

Company/Jurisdiction	Approximate Net State<br><br>Income Tax Benefit of NOL<br><br>Carryforwards		Tax Year NOL<br>Begins Expiring	Net State Valuation<br><br>Allowance for NOL<br><br>Carryforwards
	(in millions)			(in millions)
Mississippi Power
Mississippi	$	167	2032	$	(32)
Southern Power
Oklahoma	$	25	2035	$	(13)
Florida	10		2034	(10)
Other states	2		2034	—
Southern Power total	$	37		$	(23)
Other(*)
New York	$	11	2036	$	(11)
New York City	14		2036	(14)
Other states	21		2026	(5)
Southern Company total	$	250		$	(85)

(*)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, 2025.

Certain state NOLs are not expected to be fully utilized prior to expiration. The ultimate outcome of these matters cannot be determined at this time.

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Unrecognized Tax Benefits

Changes in unrecognized tax benefits for the periods presented were as follows:

	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br><br>Power		Southern<br>Company Gas
	(in millions)
Unrecognized tax benefits at December 31, 2022	$	80	$	—	$	—	$	32
Tax positions changes —
Increase from prior periods	88		—		86		2
Statute of limitations expiration	(52)		—		(9)		—
Unrecognized tax benefits at December 31, 2023	116		—		77		34
Tax positions changes —
Increase from prior periods	10		—		—		10
Decrease from prior periods	(44)		—		(43)		—
Unrecognized tax benefits at December 31, 2024	82		—		34		44
Tax positions changes —
Statute of limitations expiration	(34)		—		(34)		—
Increase from current period	122		50		72		—
Unrecognized tax benefits at December 31, 2025	$	170	$	50	$	72	$	44

The unrecognized tax positions increase from prior periods for 2023 is 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, which 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 relate 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.

The unrecognized tax positions increase from prior periods for 2024 is primarily related to a certain state tax filing position at Southern Company Gas. If effective settlement of this position is favorable, this position would decrease Southern Company's and Southern Company Gas' annual effective tax rates. The ultimate outcome is dependent on acceptance by the state.

The unrecognized tax positions decrease from prior periods and statute of limitations expiration for 2024 and 2025, respectively, are primarily related to the 2019 through 2021 amended state filing positions related to tax credit utilization at Georgia Power.

Alabama Power and Georgia Power recorded an unrecognized tax position in the second quarter 2025 for zero-emission nuclear power PTCs generated on the consolidated 2024 federal income tax return due to the uncertainty to meet the prevailing wage requirements. In the fourth quarter 2025, the unrecognized tax position at Alabama Power and Georgia Power was reversed as Southern Company received the acceptance letter from the IRS on these PTCs for the 2024 tax year. The reversal of the unrecognized tax position did not impact Southern Company's, Alabama Power's, and Georgia Power's effective tax rates.

The unrecognized tax positions increase from the current period is related to the Alabama Power and Georgia Power zero-emission nuclear power PTCs for the 2025 tax year of $50 million and $72 million, respectively.

All of the Registrants classify interest on tax uncertainties as interest expense. Accrued interest for all tax positions was immaterial for all periods 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 2024. Southern Company is a participant in the Compliance Assurance Process of the IRS. The IRS selected six Southern Power partnership returns for exam for the 2020 and 2021 tax years. One audit for 2020 is still under review, and the remaining audits have been closed with no change. 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 2018.

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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, 2025 and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2026. The Southern Company system also provides certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis. In addition, the Southern Company system provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund other postretirement trusts to the extent required by their respective regulatory commissions. For the year ending December 31, 2026, 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.

	2025
Assumptions used to determine net<br>periodic costs:	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
Pension plans
Discount rate – benefit obligations	5.76	%	5.78	%	5.75	%	5.76	%	5.84	%	5.73	%
Discount rate – interest costs	5.47		5.48		5.44		5.46		5.58		5.46
Discount rate – service costs	5.93		5.95		5.95		5.94		5.93		5.84
Expected long-term return on plan assets	8.50		8.50		8.50		8.50		8.50		8.50
Annual salary increase	4.60		4.60		4.60		4.60		4.60		4.60
Other postretirement benefit plans
Discount rate – benefit obligations	5.64	%	5.67	%	5.61	%	5.63	%	5.73	%	5.62	%
Discount rate – interest costs	5.35		5.38		5.34		5.34		5.45		5.30
Discount rate – service costs	5.90		5.92		5.91		5.89		5.86		5.89
Expected long-term return on plan assets	7.80		8.06		7.78		7.69		—		6.44
Annual salary increase	4.60		4.60		4.60		4.60		4.60		4.60				2024
---	---	---	---	---	---	---	---	---	---	---	---	---
Assumptions used to determine net<br>periodic costs:	Southern<br><br>Company		Alabama<br>Power		Georgia<br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
Pension plans
Discount rate – benefit obligations	5.07	%	5.08	%	5.06	%	5.06	%	5.14	%	5.05	%
Discount rate – interest costs	4.94		4.94		4.94		4.93		5.01		4.93
Discount rate – service costs	5.19		5.20		5.21		5.19		5.20		5.13
Expected long-term return on plan assets	8.30		8.30		8.30		8.30		8.30		8.30
Annual salary increase	4.60		4.60		4.60		4.60		4.60		4.60
Other postretirement benefit plans
Discount rate – benefit obligations	4.99	%	5.01	%	4.98	%	4.98	%	5.06	%	4.98	%
Discount rate – interest costs	4.90		4.90		4.89		4.90		4.94		4.89
Discount rate – service costs	5.16		5.17		5.16		5.16		5.14		5.16
Expected long-term return on plan assets	7.67		7.97		7.59		7.43		—		6.36
Annual salary increase	4.60		4.60		4.60		4.60		4.60		4.60

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	2023
Assumptions used to determine net periodic costs:	Southern<br><br>Company		Alabama<br>Power		Georgia<br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
Pension plans
Discount rate – benefit obligations	5.25	%	5.26	%	5.25	%	5.25	%	5.31	%	5.24	%
Discount rate – interest costs	5.13		5.14		5.12		5.12		5.19		5.12
Discount rate – service costs	5.36		5.38		5.38		5.37		5.37		5.31
Expected long-term return on plan assets	8.40		8.40		8.40		8.40		8.40		8.40
Annual salary increase	4.80		4.80		4.80		4.80		4.80		4.80
Other postretirement benefit plans
Discount rate – benefit obligations	5.18	%	5.20	%	5.17	%	5.17	%	5.24	%	5.16	%
Discount rate – interest costs	5.08		5.09		5.07		5.08		5.12		5.07
Discount rate – service costs	5.34		5.35		5.34		5.33		5.33		5.33
Expected long-term return on plan assets	7.67		7.95		7.49		7.43		—		6.59
Annual salary increase	4.80		4.80		4.80		4.80		4.80		4.80				2025
---	---	---	---	---	---	---	---	---	---	---	---	---
Assumptions used to determine benefit obligations:	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br><br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
Pension plans
Discount rate	5.69	%	5.72	%	5.67	%	5.66	%	5.85	%	5.61	%
Annual salary increase	5.00		5.00		5.00		5.00		5.00		5.00
Other postretirement benefit plans
Discount rate	5.40	%	5.45	%	5.34	%	5.38	%	5.59	%	5.38	%
Annual salary increase	5.00		5.00		5.00		5.00		5.00		5.00				2024
---	---	---	---	---	---	---	---	---	---	---	---	---
Assumptions used to determine benefit obligations:	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br><br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
Pension plans
Discount rate	5.76	%	5.78	%	5.75	%	5.76	%	5.84	%	5.73	%
Annual salary increase	4.60		4.60		4.60		4.60		4.60		4.60
Other postretirement benefit plans
Discount rate	5.64	%	5.67	%	5.61	%	5.63	%	5.73	%	5.62	%
Annual salary increase	4.60		4.60		4.60		4.60		4.60		4.60

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.

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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, 2025 were as follows:

	Initial Cost<br><br>Trend Rate		Ultimate Cost<br><br>Trend Rate		Year That<br><br>Ultimate Rate is<br><br>Reached
Pre-65	8.50	%	4.50	%	2034
Post-65 medical	6.00		4.50		2034
Post-65 prescription	11.00		4.50		2034

Pension Plans

The total accumulated benefit obligation for the pension plans at December 31, 2025 and 2024 was as follows:

	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br><br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
At December 31, 2025	$	11,952	$	2,730	$	3,549	$	542	$	147	$	829
At December 31, 2024	11,437		2,617		3,438		519		140		779

An actuarial loss of $458 million and an actuarial gain of $887 million were recorded for the annual remeasurement of the Southern Company system pension plans at December 31, 2025 and 2024, respectively, primarily due to a decrease of 7 basis points and an increase of 69 basis points, respectively, in the overall discount rate used to calculate the benefit obligation as a result of a change in market interest rates.

Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2025 and 2024 were as follows:

	2025
	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	12,564	$	2,908	$	3,733	$	567	$	167	$	842
Service cost	264		60		63		11		6		27
Interest cost	664		154		196		30		9		45
Benefits paid	(761)		(166)		(247)		(35)		(6)		(55)
Actuarial (gain) loss	458		99		128		21		(1)		36
Balance at end of year	13,189		3,055		3,873		594		175		895
Change in plan assets
Fair value of plan assets at beginning of year	14,559		3,539		4,519		664		188		978
Actual return on plan assets	1,886		452		576		86		22		130
Employer contributions	66		13		13		2		1		2
Benefits paid	(761)		(166)		(247)		(35)		(6)		(55)
Fair value of plan assets at end of year	15,750		3,838		4,861		717		205		1,055
Accrued asset	$	2,561	$	783	$	988	$	123	$	30	$	160

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	2024
	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	13,252	$	3,076	$	4,009	$	599	$	177	$	882
Service cost	292		68		70		12		7		28
Interest cost	635		148		191		29		9		42
Benefits paid	(728)		(162)		(239)		(33)		(6)		(46)
Actuarial gain	(887)		(222)		(298)		(40)		(20)		(64)
Balance at end of year	12,564		2,908		3,733		567		167		842
Change in plan assets
Fair value of plan assets at beginning of year	14,618		3,544		4,571		669		185		980
Actual return on plan assets	604		148		152		23		7		39
Employer contributions	65		9		35		5		2		5
Benefits paid	(728)		(162)		(239)		(33)		(6)		(46)
Fair value of plan assets at end of year	14,559		3,539		4,519		664		188		978
Accrued asset	$	1,995	$	631	$	786	$	97	$	21	$	136

The projected benefit obligations for the qualified and non-qualified pension plans at December 31, 2025 are shown in the following table. All pension plan assets are related to the qualified pension plan.

	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br><br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
Projected benefit obligations:
Qualified pension plan	$	12,493	$	2,939	$	3,762	$	566	$	154	$	837
Non-qualified pension plan	696		116		111		28		21		59

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Amounts recognized in the balance sheets at December 31, 2025 and 2024 related to the Registrants' pension plans consist of the following:

	Southern<br>Company		Alabama<br><br>Power		Georgia<br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
At December 31, 2025:
Prepaid pension costs(a)	$	3,257	$	899	$	1,099	$	151	$	51	$	219
Other regulatory assets, deferred(b)	2,533		687		907		136		—		114
Other current liabilities	(68)		(12)		(13)		(3)		(2)		(3)
Employee benefit obligations(c)	(628)		(104)		(98)		(25)		(19)		(56)
Other regulatory liabilities, deferred	(47)		—		—		—		—		—
AOCI	38		—		—		—		4		(56)
At December 31, 2024:
Prepaid pension costs(a)	$	2,674	$	746	$	897	$	124	$	41	$	191
Other regulatory assets, deferred(b)	2,708		741		973		144		—		126
Other current liabilities	(68)		(13)		(13)		(2)		(2)		(4)
Employee benefit obligations(c)	(611)		(102)		(98)		(25)		(18)		(51)
Other regulatory liabilities, deferred	(50)		—		—		—		—		—
AOCI	52		—		—		—		11		(54)

(a)Included in prepaid pension and other postretirement benefit costs on Alabama Power's and Southern Company Gas' balance sheets and other deferred charges and assets on Southern Power's consolidated balance sheets.

(b)Amounts for Southern Company exclude regulatory assets of $135 million and $155 million at December 31, 2025 and 2024, 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, 2025 and 2024 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.

	Southern<br>Company		Alabama<br><br>Power		Georgia<br>Power		Mississippi<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
Balance at December 31, 2025
Regulatory assets:
Prior service cost	$	8	$	3	$	4	$	1	$	(2)
Net loss	2,478		684		903		135		89
Regulatory amortization	—		—		—		—		27
Total regulatory assets(*)	$	2,486	$	687	$	907	$	136	$	114
Balance at December 31, 2024
Regulatory assets:
Prior service cost	$	8	$	3	$	5	$	1	$	(4)
Net loss	2,650		738		968		143		91
Regulatory amortization	—		—		—		—		39
Total regulatory assets(*)	$	2,658	$	741	$	973	$	144	$	126

(*)Amounts for Southern Company exclude regulatory assets of $135 million and $155 million at December 31, 2025 and 2024, respectively, associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company.

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The changes in the balance of net regulatory assets (liabilities) 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, 2025 and 2024 are presented in the following table:

	Southern<br>Company		Alabama<br><br>Power		Georgia<br>Power		Mississippi<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
Net regulatory assets (liabilities):(*)
Balance at December 31, 2023	$	2,913	$	821	$	1,051	$	152	$	143
Net gain	(199)		(63)		(58)		(5)		(7)
Reclassification adjustments:
Amortization of prior service costs	(1)		(1)		(1)		—		2
Amortization of net loss	(55)		(16)		(19)		(3)		(1)
Amortization of regulatory assets(*)	—		—		—		—		(11)
Total reclassification adjustments	(56)		(17)		(20)		(3)		(10)
Total change	(255)		(80)		(78)		(8)		(17)
Balance at December 31, 2024	$	2,658	$	741	$	973	$	144	$	126
Net (gain) loss	(127)		(42)		(50)		(5)		1
Reclassification adjustments:
Amortization of prior service costs	(1)		(1)		(1)		—		2
Amortization of net loss	(44)		(11)		(15)		(3)		(3)
Amortization of regulatory assets(*)	—		—		—		—		(12)
Total reclassification adjustments	(45)		(12)		(16)		(3)		(13)
Total change	(172)		(54)		(66)		(8)		(12)
Balance at December 31, 2025	$	2,486	$	687	$	907	$	136	$	114

(*)Amounts for Southern Company exclude regulatory assets of $135 million and $155 million at December 31, 2025 and 2024, 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, 2025 and 2024 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.

	Southern<br>Company		Southern<br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
Balance at December 31, 2025
AOCI:
Net (gain) loss	$	38	$	4	$	(56)
Balance at December 31, 2024
AOCI:
Prior service cost	$	(1)	$	—	$	(1)
Net (gain) loss	53		11		(53)
Total AOCI	$	52	$	11	$	(54)

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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, 2025 and 2024 are presented in the following table:

	Southern<br><br>Company		Southern<br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
AOCI:
Balance at December 31, 2023	$	79	$	20	$	(45)
Net gain	(29)		(9)		(11)
Reclassification adjustments:
Amortization of prior service costs	1		—		2
Amortization of net gain	1		—		—
Total reclassification adjustments	2		—		2
Total change	(27)		(9)		(9)
Balance at December 31, 2024	$	52	$	11	$	(54)
Net gain	(21)		(7)		(3)
Reclassification adjustments:
Amortization of prior service costs	1		—		1
Amortization of net gain	6		—		—
Total reclassification adjustments	7		—		1
Total change	(14)		(7)		(2)
Balance at December 31, 2025	$	38	$	4	$	(56)

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Components of net periodic pension cost for the Registrants were as follows:

	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
2025
Service cost	$	264	$	60	$	63	$	11	$	6	$	27
Interest cost	664		154		196		30		9		45
Expected return on plan assets	(1,281)		(312)		(397)		(59)		(17)		(86)
Recognized net (gain) loss(*)	38		11		15		3		—		(1)
Net amortization(*)	—		1		1		—		—		15
Prior service cost(*)	—		—		—		—		—		(3)
Net periodic pension income	$	(315)	$	(86)	$	(122)	$	(15)	$	(2)	$	(3)
2024
Service cost	$	292	$	68	$	70	$	12	$	7	$	28
Interest cost	635		148		191		29		9		42
Expected return on plan assets	(1,263)		(307)		(393)		(58)		(17)		(85)
Recognized net loss(*)	55		16		19		3		—		—
Net amortization(*)	—		1		1		—		—		15
Prior service cost(*)	—		—		—		—		—		(3)
Net periodic pension income	$	(281)	$	(74)	$	(112)	$	(14)	$	(1)	$	(3)
2023
Service cost	$	275	$	64	$	68	$	11	$	6	$	24
Interest cost	626		145		191		28		8		42
Expected return on plan assets	(1,229)		(297)		(385)		(56)		(15)		(85)
Recognized net (gain) loss(*)	32		9		13		2		—		(5)
Net amortization(*)	—		1		1		—		—		15
Prior service cost(*)	—		—		—		—		—		(3)
Net periodic pension income	$	(296)	$	(78)	$	(112)	$	(15)	$	(1)	$	(12)

(*)For Southern Company, excludes amounts related to net periodic pension cost of $20 million, $20 million, and $17 million for the years ended December 31, 2025, 2024, and 2023, respectively, associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company.

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.

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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, 2025, estimated benefit payments were as follows:

	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
Benefit Payments:
2026	$	803	$	176	$	252	$	36	$	7	$	62
2027	827		182		255		37		8		63
2028	847		188		259		38		7		65
2029	868		193		264		38		8		66
2030	889		198		267		39		9		68
2031 to 2035	4,638		1,041		1,353		209		55		360

Other Postretirement Benefits

An actuarial loss of $71 million was recorded for the annual remeasurement of the Southern Company system other postretirement benefit plans at December 31, 2025 primarily due to a decrease of 24 basis points in the overall discount rate used to calculate the benefit obligation as a result of a change in market interest rates.

Changes in the APBO and the fair value of the Registrants' plan assets during the plan years ended December 31, 2025 and 2024 were as follows:

	2025
	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	1,359	$	326	$	488	$	55	$	9	$	156
Service cost	13		4		4		1		—		—
Interest cost	70		17		25		3		—		7
Benefits paid	(113)		(24)		(40)		(5)		(1)		(16)
Actuarial (gain) loss	71		17		34		3		1		(1)
Balance at end of year	1,400		340		511		57		9		146
Change in plan assets
Fair value of plan assets at beginning of year	1,141		421		420		24		—		141
Actual return on plan assets	158		56		61		4		—		19
Employer contributions	65		4		17		4		1		12
Benefits paid	(113)		(24)		(40)		(5)		(1)		(16)
Fair value of plan assets at end of year	1,251		457		458		27		—		156
Accrued asset (liability)	$	(149)	$	117	$	(53)	$	(30)	$	(9)	$	10

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	2024
	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	1,386	$	329	$	489	$	57	$	9	$	172
Service cost	15		4		4		1		—		1
Interest cost	65		16		23		3		—		8
Benefits paid	(105)		(25)		(37)		(4)		(1)		(12)
Actuarial (gain) loss	(2)		2		9		(2)		1		(13)
Balance at end of year	1,359		326		488		55		9		156
Change in plan assets
Fair value of plan assets at beginning of year	1,095		403		410		25		—		128
Actual return on plan assets	96		37		34		—		—		18
Employer contributions	55		6		13		3		1		7
Benefits paid	(105)		(25)		(37)		(4)		(1)		(12)
Fair value of plan assets at end of year	1,141		421		420		24		—		141
Accrued asset (liability)	$	(218)	$	95	$	(68)	$	(31)	$	(9)	$	(15)

Amounts recognized in the balance sheets at December 31, 2025 and 2024 related to the Registrants' other postretirement benefit plans consist of the following:

	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br>Power		Mississippi<br><br>Power		Southern<br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
At December 31, 2025:
Prepaid other postretirement benefit costs(a)	$	—	$	117	$	—	$	—	$	—	$	10
Other regulatory assets, deferred(b)	25		—		—		—		—		—
Other current liabilities	(6)		—		—		—		(1)		—
Employee benefit obligations(c)	(143)		—		(53)		(30)		(8)		—
Other regulatory liabilities, deferred	(199)		(47)		(56)		(6)		—		(93)
AOCI	(13)		—		—		—		1		(16)
At December 31, 2024:
Prepaid other postretirement benefit costs(a)	$	—	$	95	$	—	$	—	$	—	$	—
Other regulatory assets, deferred(b)	24		—		3		—		—		—
Other current liabilities	(6)		—		—		—		(1)		—
Employee benefit obligations(c)	(212)		—		(68)		(31)		(8)		(15)
Other regulatory liabilities, deferred	(213)		(45)		(67)		(9)		—		(84)
AOCI	(14)		—		—		—		—		(15)

(a)Included in prepaid pension and other postretirement benefit costs on Alabama Power's and Southern Company Gas' balance sheets.

(b)Amounts for Southern Company exclude regulatory assets of $4 million and $16 million at December 31, 2025 and 2024, 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.

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Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2025 and 2024 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.

	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br>Power		Mississippi<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
Balance at December 31, 2025:
Regulatory assets (liabilities):
Prior service cost	$	8	$	3	$	3	$	1	$	—
Net gain	(182)		(50)		(59)		(7)		(75)
Regulatory amortization	—		—		—		—		(18)
Total regulatory assets (liabilities)(*)	$	(174)	$	(47)	$	(56)	$	(6)	$	(93)
Balance at December 31, 2024:
Regulatory assets (liabilities):
Prior service cost	$	11	$	3	$	4	$	1	$	—
Net gain	(200)		(48)		(68)		(10)		(71)
Regulatory amortization	—		—		—		—		(13)
Total regulatory assets (liabilities)(*)	$	(189)	$	(45)	$	(64)	$	(9)	$	(84)

(*)Amounts for Southern Company exclude regulatory assets of $4 million and $16 million at December 31, 2025 and 2024, 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, 2025 and 2024 are presented in the following table:

	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br>Power		Mississippi<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
Net regulatory assets (liabilities):(*)
Balance at December 31, 2023	$	(208)	$	(48)	$	(74)	$	(10)	$	(68)
Net (gain) loss	8		1		6		1		(12)
Reclassification adjustments:
Amortization of prior service costs	(2)		(1)		(1)		—		—
Amortization of net gain	13		3		5		—		5
Amortization of regulatory assets(*)	—		—		—		—		(9)
Total reclassification adjustments	11		2		4		—		(4)
Total change	19		3		10		1		(16)
Balance at December 31, 2024	$	(189)	$	(45)	$	(64)	$	(9)	$	(84)
Net (gain) loss	5		(3)		6		3		2
Reclassification adjustments:
Amortization of prior service costs	(2)		(1)		(1)		—		—
Amortization of net gain (loss)	12		2		3		—		(6)
Amortization of regulatory assets(*)	—		—		—		—		(5)
Total reclassification adjustments	10		1		2		—		(11)
Total change	15		(2)		8		3		(9)
Balance at December 31, 2025	$	(174)	$	(47)	$	(56)	$	(6)	$	(93)

(*)Amounts for Southern Company exclude regulatory assets of $4 million and $16 million at December 31, 2025 and 2024, respectively, associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company.

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Presented below are the amounts included in AOCI at December 31, 2025 and 2024 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.

	Southern<br>Company		Southern<br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
Balance at December 31, 2025
AOCI:
Net (gain) loss	$	(13)	$	1	$	(16)
Balance at December 31, 2024
AOCI:
Net gain	$	(14)	$	—	$	(15)

The components of OCI related to the other postretirement benefit plans for the plan years ended December 31, 2025 and 2024 are presented in the following table:

	Southern<br><br>Company		Southern<br>Power		Southern<br><br>Company Gas
	(in millions)
AOCI:
Balance at December 31, 2023	$	(9)	$	1	$	(10)
Net gain	(8)		(1)		(5)
Reclassification adjustments:
Amortization of net gain	3		—		—
Total change	(5)		(1)		(5)
Balance at December 31, 2024	$	(14)	$	—	$	(15)
Net (gain) loss	(1)		1		(1)
Reclassification adjustments:
Amortization of net gain	2		—		—
Total change	1		1		(1)
Balance at December 31, 2025	$	(13)	$	1	$	(16)

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Components of the other postretirement benefit plans' net periodic cost for the Registrants were as follows:

	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
2025
Service cost	$	13	$	4	$	4	$	1	$	—	$	—
Interest cost	70		17		25		3		—		7
Expected return on plan assets	(91)		(35)		(33)		(3)		1		(15)
Net amortization(*)	(12)		(2)		(2)		—		—		5
Net periodic other postretirement benefit cost (income)	$	(20)	$	(16)	$	(6)	$	1	$	1	$	(3)
2024
Service cost	$	15	$	4	$	4	$	1	$	—	$	1
Interest cost	65		16		23		3		—		8
Expected return on plan assets	(89)		(35)		(32)		(3)		1		(13)
Net amortization(*)	(13)		(3)		(4)		—		—		6
Net periodic other postretirement benefit cost (income)	$	(22)	$	(18)	$	(9)	$	1	$	1	$	2
2023
Service cost	$	15	$	4	$	4	$	1	$	—	$	1
Interest cost	70		17		25		3		—		9
Expected return on plan assets	(83)		(33)		(29)		(3)		1		(10)
Net amortization(*)	(11)		(3)		(3)		—		—		6
Net periodic other postretirement benefit cost (income)	$	(9)	$	(15)	$	(3)	$	1	$	1	$	6

(*)For Southern Company, excludes amounts related to net periodic other postretirement benefit cost of $12 million, $8 million, and $8 million for the years ended December 31, 2025, 2024, and 2023, respectively, associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company.

The service cost component of net periodic other postretirement benefit cost is included in operations and maintenance expenses and all other components of net periodic other 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.

	Southern<br><br>Company		Alabama<br><br>Power		Georgia<br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
Benefit payments:
2026	$	114	$	26	$	42	$	5	$	1	$	15
2027	115		26		43		5		1		15
2028	116		27		43		5		1		14
2029	116		27		43		5		1		14
2030	116		27		43		5		1		13
2031 to 2035	566		136		211		23		1		56

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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.

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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.<br><br><br><br>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.<br><br><br><br>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.<br><br><br><br>Private equity: Investments in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.<br><br><br><br>Private credit: Investments focused on debt instruments, of which returns are driven by income rather than capital appreciation.<br><br><br><br>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 (Investment Funds) which are generally classified as Net Asset Value as a Practical Expedient, since the Investment Funds and underlying assets are not publicly traded and/or often have liquidity restrictions. The managers of the Investment 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 Investment 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.

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The fair values, and actual allocations relative to the target allocations, of the Southern Company system's pension plans at December 31, 2025 and 2024 are presented below.

	Fair Value Measurements Using
	Quoted Prices<br><br>in Active<br><br>Markets for<br><br>Identical<br><br>Assets		Significant<br>Other<br>Observable<br>Inputs		Net Asset<br><br>Value as a<br><br>Practical<br><br>Expedient				Target<br><br>Allocation		Actual<br><br>Allocation
At December 31, 2025:	(Level 1)		(Level 2)		(NAV)		Total
	(in millions)
Southern Company
Assets:
Equity:									41	%	42	%
Domestic equity	$	2,216	$	884	$	—	$	3,100
International equity	2,219		1,184		—		3,403
Fixed income:									30		31
U.S. Treasury, government, and agency bonds	—		1,994		—		1,994
Mortgage- and asset-backed securities	—		75		—		75
Corporate bonds	—		1,859		—		1,859
Pooled funds	—		850		—		850
Cash equivalents and other	237		5		—		242
Real estate investments	350		—		1,541		1,891		12		12
Special situations	—		—		258		258		3		2
Private equity	—		—		1,829		1,829		9		11
Private credit	—		—		265		265		3		2
Infrastructure	—		—		60		60		2		—
Total	$	5,022	$	6,851	$	3,953	$	15,826	100	%	100	%
Liabilities:
Derivatives	$	(1)	$	—	$	—	$	(1)
Total	$	5,021	$	6,851	$	3,953	$	15,825	100	%	100	%
Alabama Power
Assets:
Equity:									41	%	42	%
Domestic equity	$	538	$	215	$	—	$	753
International equity	541		289		—		830
Fixed income:									30		31
U.S. Treasury, government, and agency bonds	—		486		—		486
Mortgage- and asset-backed securities	—		18		—		18
Corporate bonds	—		453		—		453
Pooled funds	—		207		—		207
Cash equivalents and other	58		1		—		59
Real estate investments	85		—		376		461		12		12
Special situations	—		—		63		63		3		2
Private equity	—		—		446		446		9		11
Private credit	—		—		65		65		3		2
Infrastructure	—		—		15		15		2		—
Total	$	1,222	$	1,669	$	965	$	3,856	100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices<br><br>in Active<br><br>Markets for<br><br>Identical<br><br>Assets		Significant<br>Other<br>Observable<br>Inputs		Net Asset<br><br>Value as a<br><br>Practical<br><br>Expedient				Target<br><br>Allocation		Actual<br><br>Allocation
At December 31, 2025:	(Level 1)		(Level 2)		(NAV)		Total		Target<br><br>Allocation		Actual<br><br>Allocation
	(in millions)
Georgia Power
Assets:
Equity:									41	%	42	%
Domestic equity	$	683	$	273	$	—	$	956
International equity	685		365		—		1,050
Fixed income:									30		31
U.S. Treasury, government, and agency bonds	—		615		—		615
Mortgage- and asset-backed securities	—		23		—		23
Corporate bonds	—		574		—		574
Pooled funds	—		262		—		262
Cash equivalents and other	73		2		—		75
Real estate investments	108		—		476		584		12		12
Special situations	—		—		80		80		3		2
Private equity	—		—		564		564		9		11
Private credit	—		—		82		82		3		2
Infrastructure	—		—		19		19		2		—
Total	$	1,549	$	2,114	$	1,221	$	4,884	100	%	100	%
Mississippi Power
Assets:
Equity:									41	%	42	%
Domestic equity	$	100	$	40	$	—	$	140
International equity	101		54		—		155
Fixed income:									30		31
U.S. Treasury, government, and agency bonds	—		91		—		91
Mortgage- and asset-backed securities	—		3		—		3
Corporate bonds	—		85		—		85
Pooled funds	—		39		—		39
Cash equivalents and other	11		—		—		11
Real estate investments	16		—		70		86		12		12
Special situations	—		—		12		12		3		2
Private equity	—		—		83		83		9		11
Private credit	—		—		12		12		3		2
Infrastructure	—		—		3		3		2		—
Total	$	228	$	312	$	180	$	720	100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices<br><br>in Active<br><br>Markets for<br><br>Identical<br><br>Assets		Significant<br>Other<br>Observable<br>Inputs		Net Asset<br><br>Value as a<br><br>Practical<br><br>Expedient				Target<br><br>Allocation		Actual<br><br>Allocation
At December 31, 2025:	(Level 1)		(Level 2)		(NAV)		Total		Target<br><br>Allocation		Actual<br><br>Allocation
	(in millions)
Southern Power
Assets:
Equity:									41	%	42	%
Domestic equity	$	29	$	12	$	—	$	41
International equity	29		15		—		44
Fixed income:									30		31
U.S. Treasury, government, and agency bonds	—		26		—		26
Mortgage- and asset-backed securities	—		1		—		1
Corporate bonds	—		24		—		24
Pooled funds	—		11		—		11
Cash equivalents and other	3		—		—		3
Real estate investments	5		—		20		25		12		12
Special situations	—		—		3		3		3		2
Private equity	—		—		24		24		9		11
Private credit	—		—		3		3		3		2
Infrastructure	—		—		1		1		2		—
Total	$	66	$	89	$	51	$	206	100%		100	%
Southern Company Gas
Assets:
Equity:									41	%	42	%
Domestic equity	$	148	$	59	$	—	$	207
International equity	149		79		—		228
Fixed income:									30		31
U.S. Treasury, government, and agency bonds	—		134		—		134
Mortgage- and asset-backed securities	—		5		—		5
Corporate bonds	—		125		—		125
Pooled funds	—		57		—		57
Cash equivalents and other	16		—		—		16
Real estate investments	23		—		103		126		12		12
Special situations	—		—		17		17		3		2
Private equity	—		—		123		123		9		11
Private credit	—		—		18		18		3		2
Infrastructure	—		—		4		4		2		—
Total	$	336	$	459	$	265	$	1,060	100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices<br><br>in Active<br><br>Markets for<br><br>Identical<br><br>Assets		Significant<br>Other<br>Observable<br>Inputs		Net Asset<br><br>Value as a<br><br>Practical<br><br>Expedient				Target<br><br>Allocation		Actual<br><br>Allocation
At December 31, 2024:	(Level 1)		(Level 2)		(NAV)		Total
	(in millions)
Southern Company
Assets:
Equity:									41	%	41	%
Domestic equity	$	2,095	$	835	$	—	$	2,930
International equity	1,959		1,032		—		2,991
Fixed income:									30		31
U.S. Treasury, government, and agency bonds	—		1,780		—		1,780
Mortgage- and asset-backed securities	—		48		—		48
Corporate bonds	—		1,715		—		1,715
Pooled funds	—		792		—		792
Cash equivalents and other	255		—		—		255
Real estate investments	361		—		1,563		1,924		12		13
Special situations	—		—		237		237		3		2
Private equity	—		—		1,797		1,797		9		12
Private Credit	—		—		152		152		3		1
Infrastructure	—		—		—		—		2		—
Total	$	4,670	$	6,202	$	3,749	$	14,621	100	%	100	%
Liabilities:
Derivatives	$	—	$	(33)	$	—	$	(33)
Total	$	4,670	$	6,169	$	3,749	$	14,588	100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices<br><br>in Active<br><br>Markets for<br><br>Identical<br><br>Assets		Significant<br>Other<br>Observable<br>Inputs		Net Asset<br><br>Value as a<br><br>Practical<br><br>Expedient				Target<br><br>Allocation		Actual<br><br>Allocation
At December 31, 2024:	(Level 1)		(Level 2)		(NAV)		Total		Target<br><br>Allocation		Actual<br><br>Allocation
	(in millions)
Alabama Power
Assets:
Equity:									41	%	41	%
Domestic equity	$	509	$	203	$	—	$	712
International equity	476		251		—		727
Fixed income:									30		31
U.S. Treasury, government, and agency bonds	—		433		—		433
Mortgage- and asset-backed securities	—		12		—		12
Corporate bonds	—		417		—		417
Pooled funds	—		193		—		193
Cash equivalents and other	62		—		—		62
Real estate investments	88		—		380		468		12		13
Special situations	—		—		57		57		3		2
Private equity	—		—		437		437		9		12
Private credit	—		—		37		37		3		1
Infrastructure	—		—		—		—		2		—
Total	$	1,135	$	1,509	$	911	$	3,555	100	%	100	%
Liabilities:
Derivatives	$	—	$	(8)	$	—	$	(8)
Total	$	1,135	$	1,501	$	911	$	3,547	100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices<br><br>in Active<br><br>Markets for<br><br>Identical<br><br>Assets		Significant<br>Other<br>Observable<br>Inputs		Net Asset<br><br>Value as a<br><br>Practical<br><br>Expedient				Target<br><br>Allocation		Actual<br><br>Allocation
At December 31, 2024:	(Level 1)		(Level 2)		(NAV)		Total		Target<br><br>Allocation		Actual<br><br>Allocation
	(in millions)
Georgia Power
Assets:
Equity:									41	%	41	%
Domestic equity	$	652	$	259	$	—	$	911
International equity	608		320		—		928
Fixed income:									30		31
U.S. Treasury, government, and agency bonds	—		552		—		552
Mortgage- and asset-backed securities	—		15		—		15
Corporate bonds	—		532		—		532
Pooled funds	—		246		—		246
Cash equivalents and other	79		—		—		79
Real estate investments	112		—		485		597		12		13
Special situations	—		—		73		73		3		2
Private equity	—		—		558		558		9		12
Private credit	—		—		47		47		3		1
Infrastructure	—		—		—		—		2		—
Total	$	1,451	$	1,924	$	1,163	$	4,538	100	%	100	%
Liabilities:
Derivatives	$	—	$	(10)	$	—	$	(10)
Total	$	1,451	$	1,914	$	1,163	$	4,528	100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices<br><br>in Active<br><br>Markets for<br><br>Identical<br><br>Assets		Significant<br>Other<br>Observable<br>Inputs		Net Asset<br><br>Value as a<br><br>Practical<br><br>Expedient				Target<br><br>Allocation		Actual<br><br>Allocation
At December 31, 2024:	(Level 1)		(Level 2)		(NAV)		Total		Target<br><br>Allocation		Actual<br><br>Allocation
	(in millions)
Mississippi Power
Assets:
Equity:									41	%	41	%
Domestic equity	$	97	$	38	$	—	$	135
International equity	89		47		—		136
Fixed income:									30		31
U.S. Treasury, government, and agency bonds	—		81		—		81
Mortgage- and asset-backed securities	—		2		—		2
Corporate bonds	—		78		—		78
Pooled funds	—		36		—		36
Cash equivalents and other	12		—		—		12
Real estate investments	16		—		71		87		12		13
Special situations	—		—		11		11		3		2
Private equity	—		—		82		82		9		12
Private credit	—		—		7		7		3		1
Infrastructure	—		—		—		—		2		—
Total	$	214	$	282	$	171	$	667	100	%	100	%
Liabilities:
Derivatives	$	—	$	(2)	$	—	$	(2)
Total	$	214	$	280	$	171	$	665	100	%	100	%
Southern Power
Assets:
Equity:									41	%	41	%
Domestic equity	$	27	$	11	$	—	$	38
International equity	25		13		—		38
Fixed income:									30		31
U.S. Treasury, government, and agency bonds	—		23		—		23
Mortgage- and asset-backed securities	—		1		—		1
Corporate bonds	—		22		—		22
Pooled funds	—		10		—		10
Cash equivalents and other	3		—		—		3
Real estate investments	5		—		20		25		12		13
Special situations	—		—		3		3		3		2
Private equity	—		—		23		23		9		12
Private credit	—		—		2		2		3		1
Infrastructure	—		—		—		—		2		—
Total	$	60	$	80	$	48	$	188	100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices<br><br>in Active<br><br>Markets for<br><br>Identical<br><br>Assets		Significant<br>Other<br>Observable<br>Inputs		Net Asset<br><br>Value as a<br><br>Practical<br><br>Expedient				Target<br><br>Allocation		Actual<br><br>Allocation
At December 31, 2024:	(Level 1)		(Level 2)		(NAV)		Total		Target<br><br>Allocation		Actual<br><br>Allocation
	(in millions)
Southern Company Gas
Assets:
Equity:									41	%	41	%
Domestic equity	$	142	$	56	$	—	$	198
International equity	132		69		—		201
Fixed income:									30		31
U.S. Treasury, government, and agency bonds	—		120		—		120
Mortgage- and asset-backed securities	—		3		—		3
Corporate bonds	—		115		—		115
Pooled funds	—		53		—		53
Cash equivalents and other	17		—		—		17
Real estate investments	24		—		105		129		12		13
Special situations	—		—		16		16		3		2
Private equity	—		—		121		121		9		12
Private credit	—		—		10		10		3		1
Infrastructure	—		—		—		—		2		—
Total	$	315	$	416	$	252	$	983	100	%	100	%
Liabilities:
Derivatives	$	—	$	(2)	$	—	$	(2)
Total	$	315	$	414	$	252	$	981	100	%	100	%

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The fair values, and actual allocations relative to the target allocations, of the applicable Registrants' other postretirement benefit plan assets at December 31, 2025 and 2024 are presented below.

	Fair Value Measurements Using
	Quoted Prices<br><br>in Active<br><br>Markets for<br><br>Identical<br><br>Assets		Significant<br>Other<br>Observable<br>Inputs		Net Asset<br><br>Value as a<br><br>Practical<br><br>Expedient		Total		Target<br><br>Allocation		Actual<br><br>Allocation
At December 31, 2025:	(Level 1)		(Level 2)		(NAV)
	(in millions)
Southern Company
Assets:
Equity:									60	%	63	%
Domestic equity	$	98	$	108	$	—	$	206
International equity	63		102		—		165
Fixed income:									30		27
U.S. Treasury, government, and agency bonds	—		61		—		61
Mortgage- and asset-backed securities	—		2		—		2
Corporate bonds	—		53		—		53
Pooled funds	—		106		—		106
Cash equivalents and other	13		—		—		13
Trust-owned life insurance	—		520		—		520
Real estate investments	11		—		44		55		4		4
Special situations	—		—		7		7		1		1
Private equity	—		—		52		52		3		4
Private credit	—		—		7		7		1		1
Infrastructure	—		—		2		2		1		—
Total	$	185	$	952	$	112	$	1,249	100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices<br><br>in Active<br><br>Markets for<br><br>Identical<br><br>Assets		Significant<br>Other<br>Observable<br>Inputs		Net Asset<br><br>Value as a<br><br>Practical<br><br>Expedient		Total		Target<br><br>Allocation		Actual<br><br>Allocation
At December 31, 2025:	(Level 1)		(Level 2)		(NAV)		Total		Target<br><br>Allocation		Actual<br><br>Allocation
	(in millions)
Alabama Power
Assets:
Equity:									68	%	69	%
Domestic equity	$	18	$	7	$	—	$	25
International equity	18		10		—		28
Fixed income:									23		23
U.S. Treasury, government, and agency bonds	—		17		—		17
Mortgage- and asset-backed securities	—		1		—		1
Corporate bonds	—		15		—		15
Pooled funds	—		11		—		11
Cash equivalents and other	2		—		—		2
Trust-owned life insurance	—		320		—		320
Real estate investments	3		—		13		16		3		3
Special situations	—		—		2		2		1		1
Private equity	—		—		15		15		3		3
Private credit	—		—		2		2		1		1
Infrastructure	—		—		—		—		1		—
Total	$	41	$	381	$	32	$	454	100	%	100	%
Georgia Power
Assets:
Equity:									59	%	60	%
Domestic equity	$	54	$	7	$	—	$	61
International equity	18		50		—		68
Fixed income:									35		32
U.S. Treasury, government, and agency bonds	—		17		—		17
Mortgage- and asset-backed securities	—		1		—		1
Corporate bonds	—		15		—		15
Pooled funds	—		51		—		51
Cash equivalents and other	8		—		—		8
Trust-owned life insurance	—		201		—		201
Real estate investments	4		—		13		17		3		3
Special situations	—		—		2		2		1		1
Private equity	—		—		15		15		2		3
Private credit	—		—		2		2		—		1
Total	$	84	$	342	$	32	$	458	100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices<br><br>in Active<br><br>Markets for<br><br>Identical<br><br>Assets		Significant<br>Other<br>Observable<br>Inputs		Net Asset<br><br>Value as a<br><br>Practical<br><br>Expedient		Total		Target<br><br>Allocation		Actual<br><br>Allocation
At December 31, 2025:	(Level 1)		(Level 2)		(NAV)		Total		Target<br><br>Allocation		Actual<br><br>Allocation
	(in millions)
Mississippi Power
Assets:
Equity:									34	%	34	%
Domestic equity	$	3	$	1	$	—	$	4
International equity	3		2		—		5
Fixed income:									43		43
U.S. Treasury, government, and agency bonds	—		7		—		7
Corporate bonds	—		3		—		3
Pooled funds	—		1		—		1
Cash equivalents and other	1		—		—		1
Real estate investments	—		—		2		2		10		10
Special situations	—		—		—		—		2		2
Private equity	—		—		3		3		7		9
Private credit	—		—		—		—		3		2
Infrastructure	—		—		—		—		1		—
Total	$	7	$	14	$	5	$	26	100	%	100	%
Southern Company Gas
Assets:
Equity:									72	%	74	%
Domestic equity	$	1	$	83	$	—	$	84
International equity	1		29		—		30
Fixed income:									26		24
U.S. Treasury, government, and agency bonds	—		1		—		1
Corporate bonds	—		1		—		1
Pooled funds	—		34		—		34
Cash equivalents and other	1		—		—		1
Real estate investments	—		—		1		1		1		1
Private equity	—		—		1		1		1		1
Total	$	3	$	148	$	2	$	153	100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices<br><br>in Active<br><br>Markets for<br><br>Identical<br><br>Assets		Significant<br>Other<br>Observable<br>Inputs		Net Asset<br><br>Value as a<br><br>Practical<br><br>Expedient				Target<br><br>Allocation		Actual<br><br>Allocation
At December 31, 2024:	(Level 1)		(Level 2)		(NAV)		Total
	(in millions)
Southern Company
Assets:
Equity:									61	%	62	%
Domestic equity	$	94	$	98	$	—	$	192
International equity	54		83		—		137
Fixed income:									29		28
U.S. Treasury, government, and agency bonds	—		54		—		54
Mortgage- and asset-backed securities	—		1		—		1
Corporate bonds	—		48		—		48
Pooled funds	—		99		—		99
Cash equivalents and other	16		—		—		16
Trust-owned life insurance	—		478		—		478
Real estate investments	11		—		43		54		4		5
Special situations	—		—		6		6		1		1
Private equity	—		—		50		50		3		4
Private credit	—		—		4		4		1		—
Infrastructure	—		—		—		—		1		—
Total	$	175	$	861	$	103	$	1,139	100	%	100	%
Liabilities:
Derivatives	$	—	$	(1)	$	—	$	(1)
Total	$	175	$	860	$	103	$	1,138	100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices<br><br>in Active<br><br>Markets for<br><br>Identical<br><br>Assets		Significant<br>Other<br>Observable<br>Inputs		Net Asset<br><br>Value as a<br><br>Practical<br><br>Expedient				Target<br><br>Allocation		Actual<br><br>Allocation
At December 31, 2024:	(Level 1)		(Level 2)		(NAV)		Total		Target<br><br>Allocation		Actual<br><br>Allocation
	(in millions)
Alabama Power
Assets:
Equity:									68	%	68	%
Domestic equity	$	17	$	7	$	—	$	24
International equity	16		9		—		25
Fixed income:									23		24
U.S. Treasury, government, and agency bonds	—		14		—		14
Corporate bonds	—		14		—		14
Pooled funds	—		11		—		11
Cash equivalents and other	2		—		—		2
Trust-owned life insurance	—		294		—		294
Real estate investments	3		—		13		16		3		4
Special situations	—		—		2		2		1		1
Private equity	—		—		15		15		3		3
Private credit	—		—		1		1		1		—
Infrastructure	—		—		—		—		1		—
Total	$	38	$	349	$	31	$	418	100	%	100	%
Georgia Power
Assets:
Equity:									59	%	59	%
Domestic equity	$	52	$	7	$	—	$	59
International equity	16		41		—		57
Fixed income:									35		33
U.S. Treasury, government, and agency bonds	—		14		—		14
Corporate bonds	—		14		—		14
Pooled funds	—		48		—		48
Cash equivalents and other	10		—		—		10
Trust-owned life insurance	—		184		—		184
Real estate investments	4		—		13		17		3		4
Special situations	—		—		2		2		1		1
Private equity	—		—		15		15		2		3
Total	$	82	$	308	$	30	$	420	100	%	100	%

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	Fair Value Measurements Using
	Quoted Prices<br><br>in Active<br><br>Markets for<br><br>Identical<br><br>Assets		Significant<br>Other<br>Observable<br>Inputs		Net Asset<br><br>Value as a<br><br>Practical<br><br>Expedient				Target<br><br>Allocation		Actual<br><br>Allocation
At December 31, 2024:	(Level 1)		(Level 2)		(NAV)		Total		Target<br><br>Allocation		Actual<br><br>Allocation
	(in millions)
Mississippi Power
Assets:
Equity:									34	%	32	%
Domestic equity	$	3	$	1	$	—	$	4
International equity	3		1		—		4
Fixed income:									43		44
U.S. Treasury, government, and agency bonds	—		7		—		7
Corporate bonds	—		2		—		2
Pooled funds	—		1		—		1
Cash equivalents and other	1		—		—		1
Real estate investments	—		—		2		2		10		11
Special situations	—		—		—		—		2		2
Private equity	—		—		2		2		7		10
Private credit	—		—		—		—		3		1
Infrastructure	—		—		—		—		1		—
Total	$	7	$	12	$	4	$	23	100	%	100	%
Southern Company Gas
Assets:
Equity:									72	%	73	%
Domestic equity	$	1	$	76	$	—	$	77
International equity	1		23		—		24
Fixed income:									26		25
U.S. Treasury, government, and agency bonds	—		1		—		1
Corporate bonds	—		1		—		1
Pooled funds	—		32		—		32
Cash equivalents and other	1		—		—		1
Real estate investments	—		—		1		1		1		1
Private equity	—		—		1		1		1		1
Total	$	3	$	133	$	2	$	138	100	%	100	%

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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 2025, 2024, and 2023 were as follows:

	Southern<br><br>Company		Alabama<br>Power		Georgia<br>Power		Mississippi<br>Power		Southern<br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
2025	$	148	$	30	$	36	$	5	$	3	$	21
2024	137		29		31		5		3		20
2023	131		28		31		5		3		18

12. STOCK COMPENSATION

Stock-based compensation 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 eligible Southern Company system employees.

At December 31, 2025, the number of current and former employees participating in stock-based compensation programs for the Registrants was as follows:

	Southern<br><br>Company	Alabama<br><br>Power	Georgia<br><br>Power	Mississippi<br><br>Power	Southern<br><br>Power	Southern<br><br>Company<br><br>Gas
Number of employees	1,189	163	185	37	33	182

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 are expected to 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.

All unvested PSUs and RSUs vest immediately upon a change in control where Southern Company is not the surviving corporation. Stock-based compensation activity is immaterial for the Subsidiary Registrants.

In 2015, Southern Company discontinued granting stock options. As of December 31, 2017, all stock option awards were vested and compensation cost fully recognized, and the last exercise occurred in November 2024. Southern Company's cash receipts from issuances related to stock options exercised under the share-based payment arrangements, total intrinsic value of options exercised, and the related tax benefit were immaterial for the years ended December 31, 2024 and 2023.

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

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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	2025	2024	2023
Expected volatility	19.7%	19.1%	30.0%
Interest rate	4.1%	4.0%	3.8%
Weighted average grant-date fair value	$91.26	$80.99	$76.83

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 2025, 2024, and 2023 was $84.06, $69.67, and $68.93, 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 2.3 million unvested PSUs outstanding at December 31, 2024. In February 2025, the PSUs that vested for the three-year performance period ended December 31, 2024 were converted into 2.0 million shares outstanding at a share price of $83.87. During 2025, Southern Company granted 1.0 million PSUs and 1.3 million PSUs were vested or forfeited, resulting in 2.0 million unvested PSUs outstanding at December 31, 2025. In February 2026, the PSUs that vested for the three-year performance period ended December 31, 2025 were converted into 2.4 million shares outstanding at a weighted average share price of $90.86.

Southern Company's total PSU compensation cost and the related tax benefit recognized in income for the years ended December 31, 2025, 2024, and 2023 were as follows:

	2025		2024		2023
	(in millions)
Compensation cost recognized in income	$	102	$	102	$	107
Tax benefit of compensation cost recognized in income	26		27		28

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.

At December 31, 2025, 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 18 months.

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 2025, 2024, and 2023 were $85.18, $70.49, and $68.95, 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, 2024. During 2025, 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, 2025, including RSUs related to employee retention agreements.

Southern Company's total RSU compensation cost and the related tax benefit recognized in income for the years ended December 31, 2025, 2024, and 2023 were as follows:

	2025		2024		2023
	(in millions)
Compensation cost recognized in income	$	33	$	30	$	30
Tax benefit of compensation cost recognized in income	9		8		8

Total unrecognized compensation cost related to RSUs at December 31, 2025, which is being recognized over a weighted-average period of approximately 18 months, was immaterial for Southern Company.

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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.

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.

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At December 31, 2025, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

	Fair Value Measurements Using
	Quoted Prices<br><br>in Active<br><br>Markets for<br><br>Identical<br><br>Assets		Significant<br><br>Other<br><br>Observable<br><br>Inputs		Significant<br><br>Unobservable<br><br>Inputs		Net Asset<br><br>Value as a<br><br>Practical<br><br>Expedient
At December 31, 2025:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives(a)	$	4	$	60	$	—	$	—	$	64
Interest rate derivatives	—		8		—		—		8
Foreign currency derivatives	—		21		—		—		21
Investments in trusts:(b)
Domestic equity	935		278		—		—		1,213
Foreign equity	182		225		—		—		407
U.S. Treasury and government agency securities	—		398		—		—		398
Municipal bonds	—		50		—		—		50
Pooled funds – fixed income	—		6		—		—		6
Corporate bonds	—		520		—		—		520
Mortgage- and asset-backed securities	—		114		—		—		114
Private equity	—		—		—		192		192
Cash and cash equivalents	1		—		—		—		1
Other	50		3		—		9		62
Investments, available for sale:
U.S. Treasury and government agency securities	3		12		—		—		15
Corporate bonds	1		2		—		—		3
Mortgage- and asset-backed securities	—		5		—		—		5
Cash equivalents	1,080		19		—		—		1,099
Other investments	10		34		8		—		52
Other	—		—		11		—		11
Total	$	2,266	$	1,755	$	19	$	201	$	4,241
Liabilities:
Energy-related derivatives(a)	$	12	$	100	$	—	$	—	$	112
Interest rate derivatives	—		187		—		—		187
Foreign currency derivatives	—		22		—		—		22
Contingent consideration	3		—		11		—		14
Other	—		13		11		—		24
Total	$	15	$	322	$	22	$	—	$	359

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	Fair Value Measurements Using
	Quoted Prices<br><br>in Active<br><br>Markets for<br><br>Identical<br><br>Assets		Significant<br><br>Other<br><br>Observable<br><br>Inputs		Significant<br><br>Unobservable<br><br>Inputs		Net Asset<br><br>Value as a<br><br>Practical<br><br>Expedient
At December 31, 2025:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Alabama Power
Assets:
Energy-related derivatives	$	—	$	19	$	—	$	—	$	19
Nuclear decommissioning trusts:(b)
Domestic equity	514		267		—		—		781
Foreign equity	182		—		—		—		182
U.S. Treasury and government agency securities	—		15		—		—		15
Municipal bonds	—		1		—		—		1
Corporate bonds	—		316		—		—		316
Mortgage- and asset-backed securities	—		31		—		—		31
Private equity	—		—		—		192		192
Other	12		1		—		9		22
Cash equivalents	273		19		—		—		292
Other investments	—		34		—		—		34
Total	$	981	$	703	$	—	$	201	$	1,885
Liabilities:
Energy-related derivatives	$	—	$	31	$	—	$	—	$	31
Georgia Power
Assets:
Energy-related derivatives	$	—	$	18	$	—	$	—	$	18
Nuclear decommissioning trusts:(b)
Domestic equity	421		1		—		—		422
Foreign equity	—		224		—		—		224
U.S. Treasury and government agency securities	—		383		—		—		383
Municipal bonds	—		49		—		—		49
Corporate bonds	—		204		—		—		204
Mortgage- and asset-backed securities	—		83		—		—		83
Other	38		2		—		—		40
Cash equivalents	20		—		—		—		20
Total	$	479	$	964	$	—	$	—	$	1,443
Liabilities:
Energy-related derivatives	$	—	$	33	$	—	$	—	$	33

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	Fair Value Measurements Using
	Quoted Prices<br><br>in Active<br><br>Markets for<br><br>Identical<br><br>Assets		Significant<br><br>Other<br><br>Observable<br><br>Inputs		Significant<br><br>Unobservable<br><br>Inputs		Net Asset<br><br>Value as a<br><br>Practical<br><br>Expedient
At December 31, 2025:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	14	$	—	$	—	$	14
Cash equivalents	12		—		—		—		12
Total	$	12	$	14	$	—	$	—	$	26
Liabilities:
Energy-related derivatives	$	—	$	27	$	—	$	—	$	27
Southern Power
Assets:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4
Foreign currency derivatives	—		17		—		—		17
Other	—		—		11		—		11
Total	$	—	$	21	$	11	$	—	$	32
Liabilities:
Energy-related derivatives	$	—	$	1	$	—	$	—	$	1
Contingent consideration	3		—		11		—		14
Other	—		13		11		—		24
Total	$	3	$	14	$	22	$	—	$	39
Southern Company Gas
Assets:
Energy-related derivatives(a)	$	4	$	5	$	—	$	—	$	9
Non-qualified deferred compensation trusts:
Domestic equity	—		10		—		—		10
Foreign equity	—		1		—		—		1
Pooled funds - fixed income	—		6		—		—		6
Cash and cash equivalents	1		—		—		—		1
Total	$	5	$	22	$	—	$	—	$	27
Liabilities:
Energy-related derivatives(a)	$	12	$	8	$	—	$	—	$	20
Interest rate derivatives	—		59		—		—		59
Total	$	12	$	67	$	—	$	—	$	79

(a)Excludes cash collateral of $33 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.

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At December 31, 2024, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

	Fair Value Measurements Using
	Quoted Prices<br><br>in Active<br><br>Markets for<br><br>Identical<br><br>Assets		Significant<br><br>Other<br><br>Observable<br><br>Inputs		Significant<br><br>Unobservable<br><br>Inputs		Net Asset<br><br>Value as a<br><br>Practical<br><br>Expedient
At December 31, 2024:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives(a)	$	12	$	77	$	—	$	—	$	89
Investments in trusts:(b)
Domestic equity	849		250		—		—		1,099
Foreign equity	148		175		—		—		323
U.S. Treasury and government agency securities	—		371		—		—		371
Municipal bonds	—		47		—		—		47
Pooled funds – fixed income	—		7		—		—		7
Corporate bonds	—		452		—		—		452
Mortgage- and asset-backed securities	—		106		—		—		106
Private equity	—		—		—		181		181
Cash and cash equivalents	1		—		—		—		1
Other	39		3		—		9		51
Investment, available for sale:
U.S. Treasury and government agency securities	2		7		—		—		9
Corporate bonds	1		2		—		—		3
Mortgage- and asset-backed securities	—		10		—		—		10
Cash equivalents and restricted cash	533		19		—		—		552
Other investments	9		31		8		—		48
Total	$	1,594	$	1,557	$	8	$	190	$	3,349
Liabilities:
Energy-related derivatives(a)	$	5	$	124	$	—	$	—	$	129
Interest rate derivatives	—		269		—		—		269
Foreign currency derivatives	—		218		—		—		218
Contingent consideration	3		—		16		—		19
Other	—		13		11		—		24
Total	$	8	$	624	$	27	$	—	$	659

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	Fair Value Measurements Using
	Quoted Prices<br><br>in Active<br><br>Markets for<br><br>Identical<br><br>Assets		Significant<br><br>Other<br><br>Observable<br><br>Inputs		Significant<br><br>Unobservable<br><br>Inputs		Net Asset<br><br>Value as a<br><br>Practical<br><br>Expedient
At December 31, 2024:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Alabama Power
Assets:
Energy-related derivatives	$	—	$	26	$	—	$	—	$	26
Nuclear decommissioning trusts:(b)
Domestic equity	459		241		—		—		700
Foreign equity	148		—		—		—		148
U.S. Treasury and government agency securities	—		16		—		—		16
Municipal bonds	—		1		—		—		1
Corporate bonds	—		287		—		—		287
Mortgage- and asset-backed securities	—		31		—		—		31
Private equity	—		—		—		181		181
Other	11		1		—		9		21
Cash equivalents and restricted cash	334		19		—		—		353
Other investments	—		31		—		—		31
Total	$	952	$	653	$	—	$	190	$	1,795
Liabilities:
Energy-related derivatives	$	—	$	42	$	—	$	—	$	42
Georgia Power
Assets:
Energy-related derivatives	$	—	$	19	$	—	$	—	$	19
Nuclear decommissioning trusts:(b)
Domestic equity	390		1		—		—		391
Foreign equity	—		174		—		—		174
U.S. Treasury and government agency securities	—		355		—		—		355
Municipal bonds	—		46		—		—		46
Corporate bonds	—		165		—		—		165
Mortgage- and asset-backed securities	—		75		—		—		75
Other	28		2		—		—		30
Cash equivalents	35		—		—		—		35
Total	$	453	$	837	$	—	$	—	$	1,290
Liabilities:
Energy-related derivatives	$	—	$	42	$	—	$	—	$	42
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	19	$	—	$	—	$	19
Liabilities:
Energy-related derivatives	$	—	$	34	$	—	$	—	$	34

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	Fair Value Measurements Using
	Quoted Prices<br><br>in Active<br><br>Markets for<br><br>Identical<br><br>Assets		Significant<br><br>Other<br><br>Observable<br><br>Inputs		Significant<br><br>Unobservable<br><br>Inputs		Net Asset<br><br>Value as a<br><br>Practical<br><br>Expedient
At December 31, 2024:	(Level 1)		(Level 2)		(Level 3)		(NAV)		Total
	(in millions)
Southern Power
Assets:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4
Cash equivalents	51		—		—		—		51
Total	$	51	$	4	$	—	$	—	$	55
Liabilities:
Foreign currency derivatives	—		51		—		—		51
Contingent consideration	3		—		16		—		19
Other	—		13		11		—		24
Total	$	3	$	64	$	27	$	—	$	94
Southern Company Gas
Assets:
Energy-related derivatives(a)	$	12	$	9	$	—	$	—	$	21
Non-qualified deferred compensation trusts:
Domestic equity	—		8		—		—		8
Foreign equity	—		1		—		—		1
Pooled funds - fixed income	—		7		—		—		7
Cash and cash equivalents	1		—		—		—		1
Investments, available-for-sale:
U.S. Treasury and government agency securities	2		7		—		—		9
Corporate bonds	1		2		—		—		3
Mortgage- and asset-backed securities	—		10		—		—		10
Cash equivalents	22		—		—		—		22
Total	$	38	$	44	$	—	$	—	$	82
Liabilities:
Energy-related derivatives(a)	$	5	$	6	$	—	$	—	$	11
Interest rate derivatives	—		84		—		—		84
Total	$	5	$	90	$	—	$	—	$	95

(a)Excludes cash collateral of $17 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.

Valuation Methodologies

The energy-related derivatives primarily consist of exchange-traded and OTC 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 OTC 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,

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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 Company's investments, available for sale relate to a wholly-owned subsidiary that insures various risk exposures of Southern Company and its subsidiaries. Corporate and municipal bonds, government agency securities, and commercial paper are valued using pricing models maximizing the use of observable inputs for similar securities, including basing value on yields currently available on comparable securities of issues with similar credit ratings. Mortgage- and asset-backed securities are valued through an analysis of the underlying assets and a review of the documentation, including financials, the manager's valuation methodology in valuing their underlying assets, the types of assets and risks involved, and the investor's exit and termination parameters.

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 2036, 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 the obligations 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 $201 million and $190 million at December 31, 2025 and 2024, respectively. Unfunded commitments related to the private market investments totaled $83 million and $78 million at December 31, 2025 and 2024, 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.

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At December 31, 2025 and 2024, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Southern<br><br>Company(*)		Alabama<br><br>Power		Georgia<br><br>Power		Mississippi<br><br>Power		Southern<br><br>Power		Southern<br><br>Company<br><br>Gas(*)
	(in billions)
At December 31, 2025:
Long-term debt, including securities due within one year:
Carrying amount	$	71.1	$	12.0	$	20.8	$	1.8	$	2.9	$	9.3
Fair value	67.2		10.9		19.4		1.6		2.9		8.4
At December 31, 2024:
Long-term debt, including securities due within one year:
Carrying amount	$	63.2	$	11.2	$	18.1	$	1.7	$	2.7	$	8.5
Fair value	57.7		9.8		16.2		1.5		2.6		7.4

(*)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. 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.

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 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 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 reflected in natural gas revenues.

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

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

•Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in 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, 2025, 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<br>Purchased<br>mmBtu	Longest<br>Hedge<br>Date	Longest<br>Non-Hedge<br>Date
	(in millions)
Southern Company(*)	431	2030	2029
Alabama Power	126	2028	—
Georgia Power	128	2028	—
Mississippi Power	106	2030	—
Southern Power	8	2030	2026
Southern Company Gas(*)	63	2028	2029

(*)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 72 million mmBtu and short natural gas positions of 9 million mmBtu at December 31, 2025, 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 15 million mmBtu for Southern Company, which includes 4 million mmBtu for Alabama Power, 6 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, 2026 are immaterial for Southern Company, Southern Power, and 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.

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COMBINED NOTES TO FINANCIAL STATEMENTS

At December 31, 2025, the following interest rate derivatives were outstanding:

	Notional<br>Amount		Weighted Average<br><br>Interest Rate Paid	Interest<br>Rate<br>Received	Hedge<br>Maturity<br>Date	Fair Value<br>Gain (Loss) at<br>December 31, 2025
	(in millions)					(in millions)
Fair Value Hedges of Existing Debt
Southern Company parent	$	400	1-day SOFR + 0.80%	1.75%	March 2028	$	(24)
Southern Company parent	1,000		1-day SOFR + 2.48%	3.70%	April 2030	(95)
Southern Company parent	565		1-day SOFR + 1.56%	6.50%	March 2045	(1)
Southern Company Gas	500		1-day SOFR + 0.49%	1.75%	January 2031	(59)
Southern Company	$	2,465				$	(179)

For cash flow hedges of interest rate derivatives, the estimated pre-tax gains (losses) expected to be reclassified from AOCI to interest expense for the year ending December 31, 2026 are immaterial for Southern Company, 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, 2025, the following foreign currency derivatives were outstanding:

	Pay<br><br>Notional		Pay Rate	Receive<br><br>Notional		Receive<br><br>Rate	Hedge<br><br>Maturity Date	Fair Value<br>Gain (Loss) at<br>December 31, 2025
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	564	3.78%	€	500	1.85%	June 2026	$	17
Fair Value Hedges of Existing Debt
Southern Company parent	1,476		3.39%	1,250		1.88%	September 2027	(18)
Southern Company	$	2,040		€	1,750			$	(1)

For cash flow hedges of foreign currency derivatives, the estimated pre-tax gains expected to be reclassified from AOCI to earnings for the year ending December 31, 2026 are $17 million for Southern Power.

Derivative Financial Statement Presentation and Amounts

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

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The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected as either assets or liabilities in the balance sheets (included in "Other" or shown separately as "Risk Management Activities") as follows:

	At December 31, 2025				At December 31, 2024
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)
Southern Company
Energy-related derivatives designated as hedging instruments for regulatory purposes
Current	$	24	$	64	$	33	$	82
Non-current	31		35		42		40
Total derivatives designated as hedging instruments for regulatory purposes	55		99		75		122
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Current	1		6		4		3
Non-current	2		1		4		—
Interest rate derivatives:
Current	8		48		—		61
Non-current	—		139		—		208
Foreign currency derivatives:
Current	17		22		—		36
Non-current	4		—		—		182
Total derivatives designated as hedging instruments in cash flow and fair value hedges	32		216		8		490
Energy-related derivatives not designated as hedging instruments
Current	6		6		5		3
Non-current	—		—		1		—
Total derivatives not designated as hedging instruments	6		6		6		3
Gross amounts recognized	93		321		89		615
Gross amounts offset(a)	(21)		(54)		(44)		(61)
Net amounts recognized in the Balance Sheets(b)	$	72	$	267	$	45	$	554
Alabama Power
Energy-related derivatives designated as hedging instruments for regulatory purposes
Current	$	9	$	18	$	11	$	30
Non-current	10		13		15		12
Total derivatives designated as hedging instruments for regulatory purposes	19		31		26		42
Gross amounts offset	(13)		(13)		(19)		(19)
Net amounts recognized in the Balance Sheets	$	6	$	18	$	7	$	23

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	At December 31, 2025				At December 31, 2024
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)
Georgia Power
Energy-related derivatives designated as hedging instruments for regulatory purposes
Current	$	7	$	23	$	6	$	32
Non-current	10		10		13		9
Total derivatives designated as hedging instruments for regulatory purposes	17		33		19		41
Energy-related derivatives not designated as hedging instruments
Current	1		—		—		1
Gross amounts recognized	18		33		19		42
Gross amounts offset	(14)		(14)		(15)		(15)
Net amounts recognized in the Balance Sheets	$	4	$	19	$	4	$	27
Mississippi Power
Energy-related derivatives designated as hedging instruments for regulatory purposes
Current	$	3	$	15	$	5	$	15
Non-current	11		12		14		19
Total derivatives designated as hedging instruments for regulatory purposes	14		27		19		34
Gross amounts offset	(13)		(13)		(17)		(17)
Net amounts recognized in the Balance Sheets	$	1	$	14	$	2	$	17
Southern Power
Derivatives designated as hedging instruments in cash flow hedges
Energy-related derivatives:
Current	$	1	$	1	$	1	$	—
Non-current	2		—		3		—
Foreign currency derivatives:
Current	17		—		—		11
Non-current	—		—		—		40
Total derivatives designated as hedging instruments in cash flow hedges	20		1		4		51
Energy-related derivatives not designated as hedging instruments
Current	1		—		—		—
Net amounts recognized in the Balance Sheets	$	21	$	1	$	4	$	51

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	At December 31, 2025				At December 31, 2024
Derivative Category and Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
	(in millions)
Southern Company Gas
Energy-related derivatives designated as hedging instruments for regulatory purposes
Current	$	5	$	8	$	11	$	5
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Current	—		5		3		3
Non-current	—		1		1		—
Interest rate derivatives:
Current	—		13		—		17
Non-current	—		46		—		67
Total derivatives designated as hedging instruments in cash flow and fair value hedges	—		65		4		87
Energy-related derivatives not designated as hedging instruments
Current	4		6		5		2
Non-current	—		—		1		—
Total derivatives not designated as hedging instruments	4		6		6		2
Gross amounts recognized	9		79		21		94
Gross amounts offset(a)	19		(14)		7		(10)
Net amounts recognized in the Balance Sheets(b)	$	28	$	65	$	28	$	84

(a)Gross amounts offset includes cash collateral held on deposit in broker margin accounts of $33 million and $17 million at December 31, 2025 and 2024, respectively.

(b)Net amounts of derivative instruments outstanding exclude immaterial premium and intrinsic value associated with weather derivatives at December 31, 2025 and 2024.

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At December 31, 2025 and 2024, 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<br>Location	Southern<br>Company		Alabama<br>Power		Georgia<br>Power		Mississippi<br>Power		Southern<br><br>Company<br><br>Gas
	(in millions)
At December 31, 2025:
Energy-related derivatives:
Other regulatory assets, current	$	(48)	$	(13)	$	(17)	$	(12)	$	(6)
Other regulatory assets, deferred	(8)		(5)		(1)		(2)		—
Other regulatory liabilities, current	7		4		1		—		2
Other regulatory liabilities, deferred	4		2		1		1		—
Total energy-related derivative gains (losses)	$	(45)	$	(12)	$	(16)	$	(13)	$	(4)
At December 31, 2024:
Energy-related derivatives:
Other regulatory assets, current	$	(61)	$	(23)	$	(26)	$	(11)	$	(1)
Other regulatory assets, deferred	(5)		—		—		(5)		—
Other regulatory liabilities, current	8		4		—		—		4
Other regulatory liabilities, deferred	8		3		4		1		—
Total energy-related derivative gains (losses)	$	(50)	$	(16)	$	(22)	$	(15)	$	3

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For the years ended December 31, 2025, 2024, and 2023, 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	2025		2024		2023
	(in millions)
Southern Company
Cash flow hedges:
Energy-related derivatives	$	(8)	$	(7)	$	(81)
Interest rate derivatives	6		23		(12)
Foreign currency derivatives	58		(40)		14
Fair value hedges(*):
Foreign currency derivatives	(22)		16		21
Total	$	34	$	(8)	$	(58)
Georgia Power
Cash flow hedges:
Interest rate derivatives	$	4	$	24	$	(2)
Mississippi Power
Cash flow hedges:
Interest rate derivatives	$	(1)	$	7	$	—
Southern Power
Cash flow hedges:
Energy-related derivatives	$	(1)	$	(1)	$	(18)
Foreign currency derivatives	58		(40)		14
Total	$	57	$	(41)	$	(4)
Southern Company Gas
Cash flow hedges:
Energy-related derivatives	$	(6)	$	(6)	$	(63)
Interest rate derivatives	2		(5)		—
Total	$	(4)	$	(11)	$	(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.

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The pre-tax effects of cash flow and fair value hedge accounting on income for the years ended December 31, 2025, 2024, and 2023 were as follows:

		Gain (Loss)
Statements of Income Location	Derivative Category	2025		2024		2023
		(in millions)
Southern Company
Fuel	Energy-related cash flow hedges	$	1	$	(6)	$	(23)
Cost of natural gas	Energy-related cash flow hedges	(3)		(40)		(44)
Other operations and maintenance	Energy-related cash flow hedges	—		(2)		(2)
Interest expense, net of amounts capitalized	Interest rate cash flow hedges	(13)		(16)		(35)
	Foreign currency cash flow hedges	(10)		(12)		(11)
	Interest rate fair value hedges	90		(4)		37
Other income (expense), net	Foreign currency cash flow hedges	68		(33)		19
	Foreign currency fair value hedges	149		2		69
	Amount excluded from effectiveness testing recognized in earnings	22		(16)		(21)
Southern Power
Fuel	Energy-related cash flow hedges	$	1	$	(6)	$	(23)
Interest expense, net of amounts capitalized	Foreign currency cash flow hedges	(10)		(12)		(11)
Other income (expense), net	Foreign currency cash flow hedges	68		(33)		19
Southern Company Gas
Cost of natural gas	Energy-related cash flow hedges	$	(3)	$	(40)	$	(44)
Other operations and maintenance	Energy-related cash flow hedges	—		(2)		(2)
Interest expense, net of amounts capitalized	Interest rate cash flow hedges	(1)		(1)		(19)
	Interest rate fair value hedges	25		(5)		6

At December 31, 2025 and 2024, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:

	Carrying Amount of<br>the Hedged Item				Cumulative Amount of Fair Value<br><br>Hedging Adjustment included in<br><br>Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items	At December 31, 2025		At December 31, 2024		At December 31, 2025		At December 31, 2024
	(in millions)				(in millions)
Southern Company
Long-term debt	$	(3,742)	$	(2,936)	$	156	$	242
Southern Company Gas
Long-term debt	$	(446)	$	(422)	$	51	$	75

Pre-tax gains (losses) on energy-related derivatives not designated as hedging instruments were $(11) million, $94 million, and $59 million for the years ended December 31, 2025, 2024, and 2023, respectively, and reflected in cost of natural gas on the statements of income of Southern Company and Southern Company Gas.

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, 2025, the Registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

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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 $20 million at December 31, 2025. For Southern Power, there were no foreign currency derivative liabilities with contingent features or associated collateral requirements arising from the credit-risk-related contingent features at a rating below BBB- and/or Baa3 at December 31, 2025. 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, 2025. 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, 2025, 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, which are netted with energy-related derivatives recognized in the balance sheets.

The Registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Registrants generally enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's, S&P, or Fitch 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.

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

15. ACQUISITIONS AND DISPOSITIONS

Alabama Power

On September 30, 2025, Alabama Power completed its acquisition of Tenaska Alabama Partners, L.P., which owned and operated the Lindsay Hill Generating Station, an approximately 879.7-MW combined cycle generation facility in Autauga County, Alabama. The transaction was accounted for as a business combination. The total purchase price was $635 million, of which $622 million was related to net assets recorded within property, plant, and equipment and the remainder was included in inventory, current receivables, and accounts payable on the balance sheet. The transaction was recorded as a business acquisition within the investing section of the statement of cash flows. Alabama Power assumed an existing power sales agreement under which the full output of the generating facility remains committed to a non-affiliated third party through April 2027. See Note 2 under "Alabama Power – Rate CNP New Plant" for additional information.

Mississippi Power

On July 30, 2025, Mississippi Power completed the acquisition of FP&L's 50% ownership interest in Plant Daniel Units 1 and 2 and, as part of the acquisition, received approximately $36 million from FP&L. See Note 2 under "Mississippi Power – Plant Daniel" for additional information.

Southern Power

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.

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Asset Acquisitions

During 2023, Southern Power acquired the Millers Branch and South Cheyenne projects, as discussed further under "Construction Projects" below, with an aggregate purchase price of $193 million. There were no asset acquisitions during 2024 and 2025.

Construction Projects

During 2024, Southern Power completed construction of and placed in service the 150-MW South Cheyenne solar facility. During 2025, Southern Power continued construction of the three phases of the 512-MW Millers Branch solar facility. At December 31, 2025, the total cost of construction incurred for the Millers Branch project was $694 million, which is primarily included in CWIP. The ultimate outcome of these matters cannot be determined at this time.

Project<br>Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Projected COD	PPA Contract Period
Projects Under Construction at December 31, 2025
Millers Branch
Phase I	Solar	200	Haskell County, TX	February 2026(*)	20 years
Phase II	Solar	180	Haskell County, TX	Second quarter 2026	15 years
Phase III	Solar	132	Haskell County, TX	Fourth quarter 2026	15 years
Projects Completed During 2024
South Cheyenne	Solar	150	Laramie County, WY	April 2024	20 years

(*)Subsequent to December 31, 2025, Southern Power completed construction of the 200-MW first phase of the Millers Branch solar facility.

Wind Repowering Projects

During 2025, Southern Power continued the development project to repower the Kay wind facility and began development projects to repower the Grant Plains, Grant, Wake, and Bethel wind facilities. At December 31, 2025, the total cost of construction incurred related to the projects was $358 million and is included in CWIP. The repowered output of the facilities is contracted under new and amended PPAs. The ultimate outcome of these matters cannot be determined at this time.

Project Facility	Resource	Approximate Nameplate Capacity<br><br>(MW)	Location	Projected COD
Projects Under Construction at December 31, 2025
Kay(*)	Wind	200	Kay County, OK	Third quarter 2026
Grant Plains	Wind	147	Grant County, OK	Fourth quarter 2026
Grant	Wind	152	Grant County, OK	Fourth quarter 2026
Wake	Wind	257	Crosby & Floyd Counties, TX	Second quarter 2027
Bethel	Wind	276	Castro County, TX	Third quarter 2027

(*)The facility has a total capacity of 299 MWs, of which 200 MWs is projected to be repowered and is contracted under a PPA.

Purchase of Renewable Facility Interests

On December 31, 2025, Southern Power completed the purchase of 100% of the noncontrolling Class A membership interests in SP Wind from the three financial investors for approximately $282 million. Since Southern Power retains control of SP Wind, the purchase was accounted for as an equity transaction, and Southern Power will continue to consolidate SP Wind in its financial statements. On the date of the transaction, noncontrolling interest was reduced by $242 million. The difference in the purchase price and the carrying value of the noncontrolling interest resulted in a $36 million non-cash decrease to Southern Power's common stockholders' equity, net of deferred tax remeasurement. See Note 7 under "Southern Power – Variable Interest Entities – SP Wind" for additional information.

16. SEGMENT AND RELATED INFORMATION

The Registrants adopted ASU 2023-07 and applied the guidance retrospectively effective for the fiscal year beginning January 1, 2024. See Note 1 under "Recently Adopted Accounting Standards" for additional information.

The CODM at Southern Company, the traditional electric operating companies, and Southern Company Gas is the chairman, president, and chief executive officer of such Registrant. Southern Power's CODM consists of the chairman and chief executive officer and the president. The CODMs assess segment performance using net income that is reflected on the Registrants'

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respective statements of income as net income attributable to the registrant or net income, as applicable. The CODMs use net income in the annual budget and forecasting process and consider budget versus actual results on a monthly basis when making decisions about the allocation of resources. Asset information by segment is not utilized by the CODMs for purposes of assessing performance or allocating resources.

Southern Company

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 distribution of natural gas and other complementary products and services by Southern Company Gas. While the traditional electric operating companies represent three separate operating segments, they are vertically integrated utilities providing electric service to retail customers, as well as wholesale customers, in the Southeast and have been aggregated into one reportable segment. The "All Other" presentation includes the Southern Company parent entity, which does not allocate operating expenses to business segments, and operating segments below the quantitative threshold for separate disclosure. These operating segments include providing distributed energy and resilience solutions and deploying microgrids for commercial, industrial, governmental, and utility customers, as well as investments in telecommunications. Revenues from sales by Southern Power to the traditional electric operating companies were $437 million, $371 million, and $537 million in 2025, 2024, and 2023, respectively. All other inter-segment revenues were immaterial for all periods presented.

Southern Company's CODM utilizes segment net income, including variances to budget and forecasts, to assess performance and is not provided with segment expense information. To achieve the consolidated net income goal, Southern Company's CODM sets net income expectations for each operating segment, which is expected to monitor its expenses in order to achieve its assigned net income target. Therefore, Southern Company has no reportable significant segment expenses.

Financial data for business segments and products and services for the years ended December 31, 2025, 2024, and 2023 was as follows:

	Electric Utilities
	Traditional<br>Electric<br>Operating<br>Companies		Southern<br>Power		Eliminations		Total		Southern<br><br>Company<br><br>Gas		Total<br><br>Reportable<br><br>Segments		All<br>Other		Eliminations		Consolidated
	(in millions)
2025
Operating revenues	$	22,056	$	2,198	$	(477)	$	23,777	$	5,044	$	28,821	$	893	$	(161)	$	29,553
Other segment items(a)(b)(c)	11,157		1,187		(477)		11,867		3,172		15,039		872		(154)		15,757
Depreciation and amortization(d)	3,882		843		—		4,725		708		5,433		68		—		5,501
Earnings from equity method investments	6		—		—		6		127		133		(21)		—		112
Interest expense(e)	1,341		104		—		1,445		377		1,822		1,416		—		3,238
Income taxes (benefit)	1,100		(61)		—		1,039		182		1,221		(393)		—		828
Segment net income (loss)(b)(c)(d)(e)(f)	$	4,582	$	125	$	—	$	4,707	$	732	$	5,439	$	(1,091)	$	(7)	$	4,341
At December 31, 2025
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	5,017	$	144	$	—	$	5,161
Total assets	114,287		12,657		(915)		126,029		27,387		153,416		2,829		(525)		155,720

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	Electric Utilities
	Traditional<br>Electric<br>Operating<br>Companies		Southern<br>Power		Eliminations		Total		Southern<br><br>Company<br><br>Gas		Total<br><br>Reportable<br><br>Segments		All<br>Other		Eliminations		Consolidated
	(in millions)
2024
Operating revenues	$	19,977	$	2,014	$	(388)	$	21,603	$	4,456	$	26,059	$	843	$	(178)	$	26,724
Other segment items(a)(b)(g)(h)	10,057		1,060		(388)		10,729		2,613		13,342		802		(149)		13,995
Depreciation and amortization(d)	3,512		522		—		4,034		650		4,684		71		—		4,755
Earnings from equity method investments	8		—		—		8		146		154		(17)		2		139
Interest expense	1,255		117		—		1,372		341		1,713		1,030		—		2,743
Income taxes (benefit)	1,016		(13)		—		1,003		258		1,261		(292)		—		969
Segment net income (loss)(b)(d)(f)(g)(h)	$	4,145	$	328	$	—	$	4,473	$	740	$	5,213	$	(785)	$	(27)	$	4,401
At December 31, 2024
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	5,017	$	144	$	—	$	5,161
Total assets	105,577		12,653		(1,025)		117,205		26,177		143,382		2,371		(573)		145,180
2023
Operating revenues	$	18,358	$	2,189	$	(549)	$	19,998	$	4,702	$	24,700	$	718	$	(165)	$	25,253
Other segment items(a)(b)(c)(i)	9,643		1,187		(549)		10,281		3,124		13,405		699		(150)		13,954
Depreciation and amortization	3,361		504		—		3,865		582		4,447		78		—		4,525
Earnings from equity method investments	(1)		—		—		(1)		140		139		5		—		144
Interest expense	1,145		129		—		1,274		310		1,584		879		(17)		2,446
Income taxes (benefit)	571		12		—		583		211		794		(298)		—		496
Segment net income (loss)(b)(c)(f)(i)	$	3,637	$	357	$	—	$	3,994	$	615	$	4,609	$	(635)	$	2	$	3,976
At December 31, 2023
Goodwill	$	—	$	2	$	—	$	2	$	5,015	$	5,017	$	144	$	—	$	5,161
Total assets	100,429		12,761		(545)		112,645		25,083		137,728		2,446		(843)		139,331

(a)Primarily consists of fuel, purchased power, cost of natural gas, cost of other sales, other operations and maintenance (including credits to income for estimated probable losses, regulatory disallowances, losses (gains) on asset dispositions, and impairment charges), taxes other than income taxes, AFUDC equity, non-service cost-related retirement benefits income, and net income (loss) attributable to noncontrolling interests.

(b)For the traditional electric operating companies, includes pre-tax credits to income at Georgia Power for the estimated probable loss associated with the construction and completion of Plant Vogtle Units 3 and 4 of $60 million ($45 million after tax) in 2025, $21 million ($16 million after tax) in 2024, and $68 million ($50 million after tax) in 2023. See Note 2 under "Georgia Power – Nuclear Construction" for additional information.

(c)For Southern Company Gas, includes pre-tax charges associated with the disallowance of certain capital investments at Nicor Gas totaling approximately $63 million ($47 million after tax) in 2025 and $96 million ($72 million after tax) in 2023. See Note 2 under "Southern Company Gas" for additional information.

(d)For Southern Power, includes accelerated depreciation related to the repowering of multiple wind facilities of $307 million ($221 million after tax, net of noncontrolling interest impacts) in 2025 and $9 million ($7 million after tax, net of noncontrolling interest impacts) in 2024. See Note 15 under "Southern Power –Wind Repowering Projects" for additional information.

(e)For All Other, includes a pre-tax loss of $252 million ($189 million after tax) associated with the extinguishment of debt at the parent company. See Note 8 under "Convertible Senior Notes" for additional information.

(f)Attributable to Southern Company.

(g)For the traditional electric operating companies, includes a pre-tax impairment loss at Alabama Power of $36 million ($27 million after tax) related to Alabama Power discontinuing the development of a multi-use commercial facility. See Note 1 under "Impairment of Long-Lived Assets" for additional information.

(h)For the traditional electric operating companies, includes a pre-tax gain at Georgia power of approximately $114 million ($84 million after tax) related to the sale of transmission line assets under the integrated transmission system agreement. See Note 2 under "Georgia Power – Transmission Asset Sales" for additional information.

(i)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.

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COMBINED NOTES TO FINANCIAL STATEMENTS

Products and Services

Electric Utilities' Revenues
Year	Retail		Wholesale		Other		Total
	(in millions)
2025	$	19,331	$	2,940	$	1,506	$	23,777
2024	17,790		2,431		1,382		21,603
2023	16,343		2,467		1,188		19,998			Southern Company Gas' Revenues
---	---	---	---	---	---	---
Year	Gas<br>Distribution<br>Operations		Gas<br>Marketing<br>Services		Other		Total
	(in millions)
2025	$	4,428	$	582	$	34	$	5,044
2024	3,899		516		41		4,456
2023	4,090		548		64		4,702

Traditional Electric Operating Companies

Each of the traditional electric operating companies' single reportable business segment is the sale of electricity. Revenues from products and services of the traditional electric operating companies are segregated into retail, wholesale, and other as reflected on their statements of income.

Alabama Power and Georgia Power have identified utility operations and maintenance expenses as significant segment expenses provided to their CODMs. Utility operations and maintenance expenses is calculated as other operations and maintenance, as reflected on the statements of income, less expenses from unregulated products and services, losses (gains) on asset dispositions, impairment charges, amortization of cloud software, and, for Georgia Power, charges (credits) for estimated loss on Plant Vogtle Units 3 and 4. Alabama Power's utility operations and maintenance expenses are disaggregated into expenses related to Rate RSE and Rate CNP Compliance. See Note 2 under "Alabama Power" for additional information.

During the third and fourth quarters of 2025, Mississippi Power updated the information provided to its CODM. As a result, Mississippi Power has identified certain operational and environmental compliance expenses as significant segment expenses and has recast prior period information to conform to the current period presentation.

Financial data for significant segment expenses and other segment information for the years ended December 31, 2025, 2024, and 2023 was as follows:

	2025		2024		2023
	(in millions)
Alabama Power
Operating revenues	$	8,235	$	7,554	$	7,050
Utility operations and maintenance
Rate RSE expenses	1,636		1,480		1,421
Rate CNP Compliance expenses	292		279		254
Total utility operations and maintenance	1,928		1,759		1,675
Other segment items(a)(b)	2,391		2,125		2,098
Depreciation and amortization	1,510		1,459		1,401
Interest expense	465		448		425
Income taxes	425		360		81
Segment net income(b)	$	1,516	$	1,403	$	1,370
Capital expenditures	$	2,508	$	2,114	$	2,159

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COMBINED NOTES TO FINANCIAL STATEMENTS

	2025		2024		2023
	(in millions)
Georgia Power
Operating revenues	$	12,631	$	11,331	$	10,118
Utility operations and maintenance	2,339		2,210		1,901
Other segment items(a)(c)(d)	3,972		3,476		3,382
Depreciation and amortization	2,074		1,774		1,681
Interest expense	793		725		626
Income taxes	602		603		448
Segment net income(c)(d)	$	2,851	$	2,543	$	2,080
Capital expenditures	$	8,140	$	5,355	$	5,394
Mississippi Power
Operating revenues	$	1,695	$	1,463	$	1,474
Operational expenses(e)	264		254		265
Environmental compliance expenses(f)	16		12		10
Other segment items(a)	845		681		714
Depreciation and amortization	211		193		190
Interest expense	79		77		71
Income taxes	65		47		36
Segment net income	$	215	$	199	$	188
Capital expenditures	$	320	$	357	$	342

(a)Primarily consists of fuel, purchased power, expenses from unregulated products and services, losses (gains) on asset dispositions, amortization of cloud software, taxes other than income taxes, AFUDC equity, and non-service cost-related retirement benefits income. For Alabama Power, includes impairment charges. For Georgia Power, includes credits for estimated loss on Plant Vogtle Units 3 and 4. For Mississippi Power, includes employee benefit expenses. Also includes earnings from equity method investments, which were immaterial for all periods presented.

(b)For 2024, includes a pre-tax impairment loss of $36 million ($27 million after tax) related to Alabama Power discontinuing the development of a multi-use commercial facility. See Note 1 under "Impairment of Long-Lived Assets" for additional information.

(c)Includes pre-tax credits to income for the estimated probable loss associated with the construction and completion of Plant Vogtle Units 3 and 4 of $60 million ($45 million after tax) in 2025, $21 million ($16 million after tax) in 2024, and $68 million ($50 million after tax) in 2023. See Note 2 under "Georgia Power – Nuclear Construction" for additional information.

(d)For 2024, includes a pre-tax gain of approximately $114 million ($84 million after tax) related to the sale of transmission line assets under the integrated transmission system agreement. See Note 2 under "Georgia Power – Transmission Asset Sales" for additional information.

(e)Consists of certain operations and maintenance expenses related to PEP and the MRA tariff, including labor costs, materials, contract services, and other normal operational costs. See Note 2 under "Mississippi Power" for additional information regarding PEP and the MRA tariff.

(f)Consists of environmental compliance expenses related to ECO Plan and the MRA tariff. See Note 2 under "Mississippi Power" for additional information regarding ECO Plan and the MRA tariff.

Southern Power

Southern Power's single reportable business segment is the sale of electricity in the competitive wholesale market. Substantially all of Southern Power's revenues from products and services are reflected as wholesale on its consolidated statements of income. Southern Power's CODM utilizes segment expense information in the form of variances to budget to assess performance; therefore, Southern Power has no reportable significant segment expenses.

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COMBINED NOTES TO FINANCIAL STATEMENTS

Financial data for segment information for the years ended December 31, 2025, 2024, and 2023 was as follows:

	2025		2024		2023
	(in millions)
Operating revenues	$	2,198	$	2,014	$	2,189
Other segment items(a)(b)	1,187		1,060		1,187
Depreciation and amortization(c)	843		522		504
Interest expense	104		117		129
Income taxes (benefit)	(61)		(13)		12
Segment net income(b)(c)(d)	$	125	$	328	$	357

(a)Primarily consists of fuel, purchased power, other operations and maintenance, taxes other than income taxes, losses (gains) on asset dispositions, and net income (loss) attributable to noncontrolling interests.

(b)For 2023, 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.

(c)Includes accelerated depreciation of $307 million ($221 million after tax, net of noncontrolling interest impacts) in 2025 and $9 million ($7 million after tax, net of noncontrolling interest impacts) in 2024 related to the repowering of multiple wind facilities. See Note 15 under "Southern Power –Wind Repowering Projects" for additional information.

(d)Southern Power had no earnings from equity method investments for any period presented.

Southern Company Gas

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

The gas distribution operations segment 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.

The gas pipeline investments segment 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.

The gas marketing services segment provides natural gas marketing to end-use customers primarily in Georgia through SouthStar.

The "All Other" presentation includes operating segments and subsidiaries that fall below the quantitative threshold for separate disclosure.

Southern Company Gas' CODM utilizes segment expense information in the form of variances to budget to assess performance; therefore, Southern Company Gas has no reportable significant segment expenses.

Financial data for business segments for the years ended December 31, 2025, 2024, and 2023 was as follows:

	Gas<br><br>Distribution<br><br>Operations		Gas<br><br>Pipeline<br><br>Investments		Gas<br><br>Marketing<br><br>Services		Total<br><br>Reportable<br><br>Segments		All<br><br>Other		Eliminations		Consolidated
	(in millions)
2025
Operating revenues	$	4,428	$	32	$	582	$	5,042	$	12	$	(10)	$	5,044
Other segment items(a)(b)	2,721		5		444		3,170		12		(10)		3,172
Depreciation and amortization	687		5		14		706		2		—		708
Earnings from equity method investments	—		127		—		127		—		—		127
Interest expense	342		36		3		381		(4)		—		377
Income taxes	109		28		34		171		11		—		182
Segment net income (loss)(b)	$	569	$	85	$	87	$	741	$	(9)	$	—	$	732
Total assets at December 31, 2025	$	25,391	$	1,475	$	1,749	$	28,615	$	10,643	$	(11,871)	$	27,387

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COMBINED NOTES TO FINANCIAL STATEMENTS

	Gas<br><br>Distribution<br><br>Operations		Gas<br><br>Pipeline<br><br>Investments		Gas<br><br>Marketing<br><br>Services		Total<br><br>Reportable<br><br>Segments		All<br><br>Other		Eliminations		Consolidated
	(in millions)
2024
Operating revenues	$	3,899	$	32	$	516	$	4,447	$	23	$	(14)	$	4,456
Other segment items(a)	2,236		6		356		2,598		29		(14)		2,613
Depreciation and amortization	630		5		14		649		1		—		650
Earnings from equity method investments	—		146		—		146		—		—		146
Interest expense	311		35		3		349		(8)		—		341
Income taxes	172		31		41		244		14		—		258
Segment net income (loss)	$	550	$	101	$	102	$	753	$	(13)	$	—	$	740
Total assets at December 31, 2024	$	24,067	$	1,573	$	1,696	$	27,336	$	10,047	$	(11,206)	$	26,177
2023
Operating revenues	$	4,105	$	32	$	548	$	4,685	$	36	$	(19)	$	4,702
Other segment items(a)(b)	2,702		5		402		3,109		34		(19)		3,124
Depreciation and amortization	561		5		15		581		1		—		582
Earnings from equity method investments	—		140		—		140		—		—		140
Interest expense	275		32		3		310		—		—		310
Income taxes	126		32		37		195		16		—		211
Segment net income (loss)(b)	$	441	$	98	$	91	$	630	$	(15)	$	—	$	615
Total assets at December 31, 2023	$	22,906	$	1,534	$	1,615	$	26,055	$	9,675	$	(10,647)	$	25,083

(a)Primarily consists of cost of natural gas, other operations and maintenance, taxes other than income taxes, estimated loss on regulatory disallowance, AFUDC equity, and non-service cost-related retirement benefits income.

(b)For gas distribution operations, includes pre-tax charges associated with the disallowance of certain capital investments at Nicor Gas totaling approximately $63 million ($47 million after tax) in 2025 and $96 million ($72 million after tax) in 2023. See Note 2 under "Southern Company Gas" for additional information.

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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
Southern Company	II-255
Alabama Power	II-256
Georgia Power	II-257
Mississippi Power	II-258
Southern Power	II-259
Southern Company Gas	II-260

(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 2025 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

The following table reports information regarding the adoption 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, 2025 for Southern Company's directors and "officers," as defined in Rule 16a-1(f) under the Securities Exchange Act of 1934, as amended. There were no modifications or terminations of such trading arrangements during the three months ended December 31, 2025. Unless otherwise indicated, each trading arrangement listed below is a "Rule 10b5-1 trading arrangement," provides for the sale of shares of Southern Company's common stock, commences no earlier than the expiration of the cooling-off period required by Rule 10b5-1(c)(1)(ii)(B)(1) under the Securities Exchange Act of 1934, as amended, and terminates upon the earlier of the

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"Expiration Date" listed below or the completion of all sales. The Subsidiary Registrants had no reportable trading arrangements for the three months ended December 31, 2025.

Name	Title	Date of Adoption	Expiration Date	Aggregate Number of Shares Covered
Stanley W. Connally, Jr.	Executive Vice President and Chief Operating Officer	November 17, 2025	March 16, 2027	12,500
Christopher Cummiskey	Executive Vice President	November 18, 2025	March 9, 2027	8,954(1)
Matthew M. Kim	Comptroller	November 25, 2025	February 24, 2027	6,353(1)
Sterling A. Spainhour	Executive Vice President and Chief Legal Officer	November 25, 2025	September 1, 2027	9,443
Kimberly S. Greene	Chairman, President, and Chief Executive Officer of Georgia Power	November 26, 2025	March 30, 2027	65,000

(1)Includes shares underlying equity awards subject to performance conditions and accrual of dividend-equivalent rights. Accordingly, the total number of shares ultimately available for sale could be more or less than the amount shown. The amount shown is based on the target number of shares subject to equity awards and the dividend-equivalent rights accrued as of the date of adoption.

Item 9C.DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

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MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Southern Company and Subsidiary Companies

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, 2025.

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, 2025, which is included herein.

/s/ Christopher C. Womack

Christopher C. Womack

Chairman, President, and Chief Executive Officer

/s/ David P. Poroch

David P. Poroch

Executive Vice President, Chief Financial Officer, and Treasurer

February 18, 2026

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MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Alabama Power Company

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, 2025.

/s/ J. Jeffrey Peoples

J. Jeffrey Peoples

Chairman, President, and Chief Executive Officer

/s/ Moses H. Feagin

Moses H. Feagin

Executive Vice President, Chief Financial Officer, and Treasurer

February 18, 2026

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MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Georgia Power Company

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, 2025.

/s/ Kimberly S. Greene

Kimberly S. Greene

Chairman, President, and Chief Executive Officer

/s/ Tyler M. Cook

Tyler M. Cook

Senior Vice President, Chief Financial Officer, and Treasurer

February 18, 2026

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MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Mississippi Power Company

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, 2025.

/s/ Pedro P. Cherry

Pedro P. Cherry

Chairman, President, and Chief Executive Officer

/s/ Matthew P. Grice

Matthew P. Grice

Vice President, Chief Financial Officer, and Treasurer

February 18, 2026

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MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Southern Power Company and Subsidiary Companies

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, 2025.

/s/ Christopher Cummiskey

Christopher Cummiskey

Chairman and Chief Executive Officer

/s/ Gary Kerr

Gary Kerr

Senior Vice President, Chief Financial Officer, and Treasurer

February 18, 2026

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MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Southern Company Gas and Subsidiary Companies

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, 2025.

/s/ James Y. Kerr II

James Y. Kerr II

Chairman, President, and Chief Executive Officer

/s/ Grace A. Kolvereid

Grace A. Kolvereid

Executive Vice President, Chief Financial Officer, and Treasurer

February 18, 2026

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PART III

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 2026 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 Laura O. Hewett, 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.

Insider Trading Policies and Procedures

Each of the Registrants has adopted a Prohibition of Securities Trading Policy governing, among other items, the purchase, sale, and/or other dispositions of such Registrant's securities by directors, officers, and employees. Each Prohibition of Securities Trading Policy is reasonably designed to promote compliance with insider trading laws, rules, and regulations, and any listing standards applicable to such Registrant. The Prohibition of Securities Trading Policies do not address transactions in the Registrants' securities by the Registrants themselves; however, pursuant to the Code of Ethics, which, among other items, requires each Registrant to comply with all laws and regulations, it is the policy of each Registrant to comply with applicable securities laws and regulations with respect to any such transactions. Copies of the Prohibition of Securities Trading Policy for each Registrant are filed as Exhibits 19(a)-(f) to this Annual Report on Form 10-K.

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Item 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following represents fees billed to the Subsidiary Registrants in 2025 and 2024 by Deloitte & Touche LLP, each company's principal public accountant:

	2025		2024
	(in thousands)
Alabama Power
Audit Fees (a)	$	4,098	$	3,663
Audit-Related Fees (b)	92		128
Tax Fees	—		—
All Other Fees (c)	113		46
Total	$	4,303	$	3,837
Georgia Power
Audit Fees (a)	$	6,668	$	6,216
Audit-Related Fees (b)	154		196
Tax Fees	—		—
All Other Fees (c)	155		29
Total	$	6,977	$	6,441
Mississippi Power
Audit Fees (a)	$	681	$	697
Audit-Related Fees (b)	17		25
Tax Fees	—		—
All Other Fees (c)	25		7
Total	$	723	$	729
Southern Power
Audit Fees (a)	$	1,106	$	1,028
Audit-Related Fees (d)	2,130		2,478
Tax Fees	—		—
All Other Fees (c)	4		33
Total	$	3,240	$	3,539
Southern Company Gas
Audit Fees (a)(e)	$	2,626	$	2,711
Audit-Related Fees (b)	1,239		297
Tax Fees	—		—
All Other Fees (c)	12		11
Total	$	3,877	$	3,019

(a)Includes services performed in connection with financing transactions.

(b)Represents fees for statutory and non-statutory audit services and other attest services.

(c)Represents registration fees for attendance at Deloitte & Touche LLP-sponsored education seminars and other non-audit advisory services.

(d)Represents fees in connection with audits of Southern Power partnerships, other statutory and non-statutory audit services, and other attest services.

(e)Includes fees in connection with statutory audits of several Southern Company Gas subsidiaries.

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 2025 and 2024 and related fees were approved in advance by the Southern Company Audit Committee.

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PART IV

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.

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SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

FOR THE YEARS ENDED DECEMBER 31, 2025, 2024, AND 2023

			Additions
Description	Balance at Beginning of Period		Charged to Income		Charged to Other Accounts		Deductions(*)		Balance at End of Period
	(in millions)
Provision for uncollectible accounts:
Southern Company
2025	$	74	$	127	$	7	$	124	$	84
2024	68		119		(1)		112		74
2023	71		87		3		93		68
Alabama Power
2025	$	22	$	22	$	—	$	21	$	23
2024	16		26		—		20		22
2023	14		16		—		14		16
Georgia Power
2025	$	15	$	52	$	—	$	60	$	7
2024	4		51		—		40		15
2023	3		26		—		25		4
Mississippi Power
2025	$	1	$	2	$	—	$	2	$	1
2024	1		2		—		2		1
2023	1		2		—		2		1
Southern Power
2025	$	—	$	—	$	—	$	—	$	—
2024	1		(1)		—		—		—
2023	1		—		—		—		1
Southern Company Gas
2025	$	33	$	50	$	7	$	40	$	50
2024	44		39		(1)		49		33
2023	50		43		3		52		44

(*)Deductions represent write-offs of accounts considered to be uncollectible, less recoveries of amounts previously written off.

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SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS (CONTINUED)

FOR THE YEARS ENDED DECEMBER 31, 2025, 2024, AND 2023

			Additions
Description	Balance at Beginning of Period		Charged to Income		Charged to Other Accounts		Deductions		Balance at End of Period
	(in millions)
Tax valuation allowance (net state):
Southern Company(a)(b)(c)
2025	$	268	$	128	$	—	$	39	$	357
2024	168		97		3		—		268
2023	207		(14)		(25)		—		168
Georgia Power(b)
2025	$	124	$	126	$	—	$	39	$	211
2024	60		97		(33)		—		124
2023	98		(15)		(23)		—		60
Mississippi Power(c)
2025	$	32	$	—	$	—	$	—	$	32
2024	32		—		—		—		32
2023	32		—		—		—		32
Southern Power(c)
2025	$	21	$	2	$	—	$	—	$	23
2024	21		—		—		—		21
2023	21		—		—		—		21
Southern Company Gas(c)
2025	$	4	$	—	$	—	$	—	$	4
2024	5		—		(1)		—		4
2023	7		—		(2)		—		5

(a)In 2024, Southern Company established a valuation allowance for certain Georgia state tax credits expected to expire prior to being fully utilized.

(b)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.

(c)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.

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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
	Southern Company
		(a)	1	—	Restated Certificate of Incorporation of Southern Company and amendments thereto through May 27, 2025. (Designated inForm 10-K for the year ended December 31, 2018, File No. 1-3526, as Exhibit 3(a)1 and inhttps://www.sec.gov/Archives/edgar/data/92122/000009212225000059/ex3-1sorestatedcertificate.htmForm 8-K dated May 21, 2025. File No. 1-3526, as Exhibit 3.1.)
		(a)	2	—	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.)
	Alabama Power
		(b)	1	—	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 4.5, 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 4.5.)
		(b)	2	—	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.)
	Georgia Power
		(c)	1	—	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), inForm 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)	2	—	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.)
	Mississippi Power
		(d)	1	—	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)	2	—	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.)

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	Southern Power
		(e)	1	—	Certificate of Incorporation of Southern Power Company dated January 8, 2001. (Designated in Registration No. 333-98553 as Exhibit 3.1.)
		(e)	2	—	By-laws of Southern Power Company effective January 8, 2001. (Designated in Registration No. 333-98553 as Exhibit 3.2.)
	Southern Company Gas
		(f)	1	—	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)	2	—	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.
	Southern Company
		(a)	1	—	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 November 6, 2025. (Designated in Form 8-K dated Januaryhttps://www.sec.gov/Archives/edgar/data/92122/000009212207000006/ex4-1.txt11, 2007, File No.https://www.sec.gov/Archives/edgar/data/92122/000009212207000006/ex4-1.txt1-3526, as Exhibit 4.1, in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(e), inForm 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(b), in Form 8-K dated May 15, 2023, File No. 1-3526, as Exhibit 4.4(a), inForm 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), in Form 8-K dated September 5, 2023, File No. 1-3526, as Exhibit 4.4(b), in Form 8-K dated May 9, 2024, File No. 1-3526, as Exhibit 4.2, in Form 8-K dated September 4, 2024, File No. 1-3526, as Exhibit 4.2, inhttps://www.sec.gov/Archives/edgar/data/92122/000009212225000060/ex4-2so34thsupplementalind.htmForm 8-K dated May 20, 2025, File No. 1-3526,as Exhibit 4.2, in Form 8-K dated November 3, 2025, File No, 1-3526, as Exhibit 4.2(a), and in Form 8-K dated November 3, 2025, File No. 1-3526,as Exhibit 4.2(b).)
		(a)	2	—	Subordinated Note Indenture dated as of October 1, 2015, between Southern Company and Computershare Trust Company, N.A., as successor Trustee, and certain indentures supplemental thereto through February 28, 2025. (Designated in Form 8-K dated October 1, 2015, File No. 1-3526, as Exhibit 4.3, inForm 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(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(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(b), in Form 8-K dated January 8, 2025, File No. 1-3526, as Exhibit 4.4, and in Form 8-K datedFebruary 25, 2025, File No. 1-3526,as Exhibit 4.4.)
		(a)	3	—	Purchase Contract and Pledge Agreement, dated as of November 6, 2025, between Southern Company and U.S. Bank Trust Company, National Association, as Purchase Contract Agent, Collateral Agent, Custodial Agent, and Securities Intermediary. (Designated in Form 8-K dated November 3, 2025, File No. 1-3526, as Exhibit 4.9.)
	*	(a)	4	—	Description of securities registered pursuant to Section 12 of the Securities Exchange Act of 1934, as amended.

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Alabama Power
	(b)	1	—	Senior Note Indenture dated as of December 1, 1997, between Alabama Power and Regions Bank, as Successor Trustee, and certain indentures supplemental thereto through September 5, 2025. (Designated in Form 8-K dated Decemberhttps://www.sec.gov/Archives/edgar/data/3153/0000003153-97-000035.txt4, 1997, File No.https://www.sec.gov/Archives/edgar/data/3153/0000003153-97-000035.txt1-3164, as Exhibit 4.1, in Form 8-K dated Februaryhttps://www.sec.gov/Archives/edgar/data/3153/000000315303000009/ex4-2a.txt11, 2003, File No.https://www.sec.gov/Archives/edgar/data/3153/000000315303000009/ex4-2a.txt1-3164, as Exhibit 4.2(a), in Form 8-K dated Marchhttps://www.sec.gov/Archives/edgar/data/3153/000000315303000013/ex4-1.txt12, 2003, File No.https://www.sec.gov/Archives/edgar/data/3153/000000315303000013/ex4-1.txt1-3164, as Exhibit 4.2, in Form 8-K dated Mayhttps://www.sec.gov/Archives/edgar/data/3153/000009212208000036/exhibit42.txt8, 2008, File No.https://www.sec.gov/Archives/edgar/data/3153/000009212208000036/exhibit42.txt1-3164, as Exhibit 4.2, in Form 8-K dated February 26, 2009, File No.https://www.sec.gov/Archives/edgar/data/3153/000009212209000020/x4-2al8k.htm1-3164,as Exhibit 4.2, in Form 8-K dated Marchhttps://www.sec.gov/Archives/edgar/data/3153/000009212211000020/ex4-2.htm3, 2011, File No.https://www.sec.gov/Archives/edgar/data/3153/000009212211000020/ex4-2.htm1-3164, as Exhibit 4.2, in Form 8-K dated Mayhttps://www.sec.gov/Archives/edgar/data/3153/000009212211000079/x4-2b.htm18, 2011, File No.https://www.sec.gov/Archives/edgar/data/3153/000009212211000079/x4-2b.htm1-3164, as Exhibit 4.2(b), in Form 8-K dated Januaryhttps://www.sec.gov/Archives/edgar/data/3153/000009212212000006/x4-2.htm10, 2012, File No.https://www.sec.gov/Archives/edgar/data/3153/000009212212000006/x4-2.htm1-3164, 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 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, in Form 8-K dated November 6, 2023, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated March 20, 2025, File No. 1-3164,as Exhibit 4.6, in Form 8-K dated June 11, 2025, File No. 1-3164,as Exhibit 4.6, and in Form 8-K datedSeptember 2, 2025, File No. 1-3164,as Exhibit 4.6.)
Georgia Power
	(c)	1	—	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 September 29, 2025. (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), inhttps://www.sec.gov/Archives/edgar/data/41091/000004109119000019/ga60thsupindenture2019.htmForm 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), in Form 8-K dated February 20, 2024, File No. 1-6468, as Exhibit 4.2(a), in Form 8-K dated February 20, 2024, File No. 1-6468, as Exhibit 4.2(b), in Form 8-K dated November 8, 2024, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated December 2, 2024, File No. 1-6468, as Exhibit 4.2, inForm 8-K datedFebruary 24, 2025, File No. 1-6468, as Exhibit 4.3(a), in Form 8-K datedhttps://www.sec.gov/Archives/edgar/data/41091/000004109125000022/ex4-3bgpc74thsupplementali.htmFebruary 24, 2025, File No. 1-6468, as Exhibit 4.3(b), in Form 8-K datedFebruary 24, 2025, File No. 1-6468, as Exhibit 4.3(c), in Form 8-K dated September 24, 2025, File No. 1-6468, asExhibit 4.3(b), and inForm 8-K dated September 24, 2025, File No. 1-6468, as Exhibit 4.3(c).)
	(c)	2	—	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)	3	—	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.https://www.sec.gov/Archives/edgar/data/41091/000004109119000004/x4-1ga8xkardoeloanguarante.htm1-6468, as Exhibithttps://www.sec.gov/Archives/edgar/data/41091/000004109119000004/x4-1ga8xkardoeloanguarante.htm4.1.)
	(c)	4	—	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)	5	—	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.https://www.sec.gov/Archives/edgar/data/41091/000004109114000002/gadoeloan8-kexhibit4x3.htm1-6468, as Exhibithttps://www.sec.gov/Archives/edgar/data/41091/000004109114000002/gadoeloan8-kexhibit4x3.htm4.3.)
	(c)	6	—	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.https://www.sec.gov/Archives/edgar/data/41091/000004109119000004/x4-4ga8xkardoeloanguarante.htm1-6468, as Exhibithttps://www.sec.gov/Archives/edgar/data/41091/000004109119000004/x4-4ga8xkardoeloanguarante.htm4.4.)

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	(c)	7	—	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 Exhibithttps://www.sec.gov/Archives/edgar/data/41091/000004109119000004/x4-5ga8xkardoeloanguarante.htm4.5.)
	(c)	8	—	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)	9	—	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)	10	—	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.)
Mississippi Power
	(d)	1	—	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 Mayhttps://www.sec.gov/Archives/edgar/data/66904/0000066904-98-000012.txt14, 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)	2	—	Senior Note Indenture dated as of June 1, 2023, between Mississippi Power and Regions Bank, as Trustee, and certain indentures supplemental thereto through March 28, 2025. (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, in Form 10-Q for the quarter ended June 30, 2023, File No. 001-11229, as Exhibit 4(d)3, in Form 10-Q for the quarter ended March 31, 2024, File No. 001-11229, as Exhibit 4(d)1, inForm 10-Q for the quarter ended March 31, 2024, File No. 001-11229, as Exhibit 4(d)2,in Form 10-Q for the quarter ended June 30, 2024, File No. 001-11229, as Exhibit 4(d)1, in Form 10-Q for thequarter endedMarch 31, 2025, File No. 001-11229, as Exhibit 4(d)1, and inForm 10-Q for the quarter ended March 31, 2025, File No.001-11229, as Exhibithttps://www.sec.gov/Archives/edgar/data/66904/000009212225000042/ex4-d2mpcformsupplementali.htm4(d)2.)
Southern Power
	(e)	1	—	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.https://www.sec.gov/Archives/edgar/data/1160661/000116066102000001/ex4-1.txt333-98553 as Exhibit 4.1, in Form 8-K dated Septemberhttps://www.sec.gov/Archives/edgar/data/1160661/000009212211000120/x4-4.htm14, 2011, File No.https://www.sec.gov/Archives/edgar/data/1160661/000009212211000120/x4-4.htm333-98553, 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 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, and in Form 8-K dated November 10, 2016, File No. 001-37803, as Exhibit 4.4(c).)
	(e)	2	—	Senior Note Indenture dated as of August 1, 2025 between Southern Power Company and U.S. Bank Trust Company, National Association, as Trustee, and certain indentures supplemental thereto through September 19, 2025. (Designated in Registration No. 333-289172 as Exhibit 4.5, in Form 8-K datedSeptember 16, 2025, FileNo.001-37803asExhibit4.6(a), and in Form 8-K dated September 16, 2025, File No. 001-37803 asExhibit 4.6(b).)
	(e)	3	—	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.)
Southern Company Gas
	(f)	1	—	Indenture dated February 20, 2001 among 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.)

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(f)	2	—	Southern Company Gas Capital Corporation's 6.00% Senior Notes due 2034, 5.875% Senior Notes due 2041, 4.40% Senior Notes due 2043, 3.250% 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, Form of Series 2023A 5.75% Senior Note due September 15, 2033, and Form of Series 2024A 4.95% Senior Note due September 15, 2034. (Designated in Form 8-K dated September 22, 2004, File No. 1-14174, as Exhibithttps://www.sec.gov/Archives/edgar/data/1004155/000100415504000086/exhibit4-1.htm4.1, in Form 8-K dated March 16, 2011, File No.https://www.sec.gov/Archives/edgar/data/1004155/000100415511000058/exhibit_4-1.htm1-14174, as Exhibit 4.1, in Form 8-K dated May 13, 2013, File No. 1-14174, as Exhibithttps://www.sec.gov/Archives/edgar/data/1004155/000100415513000042/exhibit4_2.htm4.2, 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, inForm 8-K dated September 6, 2022, File No. 1-14174, as Exhibit 4.1, in Form 8-K dated September 11, 2023, File No. 1-14174, as Exhibit 4.1, and in Form 8-K dated September 3, 2024, File No. 1-14174, as Exhibit 4.1, respectively.)
(f)	3	—	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 3.250% 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, Form of Guarantee related to the Series 2023A 5.75% Senior Notes Due September 15, 2033, and Form of Guarantee related to the Series 2024A 4.95% Senior Notes due September 15, 2034. (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 May 13, 2016, File No. 1-14174, as Exhibit 4.3, 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, and in Form 8-K dated September 3, 2024, File No. 1-14174, as Exhibit 4.3, respectively.)
(f)	4	—	Indenture dated as of February 1, 2025 among Southern Company Gas Capital Corporation, Southern Company Gas, and U.S. Bank Trust Company, National Association, as Trustee. (Designated in Registration No.333-285115, as Exhibit 4.2.)
(f)	5	—	Southern Company Gas Capital Corporation's Form of Series 2025A 4.05% Senior Notes due September 15, 2028 and Form of Series 2025B 5.10% Senior Notes due September 15, 2035. (Designated in Form 8-K dated September 3, 2025, File No. 1-14174,as Exhibit4.1(a) and in Form 8-K dated September 3, 2025, File No. 1-14174,as Exhibit4.1(b), respectively.)
(f)	6	—	Southern Company Gas' Form of Guarantee related to the Series 2025A 4.05% Senior Notes due September 15, 2028 and Form of Guarantee related to the Series 2025B 5.10% Senior Notes due September 15, 2035. (Designated in Form 8-K dated September 3, 2025, File No. 1-14174,as Exhibit4.3(a) and in Form 8-K dated September 3, 2025, File No. 1-14174,as Exhibit4.3(b), respectively.)
(f)	7	—	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).)

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		(f)	8	—	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 4.10, 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, in Form 10-Q for the quarter ended September 30, 2023, File No. 1-4174, as Exhibit 4(f)3, in Form 10-Q for the quarter ended September 30, 2024, File No. 1-4174, as Exhibit 4(f)3, and in Form 10-Q for the quarter ended September 30, 2025, File No. 1-4174, as Exhibit 4(f)6.)
(10)	Material Contracts
	Southern Company
	#	(a)	1	—	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.)
	#	(a)	2	—	Southern Company Deferred Compensation Plan, Amended and Restated as of January 1, 2025. (Designated in Form 10-K for the year ended December 31, 2024, File No. 1-3526 as Exhibit 10(a)2.)
	#	(a)	3	—	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)	4	—	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)	5	—	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.)

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	#	(a)	6	—	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 inForm 10-K for the year ended Decemberhttps://www.sec.gov/Archives/edgar/data/3153/000009212201500065/x10a103.txt31, 2000, File No.https://www.sec.gov/Archives/edgar/data/3153/000009212201500065/x10a103.txt1-3526, as Exhibit 10(a)103 and in Form 10-K for the year ended Decemberhttps://www.sec.gov/Archives/edgar/data/3153/000009212209000011/x10a16.htm31, 2008, File No.https://www.sec.gov/Archives/edgar/data/3153/000009212209000011/x10a16.htm1-3526, as Exhibit 10(a)16.)
	#	(a)	7	—	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)	8	—	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)	9	—	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)	10	—	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.)
	#	(a)	11	—	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)	12	—	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, Sixth Amendment thereto effective July 1, 2021, Seventh Amendment thereto dated December 23, 2022, Eighth Amendment thereto dated December 13, 2023, and Ninth Amendment thereto dated December 16, 2024. (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, in Form 10-K for the year ended December 31, 2022, File No. 1-3526, as Exhibit 10(a)17, in Form 10-K for the year ended December 31, 2023, File No. 1-3526, as Exhibit 10(a)17, and in Form 10-K for thehttps://www.sec.gov/Archives/edgar/data/3153/000009212225000018/ex10a-139thamendmentto2018.htmyear ended December 31, 2024, File No. 1-3526, as Exhibit 10(a)13.)
*		(a)	13	—	Tenthamendment to the Southern Company Employee Savings Plan, datedDecember 12, 2025.
	#	(a)	14	—	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)	15	—	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.)
*	#	(a)	16	—	Consulting Agreement between SCS and Daniel S. Tucker dated August 11, 2025.
*	#	(a)	17	—	Deferred Compensation AgreementamongSouthern Company, SCS,and David P. Porochex10a-17porochdca.htmeffectiveJanuary 4, 2012.
	Alabama Power
		(b)	1	—	Intercompany Interchange Contract as revised effective May 1, 2007, among Alabama Power, Georgia Power, Gulf Power Company, 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.https://www.sec.gov/Archives/edgar/data/3153/000009212207000045/x10b5.htm1-3164, 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.)

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	Georgia Power
		(c)	1	—	Intercompany Interchange Contract as revised effective May 1, 2007, among Alabama Power, Georgia Power, Gulf Power Company, Mississippi Power, Southern Power Company, and SCS and Appendix A thereto dated as of January 1, 2019. See Exhibit 10(b)1 herein.
		(c)	2	—	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)	3	—	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)	4	—	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).)
	Mississippi Power
		(d)	1	—	Intercompany Interchange Contract as revised effective May 1, 2007, among Alabama Power, Georgia Power, Gulf Power Company, Mississippi Power, Southern Power Company, and SCS and Appendix A thereto dated as of January 1, 2019. See Exhibit 10(b)1 herein.
	Southern Power
		(e)	1	—	Intercompany Interchange Contract as revised effective May 1, 2007, among Alabama Power, Georgia Power, Gulf Power Company, Mississippi Power, Southern Power Company, and SCS and Appendix A thereto dated as of January 1, 2019. See Exhibit 10(b)1 herein.
	Southern Company Gas
		(f)	1	—	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.)
(19)	Insider Trading Policies and Procedures
	Southern Company
		(a)		—	Prohibition of Securities Trading Policy. (Designated in Form 10-K for the year ended December 31, 2024, File No. 1-3526, as Exhibit19(a).)
	Alabama Power
		(b)		—	Prohibition of Securities Trading Policy. (Designated in Form 10-K for the year ended December 31, 2024, File No. 1-3526, as Exhibit 19(b).)
	Georgia Power
		(c)		—	Prohibition of Securities Trading Policy. (Designated in Form 10-K for the year ended December 31, 2024, File No. 1-3526, as Exhibit 19(c).)
	Mississippi Power
		(d)		—	Prohibition of Securities Trading Policy. (Designated in Form 10-K for the year ended December 31, 2024, File No. 1-3526, as Exhibit 19(d).)
	Southern Power
		(e)		—	Prohibition of Securities Trading Policy. (Designated in Form 10-K for the year ended December 31, 2024, File No. 1-3526, as Exhibit 19(e).)
	Southern Company Gas
		(f)		—	Prohibition of Securities Trading Policy. (Designated in Form 10-K for the year ended December 31, 2024, File No. 1-3526, as Exhibit 19(f).)
(21)	Subsidiaries of Registrants
	Southern Company
	*	(a)		—	Subsidiaries of Registrant.
	Alabama Power
		Omitted pursuant to General Instruction I(2)(b) of Form 10-K.
	Georgia Power
		Omitted pursuant to General Instruction I(2)(b) of Form 10-K.

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	Mississippi Power
		Omitted pursuant to General Instruction I(2)(b) of Form 10-K.
	Southern Power
		Omitted pursuant to General Instruction I(2)(b) of Form 10-K.
	Southern Company Gas
		Omitted pursuant to General Instruction I(2)(b) of Form 10-K.
(23)	Consents of Experts and Counsel
	Southern Company
	*	(a)	1	—	Consent of Deloittex23a1-q42025xconsentxsouth.htm& Touche LLP.
	Alabama Power
	*	(b)	1	—	Consent of Deloittex23b1-q42025xapcconsent.htm& Touche LLP.
	Georgia Power
	*	(c)	1	—	Consent of Deloitte & Touche LLP.
	Mississippi Power
	*	(d)	1	—	Consent of Deloittex23d1-q42025xmpcconsent.htm& Touche LLP.
	Southern Power
	*	(e)	1	—	Consent of Deloittex23e1-q42025xspcconsent.htm& Touche LLP.
	Southern Company Gas
	*	(f)	1	—	Consent of Deloittex23f1-q44025xgasconsent.htm& Touche LLP.
	*	(f)	2	—	Consent of BDO USA, P.C.
(24)	Powers of Attorney and Resolutions
	Southern Company
	*	(a)	1	—	Power of Attorney and resolution.
	Alabama Power
	*	(b)	1	—	Power of Attorney and resolution.
	Georgia Power
	*	(c)	1	—	Power of Attorney and resolution.
	Mississippi Power
	*	(d)	1	—	Power of Attorney and resolution.
	Southern Power
	*	(e)	1	—	Power of Attorney and resolution.
	Southern Company Gas
	*	(f)	1	—	Power of Attorney and resolution.
(31)	Section 302 Certifications
	Southern Company
	*	(a)	1	—	Certificate of Southern Company's Chief Executive Officer required by Sectionx31a1-q42025so.htm302 of the Sarbanes-Oxley Act of 2002.
	*	(a)	2	—	Certificate of Southern Company's Chief Financial Officer required by Sectionx31a2-q42025so.htm302 of the Sarbanes-Oxley Act of 2002.
	Alabama Power
	*	(b)	1	—	Certificate of Alabama Power's Chief Executive Officer required by Sectionx31b1-q42025apc.htm302 of the Sarbanes-Oxley Act of 2002.
	*	(b)	2	—	Certificate of Alabama Power's Chief Financial Officer required by Sectionx31b2-q42025apc.htm302 of the Sarbanes-Oxley Act of 2002.

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	Georgia Power
	*	(c)	1	—	Certificate of Georgia Power's Chief Executive Officer required by Sectionx31c1-q42025gpc.htm302 of the Sarbanes-Oxley Act of 2002.
	*	(c)	2	—	Certificate of Georgia Power's Chief Financial Officer required by Sectionx31c2-q42025gpc.htm302 of the Sarbanes-Oxley Act of 2002.
	Mississippi Power
	*	(d)	1	—	Certificate of Mississippi Power's Chief Executive Officer required by Sectionx31d1-q42025mpc.htm302 of the Sarbanes-Oxley Act of 2002.
	*	(d)	2	—	Certificate of Mississippi Power's Chief Financial Officer required by Sectionx31d2-q42025mpc.htm302 of the Sarbanes-Oxley Act of 2002.
	Southern Power
	*	(e)	1	—	Certificate of Southern Power Company's Chief Executive Officer required by Sectionx31e1-q42025spc.htm302 of the Sarbanes-Oxley Act of 2002.
	*	(e)	2	—	Certificate of Southern Power Company's Chief Financial Officer required by Sectionx31e2-q42025spc.htm302 of the Sarbanes-Oxley Act of 2002.
	Southern Company Gas
	*	(f)	1	—	Certificate of Southern Company Gas' Chief Executive Officer required by Sectionx31f1-q42025gas.htm302 of the Sarbanes-Oxley Act of 2002.
	*	(f)	2	—	Certificate of Southern Company Gas' Chief Financial Officer required by Sectionx31f2-q42025gas.htm302 of the Sarbanes-Oxley Act of 2002.
(32)	Section 906 Certifications
	Southern Company
	*	(a)		—	Certificate of Southern Company's Chief Executive Officer and Chief Financial Officer required by Sectionx32a-q42025so.htm906 of the Sarbanes-Oxley Act of 2002.
	Alabama Power
	*	(b)		—	Certificate of Alabama Power's Chief Executive Officer and Chief Financial Officer required by Sectionx32b-q42025apc.htm906 of the Sarbanes-Oxley Act of 2002.
	Georgia Power
	*	(c)		—	Certificate of Georgia Power's Chief Executive Officer and Chief Financial Officer required by Sectionx32c-q42025gpc.htm906 of the Sarbanes-Oxley Act of 2002.
	Mississippi Power
	*	(d)		—	Certificate of Mississippi Power's Chief Executive Officer and Chief Financial Officer required by Sectionx32d-q42025mpc.htm906 of the Sarbanes-Oxley Act of 2002.
	Southern Power
	*	(e)		—	Certificate of Southern Power Company's Chief Executive Officer and Chief Financial Officer required by Sectionx32e-q42025spc.htm906 of the Sarbanes-Oxley Act of 2002.
	Southern Company Gas
	*	(f)		—	Certificate of Southern Company Gas' Chief Executive Officer and Chief Financial Officer required by Sectionx32f-q42025gas.htm906 of the Sarbanes-Oxley Act of 2002.
(97)	Policy Relating to Recovery of Erroneously Awarded Compensation
	Southern Company
		(a)		—	The Southern Company and Covered Subsidiaries Compensation Recoupment Policy, effective December 1, 2023. (Designated in Form 10-K for the year ended December 31, 2023, File No. 1-3526, as Exhibit 97(a).)
	Georgia Power
		(c)		—	The Southern Company and Covered Subsidiaries Compensation Recoupment Policy, effective December 1, 2023. See Exhibit 97(a) herein.
	Southern Power
		(e)		—	The Southern Company and Covered Subsidiaries Compensation Recoupment Policy, effective December 1, 2023. See Exhibit 97(a) herein.

E-10

Table of Contents                                Index to Financial Statements

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

E-11

Table of Contents                                Index to Financial Statements

THE SOUTHERN COMPANY

SIGNATURES

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:	Christopher C. Womack
	Chairman, President, and Chief Executive Officer
By:	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)
Date:	February 18, 2026

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 C. Womack
Chairman, President, and Chief Executive Officer<br><br>(Principal Executive Officer)
David P. Poroch
Executive Vice President, Chief Financial Officer, and Treasurer<br><br>(Principal Financial Officer)
Matthew M. Kim
Comptroller and Chief Accounting Officer<br>(Principal Accounting Officer)
Directors:
Janaki Akella<br><br>Shantella E. Cooper<br><br>Anthony F. Earley, Jr.<br><br>James O. Etheredge<br><br>David J. Grain<br><br>Donald M. James<br><br>John D. Johns	Dale E. Klein<br><br>David E. Meador<br><br>William G. Smith, Jr.<br><br>Kristine L. Svinicki<br><br>Lizanne Thomas<br><br>John M. Turner, Jr.		By:	/s/ Melissa K. Caen
---	---
	(Melissa K. Caen, Attorney-in-fact)

Date: February 18, 2026

Table of Contents                                Index to Financial Statements

ALABAMA POWER COMPANY

SIGNATURES

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
	Chairman, President, and Chief Executive Officer
By:	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)
Date:	February 18, 2026

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
Chairman, President, and Chief Executive Officer<br>(Principal Executive Officer)
Moses H. Feagin
Executive Vice President, Chief Financial Officer, and Treasurer<br>(Principal Financial Officer)
Anita D. Allcorn
Senior Vice President and Comptroller<br>(Principal Accounting Officer)
Directors:
Angus R. Cooper, III<br><br>Lee C. Goodloe<br><br>O. B. Grayson Hall, Jr.<br><br>Larry R. Howell, Jr.<br><br>Anthony A. Joseph	Barbara J. Knight<br><br>Kevin B. Savoy<br><br>Charisse D. Stokes<br><br>Phillip M. Webb<br><br>William B. Wilson		By:	/s/ Melissa K. Caen
---	---
	(Melissa K. Caen, Attorney-in-fact)

Date: February 18, 2026

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 2025. Accordingly, Alabama Power will not file an annual report with the Securities and Exchange Commission.

Table of Contents                                Index to Financial Statements

GEORGIA POWER COMPANY

SIGNATURES

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
	Chairman, President, and Chief Executive Officer
By:	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)
Date:	February 18, 2026

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
Chairman, President, and Chief Executive Officer<br>(Principal Executive Officer)
Tyler M. Cook
Senior Vice President, Chief Financial Officer, and Treasurer<br><br>(Principal Financial and Accounting Officer)
Adam D. Houston
Vice President and Comptroller<br>(Principal Accounting Officer)
Directors:
Jill Bullock<br><br>Mark L. Burns<br><br>Andrew W. Evans<br><br>Steven R. Ewing<br><br>Thomas M. Holder	Virgil R. Miller<br><br>Valerie Montgomery Rice<br><br>Tonialo Smith<br><br>Kessel D. Stelling, Jr.		By:	/s/ Melissa K. Caen
---	---
	(Melissa K. Caen, Attorney-in-fact)

Date: February 18, 2026

Table of Contents                                Index to Financial Statements

MISSISSIPPI POWER COMPANY

SIGNATURES

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:	Pedro P. Cherry
	Chairman, President, and Chief Executive Officer
By:	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)
Date:	February 18, 2026

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.

Pedro P. Cherry
Chairman, President, and Chief Executive Officer<br>(Principal Executive Officer)
Matthew P. Grice
Vice President, Treasurer, and Chief Financial Officer<br><br>(Principal Financial Officer)
Pascal B. Gill
Comptroller<br>(Principal Accounting Officer)
Directors:
Augustus Leon Collins<br><br>Thomas M. Duff<br><br>Mary S. Graham<br><br>David B. Hall	Mark E. Keenum<br><br>Kara R. Wilkinson<br><br>Camille Scales Young		By:	/s/ Melissa K. Caen
---	---
	(Melissa K. Caen, Attorney-in-fact)

Date: February 18, 2026

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 2025. Accordingly, Mississippi Power will not file an annual report with the Securities and Exchange Commission.

Table of Contents                                Index to Financial Statements

SOUTHERN POWER COMPANY

SIGNATURES

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:	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)
Date:	February 18, 2026

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<br>(Principal Executive Officer)
Gary Kerr
Senior Vice President, Chief Financial Officer, and Treasurer<br>(Principal Financial Officer)
Jelena Andrin
Vice President and Comptroller<br>(Principal Accounting Officer)
Directors:
Bryan D. Anderson<br><br>Stanley W. Connally, Jr.<br><br>Sloane N. Drake<br><br>James Y. Kerr, II	David P. Poroch<br><br>Sterling A. Spainhour<br><br>Christopher C. Womack		By:	/s/ Melissa K. Caen
---	---
	(Melissa K. Caen, Attorney-in-fact)

Date: February 18, 2026

Table of Contents                                Index to Financial Statements

SOUTHERN COMPANY GAS

SIGNATURES

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
	Chairman, President, and Chief Executive Officer
By:	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)
Date:	February 18, 2026

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
Chairman, President, and Chief Executive Officer<br>(Principal Executive Officer)
Grace A. Kolvereid
Executive Vice President, Chief Financial Officer, and Treasurer<br>(Principal Financial Officer)
Sarah P. Adams
Senior Vice President and Comptroller<br>(Principal Accounting Officer)
Directors:
Sandra N. Bane<br><br>Stephen A. Edwards<br><br>Vanessa C. Harrison<br><br>Bradley J. Henderson	Norman G. Holmes<br><br>J. Bret Lane<br><br>Eric S. Smith<br><br>A. Benjamin Spencer		By:	/s/ Melissa K. Caen
---	---
	(Melissa K. Caen, Attorney-in-fact)

Date: February 18, 2026

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 2025. Accordingly, Southern Company Gas will not file an annual report with the Securities and Exchange Commission.

Document

Exhibit 4(a)4

DESCRIPTION OF THE REGISTRANT’S SECURITIES REGISTERED PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

As of December 31, 2025, The Southern Company (the “Company”) had the following series of securities registered under Section 12 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”):

•Common Stock, Par Value $5.00 Per Share (the “Common Stock”);

•Series 2017B 5.25% Junior Subordinated Notes due December 1, 2077 (the “Series 2017B Junior Subordinated Notes”);

•Series 2020A 4.95% Junior Subordinated Notes due January 30, 2080 (the “Series 2020A Junior Subordinated Notes”);

•Series 2020C 4.20% Junior Subordinated Notes due October 15, 2026 (the “Series 2020C Junior Subordinated Notes”);

•Series 2021B 1.875% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due September 15, 2081 (the “Series 2021B Junior Subordinated Notes”);

•Series 2025A 6.50% Junior Subordinated Notes due March 15, 2085 (the “Series 2025A Junior Subordinated Notes”); and

•2025 Series A Corporate Units (the “Corporate Units”).

The Series 2021B Junior Subordinated Notes are denominated in euro. The Series 2017B Junior Subordinated Notes, the Series 2020A Junior Subordinated Notes, the Series 2020C Junior Subordinated Notes and the Series 2025A Junior Subordinated Notes are denominated in U.S. dollars and are referred to herein together as the “Junior Subordinated Notes.”

Description of the Common Stock

The following description of the Common Stock is a summary and does not purport to be complete. It is subject to and qualified in its entirety by reference to the Company’s Restated Certificate of Incorporation, as amended, which is included as exhibits to the Company’s Annual Report on Form 10-K of which this summary is a part.

The authorized capital stock of the Company currently consists of 1,500,000,000 shares of Common Stock. As of December 31, 2025, there were 1,119,237,015 shares of Common Stock issued and outstanding.

All shares of Common Stock participate equally with respect to dividends and rank equally upon liquidation. Each holder is entitled to one vote for each share held. No stockholder is entitled to preemptive rights.

The outstanding shares of Common Stock are fully paid and nonassessable by the Company and, therefore, are not subject to further calls or assessment by the Company.

The Common Stock is listed on the New York Stock Exchange under the symbol “SO”.

The transfer agent and registrar for the Common Stock is currently Equiniti Trust Company, LLC.

Description of the Junior Subordinated Notes

The following description of the Junior Subordinated Notes is a summary and does not purport to be complete. It is subject to and qualified in its entirety by reference to the Subordinated Note Indenture dated as of October 1, 2015, as supplemented and amended (the “Subordinated Note Indenture”), between the Company and Computershare Trust Company, N.A., as successor trustee (the “Subordinated Note Indenture Trustee”). The Subordinated Note Indenture and all supplements thereto are included as exhibits to the Company’s Annual Report on Form 10-K of which this summary is a part.

The terms “Additional Interest”, “Business Day”,“Event of Default”, “Interest Payment Date”, “Optional Deferral Period”, and “Rating Agency Event”, as used in this Description of the Junior Subordinated Notes, have the meanings ascribed to them in this Description of the Junior Subordinated Notes.

General

Each series of Junior Subordinated Notes was issued as a series of junior subordinated notes under the Subordinated Note Indenture. Each Series of Junior Subordinated Notes was initially issued in the applicable aggregate principal amount shown in the table below. The Company may, at any time and without the consent of the holders of any series of Junior Subordinated Notes, issue additional notes having the same ranking and the same interest rate, maturity and other terms as any series of Junior Subordinated Notes (except for the public offering price and issue date and the initial interest accrual date and initial Interest Payment Date (as defined below), if applicable). Any additional notes having such similar terms, together with the applicable series of Junior Subordinated Notes, will constitute a single series of junior subordinated notes under the Subordinated Note Indenture.

Unless earlier redeemed, the entire principal amount of each series of Junior Subordinated Notes will mature and become due and payable, together with any accrued and unpaid interest thereon, on the applicable date set forth in the table below. The Junior Subordinated Notes are not subject to any sinking fund provision. Each series of Junior Subordinated Notes is available for purchase in denominations of $25.00 and integral multiples of $25.00 in excess thereof.

Series	Original Issuance Amount	Maturity Date
Series 2017B Junior Subordinated Notes	$450,000,000	December 1, 2077
Series 2020A Junior Subordinated Notes	$1,000,000,000	January 30, 2080
Series 2020C Junior Subordinated Notes	$750,000,000	October 15, 2060
Series 2025A Junior Subordinated Notes	$565,000,000	March 15, 2085

Interest

Each Series of Junior Subordinated Notes bears interest at the applicable rate per annum set forth in the table below (the “Securities Rate”). Subject to the Company’s right to defer interest payments as described below, interest is payable quarterly in arrears on the applicable dates set forth in the table below of each year (each an “Interest Payment Date”) to the person in whose name such Junior Subordinated Note is registered at the close of business (i) on the Business Day (as defined

below) immediately preceding such Interest Payment Date if such Junior Subordinated Notes are in book-entry only form or (ii) on the 15th calendar day preceding such Interest Payment Date if such Junior Subordinated Notes are not in book-entry only form (whether or not a Business Day), provided that interest payable at maturity or on a redemption date will be paid to the person to whom principal is payable. The amount of interest payable is computed on the basis of a 360-day year of twelve 30-day months. In the event that any date on which interest is payable on any series of Junior Subordinated Notes is not a Business Day, then payment of the interest payable on such date will be made on the next succeeding day which is a Business Day (and without any interest or other payment in respect of any such delay), with the same force and effect as if made on such date.

Series	Securities Rate		Interest Payment Dates
Series 2017B Junior Subordinated Notes	5.25	%	March 1, June 1, September 1, December 1
Series 2020A Junior Subordinated Notes	4.95	%	January 30, April 30, July 30, October 30
Series 2020C Junior Subordinated Notes	4.20	%	January 15, April 15, July 15, October 15
Series 2025A Junior Subordinated Notes	6.50	%	March 15, June 15, September 15, December 15

“Business Day” means a day other than (i) a Saturday or Sunday, (ii) a day on which banks in New York, New York are authorized or obligated by law or executive order to remain closed or (iii) a day on which the Subordinated Note Indenture Trustee’s corporate trust office is closed for business.

Payment of principal of any Junior Subordinated Notes will be made only against surrender to the paying agent of such Junior Subordinated Notes. Principal of and interest on Junior Subordinated Notes will be payable, subject to any applicable laws and regulations, at the office of such paying agent or paying agents as the Company may designate from time to time, except that, at the option of the Company, payment of any interest may be made by wire transfer or other electronic transfer or by check mailed to the address of the person entitled to an interest payment as such address shall appear in the security register with respect to the applicable series of Junior Subordinated Notes. Payment of interest on Junior Subordinated Notes on any applicable Interest Payment Date will be made to the person in whose name such Junior Subordinated Notes are registered at the close of business on the record date for such interest payment.

The Subordinated Note Indenture Trustee acts as paying agent with respect to each series of the Junior Subordinated Notes. The Company may at any time designate additional paying agents or rescind the designation of any paying agents or approve a change in the office through which any paying agent acts with respect to any series of Junior Subordinated Notes.

All moneys paid by the Company to a paying agent for the payment of the principal of or interest on the Junior Subordinated Notes of any series which remain unclaimed at the end of two years after such principal or interest shall have become due and payable will be repaid to the Company, and the holder of such Junior Subordinated Notes will from that time forward look only to the Company for payment of such principal and interest.

Option to Defer Interest Payments

So long as no Event of Default (as defined below) under the Subordinated Note Indenture has occurred and is continuing, at the Company’s option, it may, on one or more occasions, defer payment of all or part of the current and accrued interest otherwise due on any series of Junior

Subordinated Notes by extending the interest payment period for up to 40 consecutive quarterly periods (each period, commencing on the date that the first such interest payment would otherwise have been made, an “Optional Deferral Period”). A deferral of interest payments with respect to a series of Junior Subordinated Notes may not extend beyond the maturity date of such series or end on a day other than an Interest Payment Date with respect to such series. Any deferred interest on a series of Junior Subordinated Notes will accrue additional interest at the applicable Securities Rate from the applicable Interest Payment Date to the date of payment, compounded quarterly (such deferred interest and additional interest accrued thereon, “Additional Interest”), to the extent permitted under applicable law. No interest will be due and payable on such series of Junior Subordinated Notes until the end of the applicable Optional Deferral Period, except upon a redemption of such series of Junior Subordinated Notes during such Optional Deferral Period.

At the end of an Optional Deferral Period or on any redemption date, the Company will be obligated to pay all accrued and unpaid interest, including any Additional Interest with respect to the applicable series of Junior Subordinated Notes. Once the Company pays all accrued and unpaid interest payments on the applicable series of Junior Subordinated Notes, including any Additional Interest, the Company can again defer interest payments on such series of Junior Subordinated Notes as described above, but not beyond the maturity date of such series.

The Company is required to provide to the Subordinated Note Indenture Trustee written notice of any optional deferral of interest at least 10 and not more than 60 Business Days prior to the earlier of (1) the next applicable Interest Payment Date or (2) the date, if any, upon which it is required to give notice of such Interest Payment Date or the record date therefor to the New York Stock Exchange or any applicable self-regulatory organization. In addition, the Company is required to deliver to the Subordinated Note Indenture Trustee an officers’ certificate stating that no default or Event of Default shall have occurred and be continuing. Subject to receipt of the officers’ certificate, the Subordinated Note Indenture Trustee is required to promptly forward such notice to each holder of record of the applicable series of Junior Subordinated Notes.

Certain Limitations During an Optional Deferral Period

During an Optional Deferral Period, subject to the exceptions noted below, the Company shall not:

•declare or pay any dividend or make any distributions with respect to, or redeem, purchase, acquire or make a liquidation payment with respect to, any of its capital stock, or

•make any payment of interest, principal or premium, if any, on or repay, repurchase or redeem any debt securities (including guarantees) issued by the Company which rank equally with or junior to the Junior Subordinated Notes.

None of the foregoing, however, shall restrict:

•any of the actions described in the preceding sentence resulting from any reclassification of the Company’s capital stock or the exchange or conversion of one class or series of the Company’s capital stock for another class or series of the Company’s capital stock;

•the purchase of fractional interests in shares of the Company’s capital stock pursuant to the conversion or exchange provisions of such capital stock or the security being converted or exchanged;

•dividends, payments or distributions payable in shares of capital stock;

•redemptions, purchases or other acquisitions of shares of capital stock in connection with any employment contract, incentive plan, benefit plan or other similar arrangement of the Company or any of its subsidiaries or in connection with a dividend reinvestment or stock purchase plan; or

•any declaration of a dividend in connection with implementation of any stockholders’ rights plan, or the issuance of rights, stock or other property under any such plan, or the redemption, repurchase or other acquisition of any such rights pursuant thereto.

In addition, with respect to the Series 2025A Junior Subordinated Notes, none of the foregoing shall restrict settling conversion of any convertible notes that rank equally with the Series 2025A Junior Subordinated Notes.

Listing

Each series of Junior Subordinated Notes is listed on the New York Stock Exchange under the applicable symbol set forth in the table below.

Series	Trading Symbol
Series 2017B Junior Subordinated Notes	SOJC
Series 2020A Junior Subordinated Notes	SOJD
Series 2020C Junior Subordinated Notes	SOJE
Series 2025A Junior Subordinated Notes	SOJF

Subordination

The Junior Subordinated Notes are subordinated and junior in right of payment to all Senior Indebtedness (as defined below) of the Company. No payment of principal of (including redemption payments, if any), premium, if any, on or interest on (including Additional Interest) the Junior Subordinated Notes may be made if (a) any Senior Indebtedness is not paid when due and any applicable grace period with respect to such default has ended with such default not being cured or waived or otherwise ceasing to exist, or (b) the maturity of any Senior Indebtedness has been accelerated because of a default, or (c) notice has been given of the exercise of an option to require repayment, mandatory payment or prepayment or otherwise of the Senior Indebtedness. Upon any payment or distribution of assets of the Company to creditors upon any liquidation, dissolution, winding-up, reorganization, assignment for the benefit of creditors, marshalling of assets or liabilities, or any bankruptcy, insolvency or similar proceedings of the Company, the holders of Senior Indebtedness shall be entitled to receive payment in full of all amounts due or to become due on or in respect of all Senior Indebtedness before the holders of the Junior Subordinated Notes are entitled to receive or retain any payment or distribution. Subject to the prior payment of all Senior Indebtedness, the rights of the holders of the Junior Subordinated Notes will be subrogated to the rights of the holders of Senior Indebtedness to receive payments and distributions applicable to such Senior Indebtedness until all amounts owing on the Junior Subordinated Notes are paid in full.

The term “Senior Indebtedness” means, with respect to the Company, (i) any payment due in respect of indebtedness of the Company, whether outstanding at the date of execution of the Subordinated Note Indenture or incurred, created or assumed after such date, (a) in respect of money

borrowed (including any financial derivative, hedging or futures contract or similar instrument) and (b) evidenced by securities, debentures, bonds, notes or other similar instruments issued by the Company that, by their terms, are senior or senior subordinated debt securities including, without limitation, all such obligations under its indentures with various trustees; (ii) all capital lease obligations; (iii) all obligations issued or assumed as the deferred purchase price of property, all conditional sale obligations and all obligations of the Company under any title retention agreement (but excluding trade accounts payable arising in the ordinary course of business and long-term purchase obligations); (iv) all obligations for the reimbursement of any letter of credit, banker’s acceptance, security purchase facility or similar credit transaction; (v) all obligations of the type referred to in clauses (i) through (iv) above of other persons the payment of which the Company is responsible or liable as obligor, guarantor or otherwise; and (vi) all obligations of the type referred to in clauses (i) through (v) above of other persons secured by any lien on any property or asset of the Company (whether or not such obligation is assumed by the Company), except for (1) any such indebtedness that is by its terms subordinated to or that ranks equally with the junior subordinated notes issued under the Subordinated Note Indenture and (2) any unsecured indebtedness between or among the Company or its affiliates. Such Senior Indebtedness shall continue to be Senior Indebtedness and be entitled to the benefits of the subordination provisions contained in the Subordinated Note Indenture irrespective of any amendment, modification or waiver of any term of such Senior Indebtedness.

The Subordinated Note Indenture does not limit the aggregate amount of Senior Indebtedness that may be issued by the Company. Since the Company is a holding company, the right of the Company and, hence, the right of creditors of the Company (including holders of Junior Subordinated Notes) to participate in any distribution of the assets of any subsidiary of the Company, whether upon liquidation, reorganization or otherwise, is subject to prior claims of creditors and preferred stockholders of each subsidiary.

Optional Redemption

At any time and from time to time on or after the applicable date set forth in the table below (the “Initial Optional Redemption Date”), the applicable series of Junior Subordinated Notes will be subject to redemption at the option of the Company in whole or in part upon not less than 30 nor more than 60 days’ notice, at a redemption price equal to 100% of the principal amount of the Junior Subordinated Notes being redeemed plus accrued and unpaid interest (including any Additional Interest) on the Junior Subordinated Notes being redeemed to the redemption date.

Series	Initial Optional Redemption Date
Series 2017B Junior Subordinated Notes	December 1, 2022
Series 2020A Junior Subordinated Notes	January 30, 2025
Series 2020C Junior Subordinated Notes	October 15, 2025
Series 2025A Junior Subordinated Notes	March 15, 2030

In addition, with respect to the Series 2025A Junior Subordinated Notes, any redemption of the Series 2025A Junior Subordinated Notes may be conditioned upon the occurrence of one or more conditions precedent.

If notice of redemption is given as aforesaid, the Junior Subordinated Notes so to be redeemed will, on the redemption date (subject, in the case of a conditional redemption of the Series 2025A Junior Subordinated Notes, to the satisfaction of all conditions precedent), become due and payable at the redemption price together with any accrued and unpaid interest thereon, and from and after such date (unless the Company has defaulted in the payment of the redemption price and accrued interest) such Junior Subordinated Notes shall cease to bear interest. If any Junior Subordinated Note called for redemption shall not be paid upon surrender thereof for redemption, the principal shall, until paid, bear interest from the redemption date at the applicable Securities Rate.

The Company may also redeem the applicable series of Junior Subordinated Notes before the applicable Initial Optional Redemption Date (i) in whole, but not in part, if certain changes in tax laws, regulations or interpretations occur, at the redemption price and under the circumstances described below under “—Right to Redeem Upon a Tax Event” and (ii) in whole, but not in part, if a rating agency makes certain changes in the equity credit criteria for securities such as the applicable series of Junior Subordinated Notes, at the redemption price and under the circumstances described below under “—Right to Redeem Upon a Rating Agency Event.”

Subject to the foregoing and to applicable law (including, without limitation, United States federal securities laws), the Company or its affiliates may, at any time and from time to time, purchase outstanding Junior Subordinated Notes by tender, in the open market or by private agreement.

Right to Redeem Upon a Tax Event

Before the applicable Initial Optional Redemption Date, the Company may redeem, upon not less than 30 nor more than 60 days’ notice, in whole but not in part, any series of Junior Subordinated Notes following the occurrence of a Tax Event (as defined below), at the applicable percentage of the principal amount of such series set forth in the table below plus any accrued and unpaid interest thereon (including any Additional Interest) to the redemption date.

Series	Percentage of Principal Amount
Series 2017B Junior Subordinated Notes	101%
Series 2020A Junior Subordinated Notes	101%
Series 2020C Junior Subordinated Notes	100%
Series 2025A Junior Subordinated Notes	100%

A “Tax Event” happens when the Company has received an opinion of counsel experienced in tax matters that, as a result of:

•any amendment to, clarification of, or change, including any announced prospective change, in the laws or treaties of the United States or any of its political subdivisions or taxing authorities, or any regulations under those laws or treaties;

•an administrative action, which means any judicial decision or any official administrative pronouncement, ruling, regulatory procedure, notice or announcement including any notice or announcement of intent to issue or adopt any administrative pronouncement, ruling, regulatory procedure or regulation;

•any amendment to, clarification of, or change in the official position or the interpretation of any administrative action or judicial decision or any interpretation or pronouncement that provides for a position with respect to an administrative action or judicial decision that differs from the previously generally accepted position, in each case by any legislative body, court, governmental authority or regulatory body, regardless of the time or manner in which that amendment, clarification or change is introduced or made known; or

•a threatened challenge asserted in writing in connection with the Company’s audit or an audit of any of its subsidiaries, or a publicly-known threatened challenge asserted in writing against any other taxpayer that has raised capital through the issuance of securities that are substantially similar to the applicable series of Junior Subordinated Notes,

which amendment, clarification or change is effective or the administrative action is taken or judicial decision, interpretation or pronouncement is issued or threatened challenge is asserted or becomes publicly known after the date of the original issuance of the applicable series of Junior Subordinated Notes, there is more than an insubstantial risk that interest payable by the Company on such series of Junior Subordinated Notes is not deductible, or within 90 days would not be deductible, in whole or in part, by the Company for United States federal income tax purposes.

Right to Redeem Upon a Rating Agency Event

Before the applicable Initial Optional Redemption Date, the Company may redeem, upon not less than 30 nor more than 60 days’ notice, in whole but not in part, any series of Junior Subordinated Notes following the occurrence of a Rating Agency Event (as defined below), at 102% of their principal amount plus any accrued and unpaid interest thereon (including any Additional Interest) to the redemption date.

“Rating Agency Event” means a change to the methodology or criteria that were employed by an applicable nationally recognized statistical rating organization for purposes of assigning equity credit to securities such as the applicable series of Junior Subordinated Notes on the date of original issuance of such series, which change reduces the amount of equity credit assigned to such series as compared with the amount of equity credit that such rating agency had assigned to such series as of the date of original issuance thereof.

Registration and Transfer

The Company shall not be required to (i) issue, register the transfer of or exchange Junior Subordinated Notes of any series during a period of 15 days immediately preceding the date notice is given identifying the Junior Subordinated Notes of such series called for redemption or (ii) issue, register the transfer of or exchange any Junior Subordinated Notes so selected for redemption, in whole or in part, except the unredeemed portion of any Junior Subordinated Note being redeemed in part.

Events of Default

The following are the “Events of Default” with respect to each series of Junior Subordinated Notes:

•failure to pay principal of, or premium, if any, on or interest on the applicable series of Junior Subordinated Notes when due at maturity or earlier redemption;

•failure to pay interest on the applicable series of Junior Subordinated Notes (including Additional Interest) when due and payable (other than at maturity or upon earlier redemption) that continues for 30 days (subject to the Company’s right to optionally defer interest payments); or

•certain events of bankruptcy, insolvency or reorganization involving the Company.

With respect to each series of Junior Subordinated Notes, the term “Default” means the following event: default in the performance or breach of any covenant or warranty of the Company in the Subordinated Note Indenture (other than (i) a covenant or warranty a default in whose performance or whose breach is addressed in the preceding paragraph or (ii) certain other covenants and warranties inapplicable to such series of Junior Subordinated Notes), and continuance of such default or breach for a period of 90 days after specified written notice to the Company by the Subordinated Note Indenture Trustee, or to the Company and the Subordinated Note Indenture Trustee by the holders of at least 25% in principal amount of the outstanding Junior Subordinated Notes of such series.

The holders of not less than a majority in aggregate outstanding principal amount of the Junior Subordinated Notes of any series have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Subordinated Note Indenture Trustee with respect to the Junior Subordinated Notes of such series. If an Event of Default occurs and is continuing with respect to the Junior Subordinated Notes of any series, then the Subordinated Note Indenture Trustee or the holders of not less than 25% in aggregate outstanding principal amount of the Junior Subordinated Notes of such series may declare the principal amount of the Junior Subordinated Notes due and payable immediately by notice in writing to the Company (and to the Subordinated Note Indenture Trustee if given by the holders), and upon any such declaration such principal amount shall become immediately due and payable. At any time after such a declaration of acceleration with respect to the Junior Subordinated Notes of any series has been made and before a judgment or decree for payment of the money due has been obtained as provided in Article Five of the Subordinated Note Indenture, the holders of not less than a majority in aggregate outstanding principal amount of the Junior Subordinated Notes of such series may, by written notice to the Company and the Subordinated Note Indenture Trustee, rescind and annul such declaration and its consequences if the default has been cured or waived and the Company has paid or deposited with the Subordinated Note Indenture Trustee a sum sufficient to pay all matured installments of interest (including any Additional Interest) and principal due otherwise than by acceleration and all sums paid or advanced by the Subordinated Note Indenture Trustee, including reasonable compensation and expenses of the Subordinated Note Indenture Trustee.

Upon the occurrence and continuance of a Default with respect to a series of Junior Subordinated Notes, the Subordinated Note Indenture Trustee and the holders of such series of Junior Subordinated Notes will have the same rights and remedies, and will be subject to the same limitations, restrictions, protections and exculpations, and the Company will be subject to the same obligations and restrictions, in each case, as would apply if such Default was an Event of Default or an event which after notice or lapse of time or both would become an Event of Default; provided that the principal of and accrued interest on such series of Junior Subordinated Notes may not be declared immediately due and payable by reason of the occurrence and continuation of a Default, and any notice of declaration or acceleration based on such Default will be null and void with respect to such series of Junior Subordinated Notes; provided, further that in case a Default has occurred and is

continuing, the Subordinated Note Indenture Trustee will not be subject to the requirement to exercise, with respect to such series of Junior Subordinated Notes, the same degree of care as a prudent individual would exercise in the conduct of his or her own affairs, unless an Event of Default has occurred and is continuing.

The holders of not less than a majority in aggregate outstanding principal amount of the Junior Subordinated Notes of any series may, on behalf of the holders of all the Junior Subordinated Notes of such series, waive any past default with respect to such series, except (i) a default in the payment of principal or interest (including Additional Interest) or (ii) a default in respect of a covenant or provision which under Article Nine of the Subordinated Note Indenture cannot be modified or amended without the consent of the holder of each outstanding Junior Subordinated Note of such series affected.

Modification

The Subordinated Note Indenture contains provisions permitting the Company and the Subordinated Note Indenture Trustee, with the consent of the holders of not less than a majority in principal amount of the outstanding Junior Subordinated Notes of each series affected, to modify the Subordinated Note Indenture or the rights of the holders of the Junior Subordinated Notes of such series; provided that no such modification may, without the consent of the holder of each outstanding Junior Subordinated Note affected, (i) change the stated maturity of the principal of, or any installment of principal of or interest on, any Junior Subordinated Note, or reduce the principal amount of any Junior Subordinated Note or the rate of interest (including Additional Interest) on any Junior Subordinated Note or any premium payable upon the redemption of any Junior Subordinated Note, or change the method of calculating the rate of interest on any Junior Subordinated Note, or impair the right to institute suit for the enforcement of any such payment on or after the stated maturity of any Junior Subordinated Note (or, in the case of redemption, on or after the redemption date), or (ii) reduce the percentage of principal amount of the outstanding Junior Subordinated Notes of any series, the consent of whose holders is required for any such supplemental indenture, or the consent of whose holders is required for any waiver (of compliance with certain provisions of the Subordinated Note Indenture or certain defaults under the Subordinated Note Indenture and their consequences) provided for in the Subordinated Note Indenture, or (iii) modify any of the provisions of the Subordinated Note Indenture relating to supplemental indentures, waiver of past defaults or waiver of certain covenants, except to increase any such percentage or to provide that certain other provisions of the Subordinated Note Indenture cannot be modified or waived without the consent of the holder of each outstanding Junior Subordinated Note affected thereby, or (iv) modify the provisions of the Subordinated Note Indenture with respect to the subordination of the Junior Subordinated Notes in a manner adverse to such holder.

In addition, the Company and the Subordinated Note Indenture Trustee may execute, without the consent of any holders of Junior Subordinated Notes, any supplemental indenture for certain other usual purposes, including the creation of any new series of junior subordinated notes.

Consolidation, Merger and Sale

The Company shall not consolidate with or merge into any other corporation or convey, transfer or lease its properties and assets substantially as an entirety to any person, unless (1) such other corporation or person is a corporation organized and existing under the laws of the United

States, any state of the United States or the District of Columbia and such other corporation or person expressly assumes, by supplemental indenture executed and delivered to the Subordinated Note Indenture Trustee, the payment of the principal of and premium, if any, on and interest (including Additional Interest) on all the Junior Subordinated Notes and the performance of every covenant of the Subordinated Note Indenture on the part of the Company to be performed or observed; (2) immediately after giving effect to such transactions, no Event of Default, and no event which, after notice or lapse of time or both, would become an Event of Default, shall have happened and be continuing; and (3) the Company has delivered to the Subordinated Note Indenture Trustee an officers’ certificate and an opinion of counsel, each stating that such transaction complies with the provisions of the Subordinated Note Indenture governing consolidation, merger, conveyance, transfer or lease and that all conditions precedent to the transaction have been complied with.

Information Concerning the Subordinated Note Indenture Trustee

The Subordinated Note Indenture Trustee, prior to an Event of Default with respect to Junior Subordinated Notes of any series, undertakes to perform, with respect to Junior Subordinated Notes of such series, only such duties as are specifically set forth in the Subordinated Note Indenture and, in case an Event of Default with respect to Junior Subordinated Notes of any series has occurred and is continuing, shall exercise, with respect to Junior Subordinated Notes of such series, the same degree of care as a prudent individual would exercise in the conduct of his or her own affairs. Subject to such provision, the Subordinated Note Indenture Trustee is under no obligation to exercise any of the powers vested in it by the Subordinated Note Indenture at the request of any holder of Junior Subordinated Notes of any series, unless offered reasonable indemnity by such holder against the costs, expenses and liabilities which might be incurred by the Subordinated Note Indenture Trustee. The Subordinated Note Indenture Trustee is not required to expend or risk its own funds or otherwise incur any financial liability in the performance of its duties if the Subordinated Note Indenture Trustee reasonably believes that repayment or adequate indemnity is not reasonably assured to it.

Governing Law

The Subordinated Note Indenture and the Junior Subordinated Notes are governed by, and construed in accordance with, the internal laws of the State of New York.

Miscellaneous

The Company has the right at all times to assign any of its rights or obligations under the Subordinated Note Indenture to a direct or indirect wholly-owned subsidiary of the Company; provided, that, in the event of any such assignment, the Company will remain primarily liable for all such obligations. Subject to the foregoing, the Subordinated Note Indenture will be binding upon and inure to the benefit of the parties to the Subordinated Note Indenture and their respective successors and assigns.

Description of the Series 2021B Junior Subordinated Notes

The following description of the Series 2021B Junior Subordinated Notes is a summary and does not purport to be complete. It is subject to and qualified in its entirety by reference to the Subordinated Note Indenture. The Subordinated Note Indenture and all supplements thereto are included as exhibits to the Company’s Annual Report on Form 10-K of which this summary is a part.

The terms “Additional Interest”, “Business Day”, “Event of Default”, “Interest Payment Date”, “Optional Deferral Period”, and “Rating Agency Event”, as used in this Description of the Series 2021B Junior Subordinated Notes, have the meanings ascribed to them in this Description of the Series 2021B Junior Subordinated Notes.

General

The Series 2021B Junior Subordinated Notes were issued as a series of junior subordinated notes under the Subordinated Note Indenture. The Series 2021B Junior Subordinated Notes were initially issued in the aggregate principal amount of €1,250,000,000. The Company may, at any time and without the consent of the holders of the Series 2021B Junior Subordinated Notes, issue additional notes having the same ranking and the same interest rate, maturity and other terms as the Series 2021B Junior Subordinated Notes (except for the public offering price and issue date and the initial interest accrual date and initial Interest Payment Date (as defined below), if applicable). Any additional notes having such similar terms, together with the Series 2021B Junior Subordinated Notes, will constitute a single series of junior subordinated notes under the Subordinated Note Indenture.

Unless earlier redeemed, the entire principal amount of the Series 2021B Junior Subordinated Notes will mature and become due and payable, together with any accrued and unpaid interest thereon, on September 15, 2081. The Series 2021B Junior Subordinated Notes are not subject to any sinking fund provision. The Series 2021B Junior Subordinated Notes are available for purchase in denominations of €100,000 and integral multiples of €1,000 in excess thereof.

Interest

The Series 2021B Junior Subordinated Notes bear interest:

•from (and including) September 16, 2021 to (but excluding) September 15, 2027 (the “First Reset Date”) at an annual rate of 1.875%;

•from (and including) the First Reset Date to (but excluding) September 15, 2032 (the “First Step-Up Date”) at an annual rate equal to the Five-Year Swap Rate (as defined herein) plus 2.108% (the “Initial Margin”);

•during each Reset Period, from (and including) the First Step-Up Date to (but excluding) September 15, 2047 (the “Second Step-Up Date”), at an annual rate equal to the applicable Five-Year Swap Rate plus the Initial Margin plus 0.25%; and

•during each Reset Period, from (and including) the Second Step-Up Date, at an annual rate equal to the applicable Five-Year Swap Rate plus the Initial Margin plus 1.00%.

Subject to the Company’s right to defer interest payments as described below, interest is payable annually in arrears on September 15 of each year (each, an “Interest Payment Date”) to the

person in whose name such Series 2021B Junior Subordinated Note is registered as of the close of business (i) on the 15th calendar day preceding each Interest Payment Date if the Series 2021B Junior Subordinated Notes are not in book-entry only form (whether or not a Business Day) or (ii) if the Series 2021B Junior Subordinated Notes are represented by one or more global notes, the close of business on the business day (for this purpose a day on which Clearstream Banking, société anonyme and Euroclear Bank S.A./N.V. are open for business) immediately preceding each Interest Payment Date. The initial Interest Payment Date is September 15, 2022.

The amount of interest payable is computed on the basis of the actual number of days in the period for which interest is being calculated and the actual number of days from and including the last Interest Payment Date (or September 16, 2021, if no interest has been paid on the Series 2021B Junior Subordinated Notes) to, but excluding, the next scheduled Interest Payment Date. This payment convention is referred to as ACTUAL/ACTUAL (ICMA) as defined in the rulebook of the International Capital Market Association. In the event that any date on which interest is payable on the Series 2021B Junior Subordinated Notes is not a Business Day, then payment of the interest payable on such date will be made on the next succeeding day which is a Business Day (and without any interest or other payment in respect of any such delay), with the same force and effect as if made on such date. If the maturity date or the redemption date of the Series 2021B Junior Subordinated Notes falls on a day that is not a Business Day, the related payment of principal, premium, if any, and interest will be made on the next succeeding Business Day as if it were made on the date such payment was due, and no interest shall accrue on the amounts so payable for the period from and after such date to the next succeeding Business Day.

Elavon Financial Services DAC, UK Branch (the “Calculation Agent” or the “Paying Agent”, as the case may be) is the initial calculation agent and paying agent for the Series 2021B Junior Subordinated Notes. The applicable interest rate for each Reset Period will be determined by the Calculation Agent as of the applicable Reset Determination Date. The Calculation Agent will promptly notify the Company, the Paying Agent and the Subordinated Note Indenture Trustee of the interest rate for each Reset Date, but in no event later than the applicable Reset Date. The Calculation Agent’s determination of any interest rate and its calculation of the amount of interest for any Reset Period will be conclusive and binding absent manifest error, will be made in the Calculation Agent’s sole discretion and, notwithstanding anything to the contrary in the documentation relating to the Series 2021B Junior Subordinated Notes, will become effective without consent from any person or entity. Such determination of any interest rate and the calculation of the amount of interest will be on file at the Company’s principal offices and will be made available to any holder of the Series 2021B Junior Subordinated Notes upon request. In no event shall the Subordinated Note Indenture Trustee have any liability for any determination made by or on behalf of such Calculation Agent.

The Company may, from time to time, replace the Calculation Agent. If the Calculation Agent is unwilling or unable to continue to act as Calculation Agent or fails to duly determine an interest rate on any Reset Date as provided herein, the Company will appoint another leading financial institution to act as such in its place. The Calculation Agent may not resign its duties or be removed without a successor having been so appointed.

Definitions

“Business Day” means a day other than a Saturday or Sunday, (i) which is not a day on which banks in the City of New York or London are authorized or obligated by law or executive order to

close and (ii) on which the Trans-European Automated Real-time Gross Settlement Express Transfer system (the TARGET2 system), or any successor thereto, operates.

“Five-Year Swap Rate” means, in relation to a Reset Date and the related Reset Determination Date, the euro mid-market swap reference rate for a term of five years as displayed on the Reset Screen Page at 11:00 a.m. (Frankfurt time) on the applicable Reset Determination Date. In the event that such rate does not appear on the Reset Screen Page on the relevant Reset Determination Date at approximately that time, the Five-Year Swap Rate will be the Reset Reference Bank Rate. If the Reset Reference Bank Rate is unavailable or the Calculation Agent determines that no Reference Bank is providing offered quotations, the Five-Year Swap Rate will be equal to the last Five-Year Swap Rate available on the Reset Screen Page as determined by the Calculation Agent, or, in the case of the First Reset Date, the rate of -0.294% per annum.

“Reset Date” means the First Reset Date and each fifth anniversary thereof.

“Reset Determination Date” means the day which is two Business Days preceding the applicable Reset Date.

“Reset Period” means each period from (and including) a Reset Date to (but excluding) the next Reset Date.

“Reset Reference Bank Rate” means the percentage rate determined on the basis of the euro mid-market swap reference rate for a term of five years provided by at least four leading swap dealers in the interbank market selected by the Calculation Agent in consultation with the Company (“Reference Banks”) to the Calculation Agent at approximately 11:00 a.m. (Frankfurt time) on the Reset Determination Date. If at least three quotations are provided, the Reset Reference Bank Rate will be the arithmetic mean of the quotations, eliminating the highest quotation (or, in the event of equality, one of the highest) and the lowest quotation (or, in the event of equality, one of the lowest). If two quotations are provided, the Reset Reference Bank Rate will be the arithmetic mean of the quotations. If one quotation is provided, the Reset Reference Bank Rate will be such quotation.

“Reset Screen Page” means Reuters screen “ICESWAP2 / EURFIXA” (or such other page as may replace such page on Reuters or such other page as may be determined by the Company in consultation with the Calculation Agent for the purposes of displaying comparable rates).

Benchmark Discontinuation

Independent Adviser

If a Benchmark Event occurs in relation to the Original Reference Rate when any interest rate with respect to the Series 2021B Junior Subordinated Notes remains to be determined by reference to the Original Reference Rate, the Company shall use reasonable efforts to appoint an Independent Adviser, as soon as reasonably practicable (provided that such appointment need not be made effective earlier than 30 days prior to the first date on which the Original Reference Rate is to be used to determine any interest rate), to determine a Successor Rate, or, in the absence of a Successor Rate, an Alternative Rate, and, in either case, an Adjustment Spread and any Benchmark Conforming Changes.

In making such determination, the Independent Adviser shall act in good faith and in a commercially reasonable manner as an expert. In the absence of bad faith or fraud, the Independent

Adviser shall have no liability whatsoever to the Company, the Paying Agent or the holders of the Series 2021B Junior Subordinated Notes for any determination made by it and for any advice given to the Company in connection with any determination made by the Company.

Successor Rate or Alternative Rate

If the Independent Adviser determines in good faith that:

•there is a Successor Rate, then such Successor Rate shall (subject to application of the Adjustment Spread provisions described below) subsequently be used in place of the Original Reference Rate to determine the relevant interest rate (or the relevant component part(s) thereof) for all relevant future payments of interest on the Series 2021B Junior Subordinated Notes (subject to the further operation of the provisions described in this section “Benchmark Discontinuation”); or

•there is no Successor Rate but that there is an Alternative Rate, then such Alternative Rate shall (subject to the application of the Adjustment Spread provisions described below) subsequently be used in place of the Original Reference Rate to determine the relevant interest rate (or the relevant component part(s) thereof) for all relevant future payments of interest on the Series 2021B Junior Subordinated Notes (subject to the further operation of the provisions described in this section “Benchmark Discontinuation”).

Adjustment Spread

If the Independent Adviser determines in good faith (i) that an Adjustment Spread is required to be applied to the Successor Rate or the Alternative Rate (as the case may be) and (ii) the quantum of, or a formula or methodology for determining, such Adjustment Spread, then such Adjustment Spread shall be applied to the Successor Rate or the Alternative Rate (as the case may be) for each subsequent determination of a relevant interest rate (or a relevant component part thereof) by reference to such Successor Rate or Alternative Rate (as applicable).

Benchmark Conforming Changes

If any Successor Rate, Alternative Rate or Adjustment Spread is determined in accordance with the provisions described herein and the Independent Adviser determines in good faith (A) that amendments to the terms and conditions of the Series 2021B Junior Subordinated Notes are strictly necessary to ensure the proper operation of such Successor Rate, Alternative Rate and/or Adjustment Spread (such amendments, the “Benchmark Conforming Changes”) and (B) the terms of the Benchmark Conforming Changes, then the Company shall, subject to giving notice thereof as described below under “Notices”, without any requirement for the consent or approval of holders of the Series 2021B Junior Subordinated Notes, vary the terms and conditions of the Series 2021B Junior Subordinated Notes to give effect to such Benchmark Conforming Changes with effect from the date specified in such notice. In connection with any such variation in the terms and conditions of the Series 2021B Junior Subordinated Notes, the Company shall comply with applicable laws and the rules of any stock exchange on which the Series 2021B Junior Subordinated Notes are for the time being listed or admitted to trading.

Notices

The Company will promptly notify the Subordinated Note Indenture Trustee, the Calculation Agent, the Paying Agent and the holders of the Series 2021B Junior Subordinated Notes of any Successor Rate, Alternative Rate, Adjustment Spread and Benchmark Conforming Changes.

In no event shall the Subordinated Note Indenture Trustee, the Calculation Agent or the Paying Agent be responsible for determining any substitute for the Five-Year Swap Rate, for determining whether a Benchmark Event has occurred or for making any adjustments to any alternative benchmark or spread thereon or any other relevant methodology for calculating any such substitute or successor rate.

Any determination, decision or election that may be made by the Company or its designated Independent Adviser pursuant to this subsection “Benchmark Discontinuation,” including any determination with respect to a rate or adjustment or of the occurrence or non-occurrence of an event, circumstance or date and any decision to take or refrain from taking any action or any selection, will be conclusive and binding absent manifest error, will be made in the Company’s or its designated Independent Adviser’s sole discretion and, notwithstanding anything to the contrary in any documentation relating to the Series 2021B Junior Subordinated Notes, shall become effective without consent from the holders of the Series 2021B Junior Subordinated Notes or any other party. None of the Subordinated Note Indenture Trustee, the Calculation Agent, the Paying Agent or the common depositary will have any liability for any determination made by or on behalf of the Company or its designated Independent Adviser in connection with a Benchmark Event.

Fallback

Notwithstanding any of the foregoing discussion under “Benchmark Discontinuation,” no Successor Rate or Alternative Rate will be adopted, nor will the applicable Adjustment Spread or Benchmark Conforming Changes be applied, if and to the extent that, in the determination of the Company, the same could reasonably be expected to result in a Rating Agency Event.

If, following the occurrence of a Benchmark Event and in relation to the determination of the interest rate on the immediately following Reset Determination Date, no Independent Adviser has been appointed, no Successor Rate or Alternative Rate (as applicable) is determined by the Independent Adviser or no Successor Rate or Alternative Rate is adopted in accordance with the provisions of this subsection “Benchmark Discontinuation,” the Five-Year Swap Rate will continue to apply for the purpose of determining such interest rate on such Reset Determination Date and will be equal to the last Five-Year Swap Rate available on the Reset Screen Page as determined by the Calculation Agent, or, in the case of the First Reset Date, the rate of -0.294% per annum.

Definitions

“Adjustment Spread” means either a spread (which may be positive or negative), or the formula or methodology for calculating a spread, in either case, which the Independent Adviser determines and which is required to be applied to the Successor Rate or the Alternative Rate (as the case may be) to reduce or eliminate, to the fullest extent reasonably practicable in the circumstances, any economic prejudice or benefit (as the case may be) to holders of the Series 2021B Junior Subordinated Notes as a result of the replacement of the Original Reference Rate with the Successor Rate or the Alternative Rate (as the case may be) and is the spread, formula or methodology which:

(i) in the case of a Successor Rate, is formally recommended, or formally provided as an option for parties to adopt, in relation to the replacement of the Original Reference Rate with the Successor Rate by any Relevant Nominating Body;

(ii) in the case of an Alternative Rate (or in the case of a Successor Rate where (i) above does not apply), is in customary market usage in the international debt capital markets for transactions which reference the Original Reference Rate, where such rate has been replaced by the Alternative Rate (or, as the case may be, the Successor Rate); or

(iii) if no such recommendation or option has been made (or made available), or the Independent Adviser determines there is no such spread, formula or methodology in customary market usage, the Independent Adviser, acting in good faith, determines to be appropriate.

“Alternative Rate” means, in the absence of Successor Rate, an alternative benchmark or screen rate that the Independent Adviser determines as described herein is customary market usage in the international debt capital markets for the purposes of determining rates of interest (or the relevant component part thereof) for a commensurate interest period (if there is such a customary market usage at such time) and in the same currency as the Series 2021B Junior Subordinated Notes.

“Benchmark Event” means, with respect to the Original Reference Rate:

(i) the Original Reference Rate ceasing to be published for a period of at least five Business Days or ceasing to exist;

(ii) the later of (a) the making of a public statement by the administrator of the Original Reference Rate that it will, on or before a specified date, cease publishing the Original Reference Rate permanently or indefinitely (in circumstances where no successor administrator has been appointed that will continue publication of the Original Reference Rate) and (b) the date falling six months prior to the specified date referred to in (ii)(a);

(iii) the making of a public statement by the supervisor of the administrator of the Original Reference Rate that the Original Reference Rate has been permanently or indefinitely discontinued;

(iv) the later of (a) the making of a public statement by the supervisor of the administrator of the Original Reference Rate that the Original Reference Rate will, on or before a specified date, be permanently or indefinitely discontinued and (b) the date falling six months prior to the specified date referred to in (iv)(a);

(v) the making of a public statement by the supervisor of the administrator of the Original Reference Rate that means the Original Reference Rate will be prohibited from being used or that its use will be subject to restrictions or adverse consequences, in each case within the following six months;

(vi) it has, or will prior to the next Reset Determination Date, become unlawful for the Company, the party responsible for determining the interest rate (being the Calculation Agent) or any Paying Agent to calculate any payment due to be made to any holder of a Series 2021B Junior Subordinated Note using the Original Reference Rate (including, without limitation, under Regulation (EU) 2016/1011 (the “Benchmarks Regulation”), if applicable);

(vii) that a decision to withdraw the authorization or registration pursuant to Article 35 of the Benchmarks Regulation of any benchmark administrator previously authorized to publish such Original Reference Rate has been adopted; or

(viii) the making of a public statement by the supervisor of the administrator of the Original Reference Rate that, in the view of such supervisor, such Original Reference Rate is no longer representative of an underlying market or its methodology has materially changed.

“Independent Adviser” means an independent financial institution of international repute or an independent adviser of recognized standing with appropriate expertise, appointed by the Company at its own expense as described herein.

“Original Reference Rate” means the Five-Year Swap Rate.

“Relevant Nominating Body” means, in respect of a benchmark or screen rate (as applicable):

(i) the central bank for the currency to which the benchmark or screen rate (as applicable) relates, or any central bank or other supervisory authority which is responsible for supervising the administrator of the benchmark or screen rate (as applicable); or

(ii) any working group or committee sponsored by, chaired or co-chaired by or constituted at the request of (a) the central bank for the currency to which the benchmark or screen rate (as applicable) relates, (b) any central bank or other supervisory authority which is responsible for supervising the administrator of the benchmark or screen rate (as applicable), (c) a group of the aforementioned central banks or other supervisory authorities or (d) the Financial Stability Board or any part thereof.

“Successor Rate” means a successor to or replacement of the Original Reference Rate that is formally recommended by any Relevant Nominating Body. If, following a Benchmark Event, more than one successor or replacement rates are recommended by any Relevant Nominating Body, the Independent Adviser will determine, among those successor or replacement rates, the one that is the most appropriate, taking into consideration, without limitation, the particular features of the Series 2021B Junior Subordinated Notes.

Option to Defer Interest Payments

So long as no Event of Default (as defined below) under the Subordinated Note Indenture has occurred and is continuing, at the Company’s option, it may, on one or more occasions, defer payment of all or part of the current and accrued interest otherwise due on the Series 2021B Junior Subordinated Notes by extending the interest payment period for up to 10 consecutive years (each period, commencing on the date that the first such interest payment would otherwise have been made, an “Optional Deferral Period”). A deferral of interest payments with respect to the Series 2021B Junior Subordinated Notes may not extend beyond the maturity date of the Series 2021B Junior Subordinated Notes or end on a day other than an Interest Payment Date. Any deferred interest on the Series 2021B Junior Subordinated Notes will accrue additional interest at the rate then applicable to the Series 2021B Junior Subordinated Notes from the applicable Interest Payment Date to the date of payment, compounded annually (such deferred interest and additional interest accrued thereon, “Additional Interest”), to the extent permitted under applicable law. No interest will be due and payable on the Series 2021B Junior Subordinated Notes until the end of an Optional Deferral Period,

except upon a redemption of the Series 2021B Junior Subordinated Notes during such Optional Deferral Period.

At the end of an Optional Deferral Period or on any redemption date, the Company will be obligated to pay all accrued and unpaid interest, including any Additional Interest. Once the Company pays all accrued and unpaid interest payments on the Series 2021B Junior Subordinated Notes, including any Additional Interest, the Company can again defer interest payments on the Series 2021B Junior Subordinated Notes as described above, but not beyond the maturity date of the Series 2021B Junior Subordinated Notes.

The Company is required to provide to the Subordinated Note Indenture Trustee written notice of any optional deferral of interest at least 10 and not more than 60 Business Days prior to the earlier of (1) the next applicable Interest Payment Date or (2) the date, if any, upon which it is required to give notice of such Interest Payment Date or the record date therefor to the New York Stock Exchange or any applicable self-regulatory organization. In addition, the Company is required to deliver to the Subordinated Note Indenture Trustee an officers’ certificate stating that no default or Event of Default shall have occurred and be continuing. Subject to receipt of the officers’ certificate, the Subordinated Note Indenture Trustee is required to promptly forward such notice to each holder of record of the Series 2021B Junior Subordinated Notes.

Certain Limitations During an Optional Deferral Period

During an Optional Deferral Period, subject to the exceptions noted below, the Company shall not:

•declare or pay any dividend or make any distributions with respect to, or redeem, purchase, acquire or make a liquidation payment with respect to, any of its capital stock, or

•make any payment of interest, principal or premium, if any, on or repay, repurchase or redeem any debt securities (including guarantees) issued by the Company which rank equally with or junior to the Series 2021B Junior Subordinated Notes.

None of the foregoing, however, shall restrict:

•any of the actions described in the preceding sentence resulting from any reclassification of the Company’s capital stock or the exchange or conversion of one class or series of the Company’s capital stock for another class or series of the Company’s capital stock;

•the purchase of fractional interests in shares of the Company’s capital stock pursuant to the conversion or exchange provisions of such capital stock or the security being converted or exchanged;

•dividends, payments or distributions payable in shares of capital stock;

•redemptions, purchases or other acquisitions of shares of capital stock in connection with any employment contract, incentive plan, benefit plan or other similar arrangement of the Company or any of its subsidiaries or in connection with a dividend reinvestment or stock purchase plan; or

•any declaration of a dividend in connection with implementation of any stockholders’ rights plan, or the issuance of rights, stock or other property under any such plan, or the redemption, repurchase or other acquisition of any such rights pursuant thereto.

Listing

The Series 2021B Junior Subordinated Notes are listed on the New York Stock Exchange under the symbol “SO 81”.

Subordination

The Series 2021B Junior Subordinated Notes are subordinated and junior in right of payment to all Senior Indebtedness (as defined under “Description of the Junior Subordinated Notes—Subordination” above) of the Company. No payment of principal of (including redemption payments, if any), premium, if any, on or interest on (including Additional Interest) the Series 2021B Junior Subordinated Notes may be made if (a) any Senior Indebtedness is not paid when due and any applicable grace period with respect to such default has ended with such default not being cured or waived or otherwise ceasing to exist, or (b) the maturity of any Senior Indebtedness has been accelerated because of a default, or (c) notice has been given of the exercise of an option to require repayment, mandatory payment or prepayment or otherwise of the Senior Indebtedness. Upon any payment or distribution of assets of the Company to creditors upon any liquidation, dissolution, winding-up, reorganization, assignment for the benefit of creditors, marshalling of assets or liabilities, or any bankruptcy, insolvency or similar proceedings of the Company, the holders of Senior Indebtedness shall be entitled to receive payment in full of all amounts due or to become due on or in respect of all Senior Indebtedness before the holders of the Series 2021B Junior Subordinated Notes are entitled to receive or retain any payment or distribution. Subject to the prior payment of all Senior Indebtedness, the rights of the holders of the Series 2021B Junior Subordinated Notes will be subrogated to the rights of the holders of Senior Indebtedness to receive payments and distributions applicable to such Senior Indebtedness until all amounts owing on the Series 2021B Junior Subordinated Notes are paid in full.

The Subordinated Note Indenture does not limit the aggregate amount of Senior Indebtedness that may be issued by the Company. Since the Company is a holding company, the right of the Company and, hence, the right of creditors of the Company (including holders of the Series 2021B Junior Subordinated Notes) to participate in any distribution of the assets of any subsidiary of the Company, whether upon liquidation, reorganization or otherwise, is subject to prior claims of creditors and preferred stockholders of each subsidiary.

Optional Redemption

The Company may redeem, upon not less than 15 nor more than 60 days’ notice, in whole but not in part, the Series 2021B Junior Subordinated Notes (i) on any date during the period commencing on (and including) June 15, 2027 (the “First Par Call Date”) to (and including) the First Reset Date (such period, the “First Par Call Period”) and (ii) on any Interest Payment Date falling thereafter (any such date, together with each date in the First Par Call Period, a “Par Call Date”), in each case, at a redemption price equal to 100% of the outstanding principal amount of Series 2021B Junior Subordinated Notes plus accrued and unpaid interest (including any Additional Interest) to but not including the redemption date.

In addition, on any date other than a Par Call Date, the Series 2021B Junior Subordinated Notes will be subject to redemption at the option of the Company, in whole but not in part, at any time upon not less than 15 nor more than 60 days’ notice, at a redemption price equal to the greater of (i) 100% of the principal amount of the Series 2021B Junior Subordinated Notes being redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal of and interest on the Series 2021B Junior Subordinated Notes being redeemed (not including any portion of such payments of interest accrued to the redemption date) from the redemption date to the next Par Call Date discounted (for purposes of determining present value) to but not including the redemption date on an ACTUAL/ACTUAL (ICMA) day count basis at the applicable Comparable Government Bond Rate (as defined below) plus 40 basis points, plus, in each case, accrued and unpaid interest (including any Additional Interest) on the Series 2021B Junior Subordinated Notes being redeemed to but not including the redemption date.

“Comparable Government Bond Rate” means the yield to maturity, expressed as a percentage (rounded to three decimal places, with 0.0005 being rounded upwards), on the third Business Day prior to the date fixed for redemption, of the Comparable Government Bond (as defined below) on the basis of the middle market price of the Comparable Government Bond prevailing at 11:00 a.m. (Frankfurt time) on such Business Day as determined by an independent investment bank selected by the Company.

“Comparable Government Bond” means, in relation to any Comparable Government Bond Rate calculation, at the discretion of an independent investment bank selected by the Company, a bond that is a direct obligation of the Federal Republic of Germany (“German government bond”), whose maturity is closest to the next Par Call Date, or if such independent investment bank in its discretion determines that such similar bond is not in issue, such other German government bond as such independent investment bank may, with the advice of three brokers of, and/or market makers in, German government bonds selected by the Company, determine to be appropriate for determining the Comparable Government Bond Rate.

Any redemption of the Series 2021B Junior Subordinated Notes may be conditioned upon the occurrence of one or more conditions precedent.

If notice of redemption is given as aforesaid, the Series 2021B Junior Subordinated Notes so to be redeemed will, on the redemption date (subject, in the case of a conditional redemption, to the satisfaction of all conditions precedent), become due and payable at the redemption price together with any accrued and unpaid interest thereon (including any Additional Interest), and from and after such date (unless the Company has defaulted in the payment of the redemption price and accrued interest) such Series 2021B Junior Subordinated Notes shall cease to bear interest. If any Series 2021B Junior Subordinated Note called for redemption shall not be paid upon surrender thereof for redemption, the principal shall, until paid, bear interest from the redemption date at the rate then applicable to the Series 2021B Junior Subordinated Notes.

The Company may also redeem the Series 2021B Junior Subordinated Notes (i) in whole, but not in part, if certain changes in tax laws, regulations or interpretations occur, at the redemption price and under the circumstances described below under “—Right to Redeem Upon Tax Deductibility Event” and “—Right to Redeem Upon Tax Withholding Event,” (ii) in whole, but not in part, if a rating agency makes certain changes in the equity credit criteria for securities such as the Series 2021B Junior Subordinated Notes, at the redemption price and under the circumstances described below under “—Right to Redeem Upon Rating Agency Event” and (iii) in whole, but not in part, if the Company has made certain repurchases of the Series 2021B Junior Subordinated Notes, at the redemption price and under the circumstances described below under “—Right to Redeem Upon Substantial Repurchase Event.”

Subject to the foregoing and to applicable law (including, without limitation, United States federal securities laws), the Company or its affiliates may, at any time and from time to time, purchase outstanding Series 2021B Junior Subordinated Notes by tender, in the open market or by private agreement.

Right to Redeem Upon Tax Deductibility Event

The Company may redeem, upon not less than 15 nor more than 60 days’ notice, in whole but not in part, the Series 2021B Junior Subordinated Notes following the occurrence of a Tax Deductibility Event (as defined below), at any time:

•where such redemption occurs prior to the First Par Call Date, at a redemption price equal to 101% of the principal amount plus accrued and unpaid interest (including any Additional Interest) to but not including the redemption date; and

•where such redemption occurs on or after the First Par Call Date, at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest (including any Additional Interest) to but not including the redemption date.

A “Tax Deductibility Event” happens when the Company has received an opinion of counsel experienced in tax matters that, as a result of:

•any amendment to, clarification of, or change, including any announced prospective change, in the laws or treaties of the United States or any of its political subdivisions or taxing authorities, or any regulations under those laws or treaties;

•an administrative action, which means any judicial decision or any official administrative pronouncement, ruling, regulatory procedure, notice or announcement including any notice or announcement of intent to issue or adopt any administrative pronouncement, ruling, regulatory procedure or regulation;

•any amendment to, clarification of, or change in the official position or the interpretation of any administrative action or judicial decision or any interpretation or pronouncement that provides for a position with respect to an administrative action or judicial decision that differs from the previously generally accepted position, in each case by any legislative body, court, governmental authority or regulatory body, regardless of the time or manner in which that amendment, clarification or change is introduced or made known; or

•a threatened challenge asserted in writing in connection with the Company’s audit or an audit of any of its subsidiaries, or a publicly-known threatened challenge asserted in writing against any other taxpayer that has raised capital through the issuance of securities that are substantially similar to the Series 2021B Junior Subordinated Notes,

which amendment, clarification or change is effective or the administrative action is taken or judicial decision, interpretation or pronouncement is issued or threatened challenge is asserted or becomes publicly known after September 16, 2021, there is more than an insubstantial risk that interest payable by the Company on the Series 2021B Junior Subordinated Notes is not deductible, or within 90 days would not be deductible, in whole or in part, by the Company for United States federal income tax purposes.

Right to Redeem Upon Rating Agency Event

The Company may redeem, upon not less than 15 nor more than 60 days’ notice, in whole but not in part, the Series 2021B Junior Subordinated Notes following the occurrence of a Rating Agency Event (as defined below), at any time:

•where such redemption occurs prior to the First Par Call Date, at a redemption price equal to 101% of the principal amount plus accrued and unpaid interest (including any Additional Interest) to but not including the redemption date; and

•where such redemption occurs on or after the First Par Call Date, at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest (including any Additional Interest) to but not including the redemption date.

“Rating Agency Event” means a change to the methodology or criteria that were employed by an applicable nationally recognized statistical rating organization (each, a “Rating Agency”) for purposes of assigning equity credit to securities such as the Series 2021B Junior Subordinated Notes on September 16, 2021, and as a result of which change, either: (i) the Series 2021B Junior Subordinated Notes would no longer be eligible for the same or a higher category of “equity credit” or such similar nomenclature as may be used by that Rating Agency from time to time to describe the degree to which the terms of an instrument are supportive of the Company’s senior obligations (the “equity credit”), attributed to the Series 2021B Junior Subordinated Notes at the date of issue of the Series 2021B Junior Subordinated Notes, or if “equity credit” was not assigned on the date of issue of the Series 2021B Junior Subordinated Notes by such Rating Agency, at the date when the equity credit is assigned for the first time by such Rating Agency (a “Loss in Equity Credit”) (this also applies if the Series 2021B Junior Subordinated Notes have been partially or fully re-financed since the date of issue of the Series 2021B Junior Subordinated Notes (or the date when the equity credit is assigned for the first time by such Rating Agency, as the case may be) and a Loss in Equity Credit would have also occurred as a result of such change had the Series 2021B Junior Subordinated Notes not been re-financed), or (ii) the period of time the Series 2021B Junior Subordinated Notes are eligible for the same or a higher category of equity credit attributed to the Series 2021B Junior Subordinated Notes at the date of issue of the Series 2021B Junior Subordinated Notes (or the date when the equity credit is assigned for the first time by such Rating Agency, as the case may be) is being shortened.

Right to Redeem Upon Tax Withholding Event

If, as a result of any change in, or amendment to, the laws (or any regulations or rulings promulgated under the laws) of the United States (or any taxing authority in the United States), or any change in, or amendments to, an official position regarding the application or interpretation of such laws, regulations or rulings, the Company becomes or, based upon a written opinion of independent counsel selected by the Company, will become obligated to pay additional amounts as described herein under the heading “—Payment of Additional Amounts” with respect to the Series 2021B Junior Subordinated Notes (a “Tax Withholding Event”), then the Company may at any time at its option redeem, in whole, but not in part, the Series 2021B Junior Subordinated Notes on not less than 15 nor more than 60 days’ prior notice, at a redemption price equal to 100% of the outstanding principal amount of the Series 2021B Junior Subordinated Notes, together with accrued and unpaid interest thereon (including any Additional Interest) to but not including the redemption date.

Right to Redeem Upon Substantial Repurchase Event

If the Company has repurchased Series 2021B Junior Subordinated Notes equal to or in excess of 75% of the initial aggregate principal amount of the Series 2021B Junior Subordinated Notes (a “Substantial Repurchase Event”), then the Company may at any time at its option redeem, in whole, but not in part, the remaining Series 2021B Junior Subordinated Notes on not less than 15 nor more than 60 days’ prior notice, at a redemption price equal to 100% of the outstanding principal amount of the Series 2021B Junior Subordinated Notes, together with accrued and unpaid interest thereon (including any Additional Interest) to but not including the redemption date.

Payment of Additional Amounts

The Company will, subject to the exceptions and limitations set forth below, pay as additional interest on the Series 2021B Junior Subordinated Notes such additional amounts as are necessary in order that the net payment by the Company of the principal of and interest on the Series 2021B Junior Subordinated Notes to a holder who is not a United States person (as defined herein), after withholding or deduction for any present or future tax, assessment or other governmental charge imposed by the United States or a taxing authority in the United States (including any withholding or deduction with respect to the payment of such additional amounts), will not be less than the amount provided in the Series 2021B Junior Subordinated Notes to be then due and payable; provided, however, that the foregoing obligation to pay additional amounts shall not apply:

(1) to any tax, assessment or other governmental charge that is imposed by reason of the holder (or the beneficial owner for whose benefit such holder holds such Series 2021B Junior Subordinated Note), or a fiduciary, settlor, beneficiary, member or shareholder of the holder or beneficial owner if the holder or beneficial owner is an estate, trust, partnership, corporation or other entity, or a person holding a power over an estate or trust administered by a fiduciary holder, being considered as:

(a) being or having been engaged in a trade or business in the United States or having or having had a permanent establishment in the United States;

(b) having a current or former connection with the United States (other than a connection arising solely as a result of the ownership of the Series 2021B Junior Subordinated Notes, the receipt of any payment thereon or the enforcement of any rights thereunder), including being or having been a citizen or resident of the United States;

(c) being or having been a personal holding company, a passive foreign investment company or a controlled foreign corporation for United States federal income tax purposes or a corporation that has accumulated earnings to avoid United States federal income tax;

(d) being or having been a “10-percent shareholder” of the Company as defined in Section 871(h)(3) of the United States Internal Revenue Code of 1986, as amended (the “Code”), or any successor provision; or

(e) being a bank receiving payments on an extension of credit made pursuant to a loan agreement entered into in the ordinary course of its trade or business;

(2) to any holder that is not the sole beneficial owner of the Series 2021B Junior Subordinated Notes, or a portion of the Series 2021B Junior Subordinated Notes, or that is a fiduciary, partnership or limited liability company, but only to the extent that a beneficial owner with respect to the holder, a beneficiary or settlor with respect to the fiduciary, or a beneficial owner or member of the partnership or limited liability company would not have been entitled to the payment of such additional amounts had the beneficiary, settlor, beneficial owner or member received directly its beneficial or distributive share of the payment;

(3) to any tax, assessment or other governmental charge that would not have been imposed but for the failure of the holder or any other person to comply with certification, identification or information reporting requirements concerning the nationality, residence, identity or connection with the United States of such holder or other person, if compliance is required by statute, by regulation of the United States or any taxing authority therein or by an applicable income tax treaty to which the United States is a party as a precondition to exemption from, or reduction in, such tax, assessment or other governmental charge;

(4) to any tax, assessment or other governmental charge that is imposed otherwise than by withholding by the Company or a paying agent from payments on the Series 2021B Junior Subordinated Notes;

(5) to any tax, assessment or other governmental charge that would not have been imposed but for a change in law, regulation, or administrative or judicial interpretation that becomes effective more than 15 days after the payment becomes due or is duly provided for, whichever occurs later;

(6) to any estate, inheritance, gift, sales, excise, transfer, wealth, capital gains or personal property tax or similar tax, assessment or other governmental charge;

(7) to any tax, assessment or other governmental charge required to be withheld by any paying agent from any payment of principal of or interest on any Series 2021B Junior

Subordinated Note, if such payment can be made without such withholding by at least one other paying agent;

(8) to any tax, assessment or other governmental charge that would not have been imposed but for the presentation by the holder of any Series 2021B Junior Subordinated Note, where presentation is required, for payment on a date more than 30 days after the date on which payment became due and payable or the date on which payment thereof is duly provided for, whichever occurs later;

(9) to any tax, assessment or other governmental charge that is imposed or withheld solely by reason of the beneficial owner being a bank (i) purchasing the Series 2021B Junior Subordinated Notes in the ordinary course of its lending business or (ii) that is neither (A) buying the Series 2021B Junior Subordinated Notes for investment purposes only nor (B) buying the Series 2021B Junior Subordinated Notes for resale to a third-party that either is not a bank or holding the Series 2021B Junior Subordinated Notes for investment purposes only;

(10) to any tax, assessment or other governmental charge imposed under Sections 1471 through 1474 of the Code (or any amended or successor provisions), any current or future regulations or official interpretations thereof, any agreement entered into pursuant to Section 1471(b) of the Code or any fiscal or regulatory legislation, rules or practices adopted pursuant to any intergovernmental agreement entered into in connection with the implementation of such sections of the Code; or

(11) in the case of any combination of items (1), (2), (3), (4), (5), (6), (7), (8), (9) and (10).

The Series 2021B Junior Subordinated Notes are subject in all cases to any tax, fiscal or other law or regulation or administrative or judicial interpretation applicable to the Series 2021B Junior Subordinated Notes. Except as specifically provided under this heading, the Company will not be required to make any payment for any tax, assessment or other governmental charge imposed by any government or a political subdivision or taxing authority of or in any government or political subdivision.

As used under this heading and under the heading “Right to Redeem Upon Tax Withholding Event,” the term “United States” means the United States of America (including the states of the United States and the District of Columbia and any political subdivision thereof) and the term “United States person” means (i) an individual citizen or resident of the United States, (ii) a corporation (or other entity taxable as a corporation) created or organized in or under the laws of the United States, any state thereof or the District of Columbia, (iii) an estate the income of which is subject to United States federal income taxation regardless of its source; or (iv) a trust (a) with respect to which a court within the United States is able to exercise primary supervision over its administration and one or more United States persons have the authority to control all of its substantial decisions or (b) that was in existence on August 20, 1996 and has a valid election in effect under applicable Treasury regulations to be treated as a domestic trust.

Any reference to amounts payable in respect of the Series 2021B Junior Subordinated Notes herein or in the Subordinated Note Indenture shall be deemed to include any additional amounts which may be payable as described above.

Issuance in Euro

All payments of interest and principal, including payments made upon any redemption of the Series 2021B Junior Subordinated Notes, will be payable in euro. If the Company is unable to obtain euro in amounts sufficient to make a required payment under the Series 2021B Junior Subordinated Notes due to the imposition of exchange controls or other circumstances beyond the Company’s control (including the dissolution of the European Monetary Union) or if the euro is no longer being used by the then member states of the European Monetary Union that have adopted the euro as their currency or for the settlement of transactions by public institutions of or within the international banking community, then all payments in respect of the Series 2021B Junior Subordinated Notes will be made in U.S. dollars until the euro is again available to the Company or so used. In such circumstances, the amount payable on any date in euro will be converted into U.S. dollars at the rate mandated by the U.S. Federal Reserve Board as of the close of business on the second Business Day prior to the relevant payment date or, in the event the U.S. Federal Reserve Board has not mandated a rate of conversion, on the basis of the then most recent U.S. dollar/euro exchange rate available on or prior to the second Business Day prior to the relevant payment date as determined by the Company in its sole discretion. Any payment in respect of the Series 2021B Junior Subordinated Notes so made in U.S. dollars will not constitute an Event of Default under the Series 2021B Junior Subordinated Notes or the Subordinated Note Indenture. The Subordinated Note Indenture Trustee, the Calculation Agent and the Paying Agent shall have no responsibility for any calculation or conversion in connection with the foregoing.

Registration and Transfer

The Company shall not be required to (i) issue, register the transfer of or exchange the Junior Series 2021B Subordinated Notes during a period of 15 days immediately preceding the date notice is given identifying the Series 2021B Junior Subordinated Notes called for redemption or (ii) issue, register the transfer of or exchange any Series 2021B Junior Subordinated Notes so selected for redemption, in whole or in part, except the unredeemed portion of any Series 2021B Junior Subordinated Note being redeemed in part.

Events of Default

The following are the “Events of Default” with respect to the Series 2021B Junior Subordinated Notes:

•failure to pay principal of, or premium, if any, on or interest on the Series 2021B Junior Subordinated Notes when due at maturity or earlier redemption;

•failure to pay interest on the Series 2021B Junior Subordinated Notes (including Additional Interest) when due and payable (other than at maturity or upon earlier redemption) that continues for 30 days (subject to the Company’s right to optionally defer interest payments); or

•certain events of bankruptcy, insolvency or reorganization involving the Company.

With respect to the Series 2021B Junior Subordinated Notes, the term “Default” means the following event: default in the performance or breach of any covenant or warranty of the Company in the Subordinated Note Indenture (other than (i) a covenant or warranty a default in whose performance or whose breach is addressed in the preceding paragraph or (ii) certain other covenants and warranties inapplicable to the Series 2021B Junior Subordinated Notes), and continuance of such

default or breach for a period of 90 days after specified written notice to the Company by the Subordinated Note Indenture Trustee, or to the Company and the Subordinated Note Indenture Trustee by the holders of at least 25% in principal amount of the outstanding Series 2021B Junior Subordinated Notes.

The holders of not less than a majority in aggregate outstanding principal amount of the Series 2021B Junior Subordinated Notes have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Subordinated Note Indenture Trustee with respect to the Series 2021B Junior Subordinated Notes. If an Event of Default occurs and is continuing with respect to the Series 2021B Junior Subordinated Notes, then the Subordinated Note Indenture Trustee or the holders of not less than 25% in aggregate outstanding principal amount of the Series 2021B Junior Subordinated Notes may declare the principal amount of the Series 2021B Junior Subordinated Notes due and payable immediately by notice in writing to the Company (and to the Subordinated Note Indenture Trustee if given by the holders), and upon any such declaration such principal amount shall become immediately due and payable. At any time after such a declaration of acceleration with respect to the Series 2021B Junior Subordinated Notes has been made and before a judgment or decree for payment of the money due has been obtained as provided in Article Five of the Subordinated Note Indenture, the holders of not less than a majority in aggregate outstanding principal amount of the Series 2021B Junior Subordinated Notes may, by written notice to the Company and the Subordinated Note Indenture Trustee, rescind and annul such declaration and its consequences if the default has been cured or waived and the Company has paid or deposited with the Subordinated Note Indenture Trustee a sum sufficient to pay all matured installments of interest (including any Additional Interest) and principal due otherwise than by acceleration and all sums paid or advanced by the Subordinated Note Indenture Trustee, including reasonable compensation and expenses of the Subordinated Note Indenture Trustee.

Upon the occurrence and continuance of a Default with respect to the Series 2021B Junior Subordinated Notes, the Subordinated Note Indenture Trustee and the holders of the Series 2021B Junior Subordinated Notes will have the same rights and remedies, and will be subject to the same limitations, restrictions, protections and exculpations, and the Company will be subject to the same obligations and restrictions, in each case, as would apply if such Default was an Event of Default or an event which after notice or lapse of time or both would become an Event of Default; provided that the principal of and accrued interest on the Series 2021B Junior Subordinated Notes may not be declared immediately due and payable by reason of the occurrence and continuation of a Default, and any notice of declaration or acceleration based on such Default will be null and void with respect to the Series 2021B Junior Subordinated Notes; provided further that in case a Default has occurred and is continuing, the Subordinated Note Indenture Trustee will not be subject to the requirement to exercise, with respect to the Series 2021B Junior Subordinated Notes, the same degree of care as a prudent individual would exercise in the conduct of his or her own affairs, unless an Event of Default has occurred and is continuing.

The holders of not less than a majority in aggregate outstanding principal amount of the Series 2021B Junior Subordinated Notes may, on behalf of the holders of all the Series 2021B Junior Subordinated Notes, waive any past default with respect to the Series 2021B Junior Subordinated Notes, except (i) a default in the payment of principal or interest (including Additional Interest) or (ii) a default in respect of a covenant or provision which under Article Nine of the Subordinated Note

Indenture cannot be modified or amended without the consent of the holder of each outstanding Series 2021B Junior Subordinated Note affected.

Modification

The Subordinated Note Indenture contains provisions permitting the Company and the Subordinated Note Indenture Trustee, with the consent of the holders of not less than a majority in principal amount of the outstanding Series 2021B Junior Subordinated Notes, to modify the Subordinated Note Indenture or the rights of the holders of the Series 2021B Junior Subordinated Notes; provided that no such modification may, without the consent of the holder of each outstanding Series 2021B Junior Subordinated Note affected, (i) change the stated maturity of the principal of, or any installment of principal of or interest on, any Series 2021B Junior Subordinated Note, or reduce the principal amount of any Series 2021B Junior Subordinated Note or the rate of interest (including Additional Interest) on any Series 2021B Junior Subordinated Note or any premium payable upon the redemption of any Series 2021B Junior Subordinated Note, or change the method of calculating the rate of interest on any Series 2021B Junior Subordinated Note, or impair the right to institute suit for the enforcement of any such payment on or after the stated maturity of any Series 2021B Junior Subordinated Note (or, in the case of redemption, on or after the redemption date), or (ii) reduce the percentage of principal amount of the outstanding Series 2021B Junior Subordinated Notes, the consent of whose holders is required for any such supplemental indenture, or the consent of whose holders is required for any waiver (of compliance with certain provisions of the Subordinated Note Indenture or certain defaults under the Subordinated Note Indenture and their consequences) provided for in the Subordinated Note Indenture, or (iii) modify any of the provisions of the Subordinated Note Indenture relating to supplemental indentures, waiver of past defaults or waiver of certain covenants, except to increase any such percentage or to provide that certain other provisions of the Subordinated Note Indenture cannot be modified or waived without the consent of the holder of each outstanding Series 2021B Junior Subordinated Note affected thereby, or (iv) modify the provisions of the Subordinated Note Indenture with respect to the subordination of the Series 2021B Junior Subordinated Notes in a manner adverse to such holder.

In addition, the Company and the Subordinated Note Indenture Trustee may execute, without the consent of any holders of Junior Subordinated Notes, any supplemental indenture for certain other usual purposes, including the creation of any new series of junior subordinated notes.

Consolidation, Merger and Sale

The Company shall not consolidate with or merge into any other corporation or convey, transfer or lease its properties and assets substantially as an entirety to any person, unless (1) such other corporation or person is a corporation organized and existing under the laws of the United States, any state of the United States or the District of Columbia and such other corporation or person expressly assumes, by supplemental indenture executed and delivered to the Subordinated Note Indenture Trustee, the payment of the principal of and premium, if any, on and interest (including Additional Interest) on all the Series 2021B Junior Subordinated Notes and the performance of every covenant of the Subordinated Note Indenture on the part of the Company to be performed or observed; (2) immediately after giving effect to such transactions, no Event of Default, and no event which, after notice or lapse of time or both, would become an Event of Default, shall have happened and be continuing; and (3) the Company has delivered to the Subordinated Note Indenture Trustee an officers’ certificate and an opinion of counsel, each stating that such transaction complies with the

provisions of the Subordinated Note Indenture governing consolidation, merger, conveyance, transfer or lease and that all conditions precedent to the transaction have been complied with.

Information Concerning the Subordinated Note Indenture Trustee

The Subordinated Note Indenture Trustee, prior to an Event of Default with respect to the Series 2021B Junior Subordinated Notes, undertakes to perform, with respect to the Series 2021B Junior Subordinated Notes, only such duties as are specifically set forth in the Subordinated Note Indenture and, in case an Event of Default with respect to the Series 2021B Junior Subordinated Notes has occurred and is continuing, shall exercise, with respect to the Series 2021B Junior Subordinated Notes, the same degree of care as a prudent individual would exercise in the conduct of his or her own affairs. Subject to such provision, the Subordinated Note Indenture Trustee is under no obligation to exercise any of the powers vested in it by the Subordinated Note Indenture at the request of any holder of the Series 2021B Junior Subordinated Notes, unless offered reasonable indemnity by such holder against the costs, expenses and liabilities which might be incurred by the Subordinated Note Indenture Trustee. The Subordinated Note Indenture Trustee is not required to expend or risk its own funds or otherwise incur any financial liability in the performance of its duties if the Subordinated Note Indenture Trustee reasonably believes that repayment or adequate indemnity is not reasonably assured to it.

Governing Law

The Subordinated Note Indenture and the Series 2021B Junior Subordinated Notes are governed by, and construed in accordance with, the internal laws of the State of New York.

Miscellaneous

The Company has the right at all times to assign any of its rights or obligations under the Subordinated Note Indenture to a direct or indirect wholly-owned subsidiary of the Company; provided, that, in the event of any such assignment, the Company will remain primarily liable for all such obligations. Subject to the foregoing, the Subordinated Note Indenture will be binding upon and inure to the benefit of the parties to the Subordinated Note Indenture and their respective successors and assigns.

Description of the Corporate Units

The Corporate Units constitute one form of the Company’s 2025 Series A Equity Units (the “Equity Units”). Each Corporate Unit consists of:

•a purchase contract (each, a “purchase contract”) issued by the Company pursuant to the Purchase Contract and Pledge Agreement dated as of November 6, 2025 (the “purchase contract and pledge agreement”);

•a 1/40 undivided beneficial ownership interest in $1,000 principal amount of the Company’s Series 2025B Remarketable Senior Notes due 2030 (the “Series 2025B RSNs”); and

•a 1/40 undivided beneficial ownership interest in $1,000 principal amount of the Company’s Series 2025C Remarketable Senior Notes due 2033 (the “Series 2025C RSNs” and, together with the Series 2025B RSNs, the “RSNs”).

The summaries of the terms of the Equity Units, the purchase contracts, the purchase contract and pledge agreement and the RSNs are set forth under the captions “Description of the Purchase Contracts,” “Certain Provisions of the Purchase Contract and Pledge Agreement” and “Description of the Remarketable Senior Notes” below. Together with the summary under the caption “Description of the Common Stock” above, these summaries describe the material terms of the Corporate Units; however, these descriptions are only summaries and do not purport to be complete. These summaries are subject to and are qualified in their entirety by reference to all the provisions of the purchase contract and pledge agreement, the Senior Note Indenture dated as of January 1, 2007, between the Company and Computershare Trust Company, N.A., as successor Trustee (the “Senior Note Indenture”), the RSNs and the form of remarketing agreement, which has been attached as an exhibit to the purchase contract and pledge agreement, including the definitions of certain terms used therein, each of which is included as an exhibit to the Company’s Annual Report on Form 10-K of which these summaries are a part.

In the summaries below, the terms “you” and “your” refer to holders of the Equity Units or applicable component thereof.

Description of the Equity Units

The term “business day”, as used in this Description of the Equity Units, has the meaning ascribed to it in this Description of the Equity Units.

General

The Company issued the Equity Units under the purchase contract and pledge agreement among the Company and U.S. Bank Trust Company, National Association, as purchase contract agent (the “purchase contract agent”), collateral agent (the “collateral agent”), custodial agent (the “custodial agent”) and securities intermediary (the “securities intermediary”). The Equity Units may be either Corporate Units or 2025 Series A Treasury Units (“Treasury Units”). The Equity Units were initially issued as 40,000,000 Corporate Units, each with a stated amount of $50.

Each Corporate Unit consists of:

•    a purchase contract under which

o    the holder has agreed to purchase from the Company, and the Company has agreed to sell to the holder, on December 15, 2028 (or if such day is not a business day, the following business day), which is referred to as the “purchase contract settlement date,” or earlier upon early settlement, for $50, a number of shares of Common Stock equal to the applicable settlement rate described under “Description of the Purchase Contracts—Purchase of Common Stock,” “Description of the Purchase Contracts—Early Settlement” or “Description of the Purchase Contracts—Early Settlement Upon a Fundamental Change,” as the case may be, plus, in the case of an early settlement upon a fundamental change, the number of make-whole shares; and

o    the Company will pay the holder quarterly contract adjustment payments at the rate of 2.975% per year on the stated amount of $50, or $1.4875 per year, subject to the Company’s right to defer such contract adjustment payments as described under “Description of the Purchase Contracts—Contract Adjustment Payments,” and

either:

•    (i) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of the Series 2025B RSNs (under which the Company will pay to the holder 1/40 of the interest payment on such note at the initial rate of 4.15%, or $41.50 per year per $1,000 principal amount), and (ii) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of the Series 2025C RSNs (under which the Company will pay the holder 1/40 of the interest payment on such note at the initial rate of 4.15%, or $41.50 per year per $1,000 principal amount); or

•    following a successful optional remarketing, the applicable ownership interest in a portfolio of United States Treasury securities, which is referred to as the “Treasury portfolio.”

The “applicable ownership interest” means, with respect to the Treasury portfolio,

(1) a 1/20 undivided beneficial ownership interest in $1,000 principal amount at maturity of United States Treasury securities (or principal or interest strips thereof) included in the Treasury portfolio that mature on or prior to the purchase contract settlement date;

(2) if the optional remarketing settlement date (as defined below) occurs prior to September 15, 2028, with respect to the originally-scheduled interest payment dates on each series of the RSNs that would have occurred on September 15, 2028 and the purchase contract settlement date, an undivided beneficial interest in U.S. Treasury securities (or principal or interest strips thereof) that mature on or prior to (i) September 14, 2028 (in connection with the interest payment date that would have occurred on September 15, 2028) and (ii) December 14, 2028 (in connection with the interest payment date that would have occurred on the purchase contract settlement date), each in an aggregate amount at maturity equal to the aggregate interest payments (assuming no reset of the interest rate) that would have been paid on September 15, 2028 and the purchase contract settlement date, respectively, with respect to a 1/40 undivided beneficial ownership interest in $1,000 principal amount of each series of the RSNs; and

(3) if the optional remarketing settlement date occurs on or after September 15, 2028, with respect to the originally-scheduled interest payment date on each series of the RSNs that would have occurred on the purchase contract settlement date, an undivided beneficial interest in U.S. Treasury securities (or principal or interest strips thereof) that mature on or prior to the purchase contract settlement date, in an aggregate amount at maturity equal to the aggregate interest payments (assuming no reset of the interest rate) that would have been paid on the purchase contract settlement date with respect to a 1/40 undivided beneficial ownership interest in $1,000 principal amount of each series of the RSNs.

If United States Treasury securities (or principal or interest strips thereof) that are to be included in the Treasury portfolio in connection with a successful optional remarketing have a yield that is less than zero, (i) the Treasury portfolio will consist of an amount in cash equal to the aggregate principal amount at maturity of the United States Treasury securities described in clauses (1) and (2) or (3) above and (ii) references to the “applicable ownership interest in the Treasury portfolio” or clauses (1) and (2) or (3) above will be deemed to be references to an interest in such amount of cash or the applicable portion thereof. If the provisions set forth in this paragraph apply, references to “Treasury security” and “United States Treasury securities (or principal or interest strips thereof)” in connection with the Treasury portfolio will, thereafter, be deemed to be references to such amount of cash.

So long as the Equity Units are in the form of Corporate Units, the related undivided beneficial ownership interest in a Series 2025B RSN and in a Series 2025C RSN or the applicable ownership interest in the Treasury portfolio described in clause (1) of the definition of “applicable ownership interest” above (or $50 in cash, if the immediately preceding paragraph applies), as the case may be, will be pledged to the Company through the collateral agent to secure the holders’ obligations to purchase the Common Stock under the related purchase contracts.

Creating Treasury Units by Substituting a Treasury Security for the RSNs

Each holder of 40 Corporate Units may create, at any time other than after a successful remarketing or during a blackout period (as defined below), 40 Treasury Units by substituting for an RSN of each series two zero-coupon United States Treasury securities (for example, CUSIP No. 912821GX7) each with a principal amount at maturity equal to $1,000 and maturing on or prior to December 15, 2028, which is referred to as a “Treasury security.” This substitution would create 40 Treasury Units and the RSN of each series would be released from the pledge under the purchase contract and pledge agreement and delivered to the holder and would be tradable and transferable separately from the Treasury Units. Because both series of RSNs are issued in integral multiples of $1,000, holders of Corporate Units may make the substitution only in integral multiples of 40

Corporate Units. After a successful remarketing, holders may not create Treasury Units from Corporate Units or recreate Corporate Units from Treasury Units.

Each Treasury Unit will consist of:

•    a purchase contract under which

o    the holder has agreed to purchase from the Company, and the Company has agreed to sell to the holder, on the purchase contract settlement date, or earlier upon early settlement, for $50, a number of shares of Common Stock equal to the applicable settlement rate, plus, in the case of an early settlement upon a fundamental change, the number of make-whole shares; and

o    the Company will pay the holder quarterly contract adjustment payments at the rate of 2.975% per year on the stated amount of $50, or $1.4875 per year, subject to the Company’s right to defer the contract adjustment payments; and

•    a 1/20 undivided beneficial ownership interest in a Treasury security.

The term “blackout period” means the period (1) if the Company elects to conduct an optional remarketing, from 4:00 p.m., New York City time, on the second business day (as defined below) immediately preceding the first day of the applicable optional remarking period until the settlement date of such optional remarketing or the date the Company announces that such remarketing was unsuccessful and (2) after 4:00 p.m., New York City time, on the second business day immediately preceding the first day of the final remarketing period.

The term “business day” means any day that is not a Saturday or Sunday or a day on which banking institutions in The City of New York or Hartford, Connecticut are authorized or required by law or executive order to close or a day on which the corporate trust office of the purchase contract agent is closed for business.

The Treasury Unit holder’s beneficial ownership interest in the Treasury security will be pledged to the Company through the collateral agent to secure the holder’s obligation to purchase Common Stock under the related purchase contracts.

To create 40 Treasury Units, a holder is required to:

•    deposit with the collateral agent two Treasury securities that each have a principal amount at maturity of $1,000, which must be purchased in the open market at the expense of the Corporate Unit holder, unless otherwise owned by the holder; and

•    transfer to the purchase contract agent 40 Corporate Units, accompanied by a notice stating that the holder of the Corporate Units has deposited two Treasury securities with the collateral agent and requesting that the purchase contract agent instruct the collateral agent to release the related RSN of each series.

Upon receiving instructions from the purchase contract agent and receipt of the Treasury securities, the collateral agent will release the related RSN of each series from the pledge and deliver them to the purchase contract agent on behalf of the holder, free and clear of the Company’s security interest. The purchase contract agent then will:

•    cancel the 40 Corporate Units;

•    transfer the related RSN of each series to the holder; and

•    deliver 40 Treasury Units to the holder.

The Treasury securities will be substituted for the RSNs and will be pledged to the Company through the collateral agent to secure the holder’s obligation to purchase shares of Common Stock under the related purchase contracts. The RSNs thereafter will trade and be transferable separately from the Treasury Units.

Holders who create Treasury Units will be responsible for any taxes, governmental charges or other fees or expenses (including, without limitation, fees and expenses payable to the collateral agent) attributable to such collateral substitution. See “Certain Provisions of the Purchase Contract and Pledge Agreement—Miscellaneous.”

Recreating Corporate Units

Each holder of 40 Treasury Units will have the right, at any time, other than during a blackout period or after a successful remarketing, to substitute for the related Treasury securities held by the collateral agent a RSN of each series having a principal amount equal to $1,000. This substitution would recreate 40 Corporate Units and the applicable Treasury securities would be released from the pledge under the purchase contract and pledge agreement and delivered to the holder and would be tradable and transferable separately from the Corporate Units. Because both series of RSNs are issued in integral multiples of $1,000, holders of Treasury Units may make this substitution only in integral multiples of 40 Treasury Units. After a successful remarketing, holders may not recreate Corporate Units from Treasury Units.

To recreate 40 Corporate Units, a holder is required to:

•    deposit with the collateral agent a RSN of each series having a principal amount of $1,000, which must be purchased in the open market at the expense of the Treasury Unit holder, unless otherwise owned by the holder; and

•    transfer to the purchase contract agent 40 Treasury Units, accompanied by a notice stating that the holder of the Treasury Units has deposited a RSN of each series having a principal amount of $1,000 with the collateral agent and requesting that the purchase contract agent instruct the collateral agent to release the related Treasury securities.

Upon receiving instructions from the purchase contract agent and receipt of a RSN of each series having a principal amount of $1,000, the collateral agent will promptly release the related Treasury securities from the pledge and promptly instruct the securities intermediary to transfer such Treasury securities to the purchase contract agent for distribution to the holder, free and clear of the Company’s security interest. The purchase contract agent then will:

•    cancel the 40 Treasury Units;

•    transfer the related Treasury securities to the holder; and

•    deliver 40 Corporate Units to the holder.

The $1,000 principal amount RSN of each series will be substituted for the Treasury securities and will be pledged to the Company through the collateral agent to secure the holder’s obligation to purchase shares of Common Stock under the related purchase contracts. The Treasury securities thereafter will trade and be transferable separately from the Corporate Units.

Holders who recreate Corporate Units will be responsible for any taxes, governmental charges or other fees or expenses (including, without limitation, fees and expenses payable to the collateral agent) attributable to the collateral substitution. See “Certain Provisions of the Purchase Contract and Pledge Agreement—Miscellaneous.”

Payments on the Equity Units

Holders of Corporate Units and Treasury Units will receive quarterly contract adjustment payments payable by the Company at the rate of 2.975% per year on the stated amount of $50 per Equity Unit. The Company will make all contract adjustment payments on the Corporate Units and the Treasury Units quarterly in arrears on March 15, June 15, September 15 and December 15 of each year (except that if any such date is not a business day, contract adjustment payments will be payable on the following business day, without adjustment), commencing March 15, 2026. Unless the purchase contracts have been terminated (as described under “Description of the Purchase Contracts—Termination” below), the Company will make such contract adjustment payments until the earliest of the purchase contract settlement date, the fundamental change early settlement date (in the case of a fundamental change early settlement, as described under “Description of the Purchase Contracts—Early Settlement Upon a Fundamental Change” below) and the most recent contract adjustment payment date on or before any other early settlement with respect to the related purchase contracts (in the case of an early settlement as described under “Description of the Purchase Contracts—Early Settlement” below). If the purchase contracts have been terminated, the Company’s obligation to pay the contract adjustment payments, including any accrued and unpaid contract adjustment payments and deferred contract adjustment payments (including compounded contract adjustment payments thereon), will cease. In addition, holders of Corporate Units receive quarterly cash distributions consisting of their pro rata share of interest payments on each series of RSNs (or distributions on the applicable ownership interest in the Treasury portfolio, as applicable), equivalent to the rate of 4.15% per year for the Series 2025B RSNs and 4.15% per year for the Series 2025C RSNs. There will be no interest payments in respect of the Treasury securities that are a component of the Treasury Units, but to the extent that such holders of Treasury Units continue to hold the RSNs that were delivered to them when they created the Treasury Units, such holders will continue to receive the scheduled interest payments on their separate RSNs for as long as they hold the RSNs, subject to any modifications made thereto pursuant to a successful remarketing.

The Company has the right to defer payment of quarterly contract adjustment payments as described under “Description of the Purchase Contracts—Contract Adjustment Payments”.

Listing

The Corporate Units are listed on the New York Stock Exchange under the symbol “SOMN”. Except in connection with early settlement, fundamental change early settlement, a termination event or settlement on the purchase contract settlement date with separate cash, unless and until substitution has been made as described in “—Creating Treasury Units by Substituting a Treasury Security for the RSNs” or “—Recreating Corporate Units,” neither the RSN of either series or the applicable ownership interest in the Treasury portfolio component of a Corporate Unit nor the Treasury security component of a Treasury Unit will trade separately from Corporate Units or Treasury Units. The

RSNs or applicable ownership interest in the Treasury portfolio component will trade as a unit with the purchase contract component of the Corporate Units, and the Treasury security component will trade as a unit with the purchase contract component of the Treasury Units. In addition, if Treasury Units or RSNs of either series are separately traded to a sufficient extent that the applicable exchange listing requirements are met, the Company may endeavor to cause the Treasury Units or RSNs of either series to be listed on the exchange on which the Corporate Units are then listed, including, if applicable, the New York Stock Exchange. However, there can be no assurance that the Company will list the Treasury Units or the RSNs of either series on any exchange or quotation system.

Ranking

The RSNs, which are included in the Equity Units, are direct, unsecured and unsubordinated obligations of the Company ranking equally with all other unsecured and unsubordinated obligations of the Company from time to time outstanding. The Series 2025B RSNs and the Series 2025C RSNs were issued under the Company’s Senior Note Indenture.

The Company’s obligations with respect to contract adjustment payments are subordinated in right of payment to the Company’s existing and future Senior Indebtedness (as defined under “Description of the Junior Subordinated Notes—Subordination” above).

The RSNs and the Company’s obligations with respect to contract adjustments payments are structurally subordinated to existing or future preferred stock and indebtedness, guarantees and other liabilities, including trade payables, of the Company’s subsidiaries and effectively subordinated to all secured indebtedness of the Company.

The Company’s subsidiaries are separate and distinct legal entities from the Company. The Company’s subsidiaries have no obligation to pay any amounts due on the RSNs or the purchase contracts or to provide the Company with funds to meet the Company’s respective payment obligations on the RSNs or purchase contracts. Any payment of dividends, loans or advances by the Company’s subsidiaries to the Company could be subject to statutory or contractual restrictions and will be contingent upon the subsidiaries’ earnings and business considerations. The Company’s right to receive any assets of any of the Company’s subsidiaries upon their bankruptcy, liquidation or similar reorganization, and therefore the right of the holders of the RSNs or purchase contracts to participate in those assets, will be structurally subordinated to the claims of that subsidiary’s creditors, including trade creditors. Even if the Company is a creditor of any of the Company’s subsidiaries, the Company’s rights as a creditor would be subordinated to any security interest in the assets of the Company’s subsidiaries and any indebtedness of the Company’s subsidiaries senior to that held by the Company.

Voting and Certain Other Rights

Prior to the delivery of shares of Common Stock under each purchase contract, such purchase contract shall not entitle the holder of the Corporate Units or Treasury Units to any rights of a holder of shares of Common Stock, including, without limitation, the right to vote or receive any dividends or other payments or distributions or to consent to or to receive notice as a stockholder or other rights in respect of the Common Stock.

Repurchase of the Equity Units

The Company may purchase from time to time any of the Equity Units that are then outstanding by tender, in the open market, by private agreement or otherwise, subject to compliance with applicable law.

Description of the Purchase Contracts

The term “business day”, as used in this Description of the Purchase Contracts, has the meaning ascribed to it under the caption “Description of the Equity Units” above.

The term “record date”, as used in this Description of the Purchase Contracts, has the meaning ascribed to it in this Description of the Purchase Contracts.

Purchase of Common Stock

Each purchase contract that is a component of a Corporate Unit or a Treasury Unit obligates its holder to purchase, and the Company to issue and deliver, on the purchase contract settlement date (December 15, 2028 (or if such day is not a business day, the following business day)), for $50 in cash a number of shares of Common Stock equal to the settlement rate (together with cash, if applicable, in lieu of any fractional shares of Common Stock in the manner described below), unless the purchase contract terminates prior to that date or is settled early at the holder’s option. The number of shares of Common Stock issuable upon settlement of each purchase contract on the purchase contract settlement date (which is referred to as the “settlement rate”) will be determined as follows, subject to adjustment as described under “—Anti-dilution Adjustments” below:

(1)    If the applicable market value of Common Stock is equal to or greater than the “threshold appreciation price” of $116.44, the settlement rate will be 0.4294 shares of the Common Stock (this settlement rate is referred to as the “minimum settlement rate”).

Accordingly, if the market price for the Common Stock increases between November 3, 2025 (the date the Equity Units were priced (the “Pricing Date”)) and the period during which the applicable market value is measured and the applicable market value is greater than the threshold appreciation price, the aggregate market value of the shares of Common Stock issued upon settlement of each purchase contract will be higher than the stated amount, assuming that the market price of the Common Stock on the purchase contract settlement date is the same as the applicable market value of the Common Stock. If the applicable market value is the same as the threshold appreciation price, the aggregate market value of the shares issued upon settlement will be equal to the stated amount, assuming that the market price of the Common Stock on the purchase contract settlement date is the same as the applicable market value of the Common Stock.

(2)    If the applicable market value of the Common Stock is less than the threshold appreciation price but greater than the “reference price” of $93.15, which was the closing price of the Common Stock on the New York Stock Exchange on the Pricing Date, the settlement rate will be a number of shares of Common Stock equal to $50 divided by the applicable market value, rounded to the nearest ten thousandth of a share.

Accordingly, if the market price for the Common Stock increases between the Pricing Date and the period during which the applicable market value is measured, but the market price does not exceed the threshold appreciation price, the aggregate market value of the shares of Common Stock issued upon settlement of each purchase contract will be equal to the stated amount, assuming that the market price of the Common Stock on the purchase contract settlement date is the same as the applicable market value of the Common Stock.

(3)    If the applicable market value of the Common Stock is less than or equal to the reference price of $93.15, the settlement rate will be 0.5368 shares of Common Stock, which

is equal to the stated amount divided by the reference price (this settlement rate is referred to as the “maximum settlement rate”).

Accordingly, if the market price for the Common Stock decreases between the Pricing Date and the period during which the applicable market value is measured and the market price is less than the reference price, the aggregate market value of the shares of Common Stock issued upon settlement of each purchase contract will be less than the stated amount, assuming that the market price on the purchase contract settlement date is the same as the applicable market value of the Common Stock. If the market price of the Common Stock is the same as the reference price, the aggregate market value of the shares will be equal to the stated amount, assuming that the market price of the Common Stock on the purchase contract settlement date is the same as the applicable market value of the Common Stock.

The threshold appreciation price is equal to $50 divided by the minimum settlement rate (such quotient rounded to the nearest $0.0001), which is $116.44 and represents appreciation of approximately 25.0% over the reference price.

If you elect to settle your purchase contract early in the manner described under “—Early Settlement,” the number of shares of Common Stock issuable upon settlement of such purchase contract will be 0.4294, the minimum settlement rate, subject to adjustment as described under “—Anti-dilution Adjustments.” If you elect to settle your purchase contract early upon a fundamental change, the number of shares of Common Stock issuable upon settlement will be determined as described under “—Early Settlement Upon a Fundamental Change.” The minimum settlement rate and the maximum settlement rate are referred to as the “fixed settlement rates.”

The “applicable market value” means the average of the volume-weighted average price, or VWAP, of the Common Stock on each trading day during the 20 consecutive scheduled trading day period ending on the third scheduled trading day immediately preceding the purchase contract settlement date (the “market value averaging period”). The “VWAP” of the Common Stock means, for the relevant trading day, the per share VWAP on the principal exchange or quotation system on which the Common Stock is listed or admitted for trading as displayed under the heading Bloomberg VWAP on Bloomberg page “SO US <EQUITY> AQR” (or its equivalent successor if that page is not available) in respect of the period from the scheduled open of trading on the relevant trading day until the scheduled close of trading on the relevant trading day (or if such VWAP is unavailable, the market price of one share of Common Stock on such trading day determined, using a volume-weighted average method, by a nationally recognized independent investment banking firm retained for this purpose by the Company).

A “trading day” means, for purposes of determining a VWAP or closing price, a day (i) on which the principal exchange or quotation system on which the Common Stock is listed or admitted for trading is scheduled to be open for business and (ii) on which there has not occurred or does not exist a market disruption event.

A “market disruption event” means any of the following events:

•    any suspension of, or limitation imposed on, trading by the principal exchange or quotation system on which the Common Stock is listed or admitted for trading during the one-hour period prior to the close of trading for the regular trading session on such exchange or quotation system (or for purposes of determining VWAP any period or periods prior to 1:00 p.m., New York City time, aggregating one half hour or longer) and whether by reason of movements in price

exceeding limits permitted by the relevant exchange or quotation system or otherwise relating to the Common Stock or in futures or option contracts relating to the Common Stock on the relevant exchange or quotation system; or

•    any event (other than a failure to open or, except for purposes of determining VWAP, a closure as described below) that disrupts or impairs the ability of market participants during the one-hour period prior to the close of trading for the regular trading session on the principal exchange or quotation system on which the Common Stock is listed or admitted for trading (or for purposes of determining VWAP any period or periods prior to 1:00 p.m., New York City time, aggregating one half hour or longer) in general to effect transactions in, or obtain market values for, the Common Stock on the relevant exchange or quotation system or futures or options contracts relating to the Common Stock on any relevant exchange or quotation system; or

•    the failure to open of the principal exchange or quotation system on which futures or options contracts relating to the Common Stock are traded or, except for purposes of determining VWAP, the closure of such exchange or quotation system prior to its respective scheduled closing time for the regular trading session on such day (without regard to after hours or other trading outside the regular trading session hours) unless such earlier closing time is announced by such exchange or quotation system at least one hour prior to the earlier of the actual closing time for the regular trading session on such day and the submission deadline for orders to be entered into such exchange or quotation system for execution at the actual closing time on such day.

If a market disruption event occurs on any scheduled trading day during the market value averaging period, the Company will notify investors on the calendar day on which such event occurs.

If 20 trading days for the Common Stock have not occurred during the market value averaging period, all remaining trading days will be deemed to occur on the third scheduled trading day immediately prior to the purchase contract settlement date and the VWAP of the Common Stock for each of the remaining trading days will be the VWAP of the Common Stock on that third scheduled trading day or, if such day is not a trading day, the closing price as of such day.

The “closing price” per share of Common Stock means, on any date of determination, the closing sale price or, if no closing sale price is reported, the last reported sale price of the Common Stock on the principal United States securities exchange on which the Common Stock is listed, or if the Common Stock is not so listed on a United States securities exchange, the average of the last quoted bid and ask prices for the Common Stock in the over-the-counter market as reported by OTC Markets Group Inc. or similar organization, or, if those bid and ask prices are not available, the market value of the Common Stock on that date as determined by a nationally recognized independent investment banking firm retained by the Company for this purpose.

The Company will not issue any fractional shares of Common Stock upon settlement of a purchase contract. Instead of a fractional share, the holder will receive an amount of cash equal to the percentage of a whole share represented by such fractional share multiplied by the closing price of the Common Stock on the trading day immediately preceding the purchase contract settlement date (or the trading day immediately preceding the relevant settlement date, in the case of early settlement). If, however, a holder surrenders for settlement at one time certificates evidencing more than one purchase contract, then the number of shares of Common Stock issuable pursuant to such purchase contracts will be computed based upon the aggregate number of purchase contracts surrendered (including any global security certificate, to the extent permitted by, and practicable under, procedures of The Depository Trust Company (“DTC” or the “depository”)).

Unless:

•    a holder has settled early the related purchase contracts by delivery of cash to the purchase contract agent in the manner described under “—Early Settlement” or “—Early Settlement Upon a Fundamental Change;”

•    a holder of Corporate Units has settled the related purchase contracts with separate cash in the manner described under “—Notice to Settle with Cash;” or

•    an event described under “—Termination” has occurred;

then, on the purchase contract settlement date,

•    in the case of Corporate Units where there has not been a successful optional or final remarketing, the holder will be deemed to have exercised its put right as described under “—Remarketing” (unless it shall have elected not to exercise such put right by delivering cash as described thereunder) and to have elected to apply the proceeds of the put price to satisfy in full the holder’s obligation to purchase Common Stock under the related purchase contracts;

•    in the case of Corporate Units where the Treasury portfolio or cash has replaced the RSNs as a component of the Corporate Units following a successful optional remarketing, the portion of the proceeds of the applicable ownership interests in the Treasury portfolio when paid at maturity or an amount of cash equal to the stated amount of $50 per Corporate Unit will be applied to satisfy in full the holder’s obligation to purchase Common Stock under the related purchase contracts and any excess proceeds will be delivered to the purchase contract agent for the benefit of the holders of Corporate Units;

•    in the case of Corporate Units where the RSNs have been successfully remarketed during the final remarketing period, the portion of the remarketing proceeds sufficient to satisfy the holder’s obligation to purchase Common Stock under the related purchase contracts will be applied to satisfy in full the holder’s obligation to purchase Common Stock under the related purchase contracts and any excess proceeds will be delivered to the purchase contract agent for the benefit of the holders of Corporate Units; and

•    in the case of Treasury Units, the proceeds of the related Treasury securities, when paid at maturity, will be applied to satisfy in full the holder’s obligation to purchase Common Stock under the related purchase contracts and any excess proceeds will be delivered to the purchase contract agent for the benefit of the holders of Treasury Units.

The Common Stock will then be issued and delivered to the holder or the holder’s designee on the purchase contract settlement date. The Company will pay all stock transfer and similar taxes attributable to the initial issuance and delivery of the shares of Common Stock pursuant to the purchase contracts, unless any such tax is due because the holder requests such shares to be issued in a name other than such holder’s name.

Prior to the settlement of a purchase contract, the shares of Common Stock underlying each purchase contract will not be outstanding, and the holder of the purchase contract will not have any voting rights, rights to dividends or other distributions or other rights of a holder of Common Stock by virtue of holding such purchase contract.

By purchasing a Corporate Unit or a Treasury Unit, a holder is deemed to have, among other things:

•    irrevocably appointed the purchase contract agent as its attorney-in-fact to enter into and perform the related purchase contract and the purchase contract and pledge agreement in the name of and on behalf of such holder;

•    agreed to be bound by the terms and provisions of the Corporate Units or Treasury Units, as applicable, including, but not limited to, the terms of the related purchase contract and the purchase contract and pledge agreement, for so long as the holder remains a holder of Corporate Units or Treasury Units;

•    consented to and agreed to be bound by the pledge of such holder’s right, title and interest in and to its undivided beneficial ownership interest in each series of RSNs, the portion of the Treasury portfolio (or cash) described in the first clause of the definition of “applicable ownership interest” or the Treasury securities, as applicable, and the delivery of such collateral by the purchase contract agent to the collateral agent; and

•    agreed to the satisfaction of the holder’s obligations under the purchase contracts with the proceeds of the pledged undivided beneficial ownership in the RSNs, Treasury portfolio (or cash), Treasury securities or put price, as applicable, in the manner described above if the option to settle the purchase contracts through payment of separate cash is not elected.

Remarketing

The Company has agreed to enter into a remarketing agreement with one or more remarketing agents no later than 20 days prior to the first day of the final remarketing period or, if the Company elects to conduct an optional remarketing, no later than five business days prior to the first day of the applicable optional remarketing period.

During a blackout period that relates to each remarketing period:

•    a holder may not settle a purchase contract early;

•    a holder may not create Treasury Units; and

•    a holder may not recreate Corporate Units from Treasury Units.

Each of an “optional remarketing” and a “final remarketing” is referred to as a “remarketing.” In a remarketing, the RSNs of each series that are a part of Corporate Units (except, in the case of a final remarketing, where the holder has elected to settle the purchase contract through payment of separate cash) and any separate RSNs whose holders have elected to participate in the remarketing, as described under “Description of the Remarketable Senior Notes—Remarketing of RSNs That Are Not Included in Corporate Units,” will be remarketed.

Following any successful remarketing of the RSNs:

•    the interest rate on each series of RSNs may be reset as described below and under “Description of the Remarketable Senior Notes—Interest Rate Reset” below;

•    interest will be payable on the RSNs semi-annually on June 15 and December 15 of each year (except with respect to any series of RSNs remarketed as floating-rate notes); and

•    the Series 2025C RSNs will cease to be redeemable at the Company’s option, and the provisions described under “Description of the Remarketable Senior Notes—Redemption at the Company’s Option” and “—Redemption Procedures” will no longer apply to the Series 2025C RSNs.

All such modifications will take effect only if the remarketing is successful, without the consent of holders, upon the earlier of the optional remarketing settlement date or the purchase contract settlement date, as the case may be, and will apply to all RSNs of such series, whether or not included in the remarketing. All other terms of the RSNs will remain unchanged.

In order to remarket the RSNs, the remarketing agent, in consultation with the Company, may:

•remarket each series of RSNs as fixed-rate notes or floating-rate notes;

•in the case of any series of RSNs remarketed as fixed-rate notes, reset the interest rate on such series of RSNs (either upward or downward) and, in the case of any series of RSNs remarketed as floating-rate notes, determine the interest rate spread applicable to such series of RSNs, in order to produce the required price in the remarketing, as discussed under “—Optional Remarketing” and “—Final Remarketing” below; and

•in the case of any series of RSNs remarketed as floating-rate notes, (i) provide that the interest on such series of RSNs will be equal to an interest rate index determined by the Company plus a spread determined by the remarketing agent, in consultation with the Company, in which case interest on such series of RSNs may be calculated on the basis of a 360-day year and the actual number of days elapsed (or such other basis as is customarily used for floating-rate notes bearing interest at a rate based on such interest rate index), and (ii) provide for provisions regarding calculation of the selected interest rate index and related benchmark transition provisions, in each case, that are customary for floating-rate notes bearing interest at a rate based on such interest rate index.

The Company will use commercially reasonable efforts to ensure that, if required by applicable law, a registration statement, including a prospectus, with regard to the full amount of each series of the RSNs to be remarketed will be effective under the securities laws in a form that may be used by the remarketing agent in connection with the remarketing (unless a registration statement is not required under the applicable laws and regulations that are in effect at that time or unless the Company conducts any remarketing in accordance with an exemption under the securities laws).

The Company will separately pay a fee to the remarketing agent for its services as remarketing agent. Holders whose RSNs are remarketed will not be responsible for the payment of any remarketing fee in connection with the remarketing.

Optional Remarketing

Unless a termination event has occurred, the Company may elect, at the Company’s option, to engage the remarketing agent pursuant to the terms of the remarketing agreement, to remarket the RSNs on any optional remarketing date occurring during the “period for early remarketing” beginning on and including June 13, 2028 (the second business day immediately preceding the June 15, 2028 interest payment date) and ending on and including November 21, 2028 (the eighth calendar day immediately preceding the first day of the final remarketing period), unless the RSNs have been

previously successfully remarketed. Any optional remarketing during the period for optional remarketing will occur during one or more periods of up to 15 business days selected by the Company; any such period of up to 15 business days selected by the Company for an optional remarketing is referred to as an “optional remarketing period,” a remarketing that occurs during an optional remarketing period as an “optional remarketing” and the date the RSNs are priced in an optional remarketing as the “optional remarketing date.” In any optional remarketing, the aggregate principal amount of the RSNs of each series that are a part of Corporate Units and any separate RSNs of either series whose holders have elected to participate in the optional remarketing, as described under “Description of the Remarketable Senior Notes—Remarketing of RSNs That Are Not Included in Corporate Units,” will be remarketed. If the Company elects to conduct an optional remarketing, the remarketing agent will use its commercially reasonable efforts to obtain a price for the RSNs of each series that results in aggregate proceeds of at least 100% of the aggregate of the Treasury portfolio purchase price (as defined below) and the separate RSNs purchase price (as defined below). To obtain that price, the remarketing agent may, in consultation with the Company, in the case of any series of RSNs remarketed as fixed-rate notes, reset the interest rate on such series of RSNs and, in the case of any series of RSNs remarketed as floating-rate notes, determine the interest rate spread applicable to such series of RSNs, as described under “Description of the Remarketable Senior Notes—Interest Rate Reset.” The Company will request that the depository notify its participants holding Corporate Units, Treasury Units and separate RSNs of the Company’s election to conduct an optional remarketing no later than five business days prior to the date the Company begins any optional remarketing.

An optional remarketing on any remarketing date will be considered successful if the remarketing agent is able to remarket the RSNs of each series at a price that results in aggregate proceeds of at least 100% of the Treasury portfolio purchase price and the separate RSNs purchase price.

Following a successful optional remarketing of the RSNs, on the optional remarketing settlement date, the portion of the remarketing proceeds equal to the Treasury portfolio purchase price will, except as described below, be used to purchase the Treasury portfolio and the remaining proceeds attributable to the RSNs underlying the Corporate Units will be remitted to the purchase contract agent for distribution pro rata to the holders of such Corporate Units. The portion of the remarketing proceeds attributable to the separate RSNs sold in the remarketing will be remitted to the custodial agent for distribution on the optional remarketing settlement date to the holders of such separate RSNs.

If the Company elects to conduct an optional remarketing and the remarketing is successful:

•    settlement with respect to the remarketed RSNs will occur on the second business day following the optional remarketing date, unless the remarketed RSNs are priced after 4:30 p.m., New York City time, on the optional remarketing date, in which case settlement will occur on the third business day following the optional remarketing date (such settlement date is referred to as the “optional remarketing settlement date”);

•    interest on the RSNs will be payable semi-annually (except with respect to any series of RSNs remarketed as floating-rate notes);

•in the case of any series of RSNs remarketed as fixed-rate notes, the interest rate on such series of RSNs will be reset and, in the case of any series of RSNs remarketed as floating-rate notes, the interest rate spread for such series of RSNs will be determined, by the remarketing agent in

consultation with the Company on the optional remarketing date and will become effective on the optional remarketing settlement date, if applicable;

•    the other modifications to the terms of the RSNs, as described under “—Remarketing,” will become effective;

•    after the optional remarketing settlement date, your Corporate Units will consist of a purchase contract and the applicable ownership interest in the Treasury portfolio (or cash), as described herein; and

•    you may no longer create Treasury Units or recreate Corporate Units from Treasury Units.

If the Company does not elect to conduct an optional remarketing during an optional remarketing period or no optional remarketing succeeds for any reason, the RSNs will continue to be a component of the Corporate Units or will continue to be held separately and the remarketing agent will use its commercially reasonable efforts to remarket the RSNs during the final remarketing period.

For the purposes of a successful optional remarketing, “Treasury portfolio purchase price” means the lowest aggregate ask-side price quoted by a primary United States government securities dealer in New York City to the quotation agent selected by the Company between 9:00 a.m. and 4:00 p.m., New York City time, on the optional remarketing date for the purchase of the Treasury portfolio for settlement on the optional remarketing settlement date; provided that if the Treasury portfolio consists of cash, “Treasury portfolio purchase price” means the amount of such cash.

Components of the Treasury Portfolio

Following a successful optional remarketing and receipt of the proceeds, the collateral agent will purchase, at the Treasury portfolio purchase price, a Treasury portfolio consisting of:

•    United States Treasury securities (or principal or interest strips thereof) that mature on or prior to the purchase contract settlement date in an aggregate amount at maturity equal to the principal amount of the Series 2025B RSNs underlying the undivided beneficial ownership interests in the Series 2025B RSNs included in the Corporate Units on the optional remarketing date;

•    United States Treasury securities (or principal or interest strips thereof) that mature on or prior to the purchase contract settlement date in an aggregate amount at maturity equal to the principal amount of the Series 2025C RSNs underlying the undivided beneficial ownership interests in the Series 2025C RSNs included in the Corporate Units on the optional remarketing date;

•    if the optional remarketing settlement date occurs prior to September 15, 2028, with respect to the originally-scheduled quarterly interest payment dates on the Series 2025B RSNs that would have occurred on September 15, 2028 and the purchase contract settlement date, U.S. Treasury securities (or principal or interest strips thereof) that mature on or prior to (i) September 14, 2028 (in connection with the interest payment date that would have occurred on September 15, 2028) and (ii) December 14, 2028 (in connection with the interest payment date that would have occurred on the purchase contract settlement date), each in an aggregate amount at maturity equal to the aggregate interest payments (assuming no reset of the interest rate) that would have been paid to the holders of the Corporate Units on September 15, 2028 and the purchase contract settlement date, respectively, on the principal amount of the Series 2025B RSNs underlying the

undivided beneficial ownership interests in the Series 2025B RSNs included in the Corporate Units on the optional remarketing date;

•    if the optional remarketing settlement date occurs on or after September 15, 2028, United States Treasury securities (or principal or interest strips thereof) that mature on or prior to the purchase contract settlement date in an aggregate amount at maturity equal to the aggregate interest payment (assuming no reset of the interest rate) that would have been paid to the holders of the Corporate Units on the purchase contract settlement date on the principal amount of the Series 2025B RSNs underlying the undivided beneficial ownership interests in the Series 2025B RSNs included in the Corporate Units on the optional remarketing date;

•    if the optional remarketing settlement date occurs prior to September 15, 2028, with respect to the originally-scheduled quarterly interest payment dates on the Series 2025C RSNs that would have occurred on September 15, 2028 and the purchase contract settlement date, U.S. Treasury securities (or principal or interest strips thereof) that mature on or prior to (i) September 14, 2028 (in connection with the interest payment date that would have occurred on September 15, 2028) and (ii) December 14, 2028 (in connection with the interest payment date that would have occurred on the purchase contract settlement date), each in an aggregate amount at maturity equal to the aggregate interest payments (assuming no reset of the interest rate) that would have been paid to the holders of the Corporate Units on September 15, 2028 and the purchase contract settlement date, respectively, on the principal amount of the Series 2025C RSNs underlying the undivided beneficial ownership interests in the Series 2025C RSNs included in the Corporate Units on the optional remarketing date; and

•    if the optional remarketing settlement date occurs on or after September 15, 2028, United States Treasury securities (or principal or interest strips thereof) that mature on or prior to the purchase contract settlement date in an aggregate amount at maturity equal to the aggregate interest payment (assuming no reset of the interest rate) that would have been paid to the holders of the Corporate Units on the purchase contract settlement date on the principal amount of the Series 2025C RSNs underlying the undivided beneficial ownership interests in the Series 2025C RSNs included in the Corporate Units on the optional remarketing date.

If United States Treasury securities (or principal or interest strips thereof) that are to be included in the Treasury portfolio in connection with a successful optional remarketing have a yield that is less than zero, the Treasury portfolio will consist of an amount in cash equal to the aggregate principal amount at maturity of the United States Treasury securities described in the bullet points above. If the provisions set forth in this paragraph apply, references herein to a “Treasury security” and “United States Treasury securities (or principal or interest strips thereof)” in connection with the Treasury portfolio will, thereafter, be deemed to be references to such amount in cash.

The applicable ownership interests in the Treasury portfolio will be substituted for the undivided beneficial ownership interests in the RSNs of each series that are components of the Corporate Units and the portions of the Treasury portfolio described in the first and second bullets above will be pledged to the Company through the collateral agent to secure the Corporate Unit holders’ obligation under the purchase contracts. On the purchase contract settlement date, for each Corporate Unit, $50 of the proceeds from the Treasury portfolio will automatically be applied to satisfy the Corporate Unit holder’s obligation to purchase Common Stock under the purchase contract. In addition, proceeds from the portions of the Treasury portfolio described in the third and fifth bullets above (if the optional remarketing occurs prior to September 15, 2028) or the fourth and sixth bullets above (if the optional remarketing occurs on or after September 15, 2028), as applicable,

which will equal the interest payments (assuming no reset of the interest rate) that would have been paid on September 15, 2028 (if the optional remarketing occurs prior to such date) and the purchase contract settlement date on each series of RSNs that were components of the Corporate Units at the time of remarketing, will be paid to the holders of the Corporate Units on such date or dates, as applicable.

If the Company elects to remarket the RSNs during any optional remarketing period and a successful remarketing has not occurred on or prior to the last day of the applicable optional remarketing period, the Company will cause a notice of the failed remarketing to be published no later than 9:00 a.m., New York City time, on the business day immediately following the last date of the applicable optional remarketing period. This notice will be validly published by furnishing such information on a Current Report on Form 8-K or by making a timely release to any appropriate news agency, including Bloomberg Business News and the Dow Jones News Service. The Company will similarly cause a notice of a successful remarketing of the RSNs to be published no later than 9:00 a.m., New York City time, on the business day immediately following the date of such successful remarketing.

On each business day during any optional remarketing period, the Company has the right in its sole and absolute discretion to determine whether or not an optional remarketing will be attempted. At any time and from time to time during an optional remarketing period prior to the announcement of a successful optional remarketing, the Company has the right to postpone any optional remarketing in its sole and absolute discretion.

Final Remarketing

Unless a termination event or a successful optional remarketing has previously occurred, the Company will remarket the RSNs during the ten business day period ending on, and including, December 12, 2028 (the third business day immediately preceding the purchase contract settlement date). This period is referred to as the “final remarketing period,” the remarketing during this period as the “final remarketing” and the date the RSNs are priced in the final marketing as the “final remarketing date.” In the final remarketing, the aggregate principal amount of the RSNs of each series that are a part of Corporate Units (except where the holder has elected to settle the purchase contract through payment of separate cash) and any separate RSNs of either series whose holders have elected to participate in the final remarketing will be remarketed. The remarketing agent will use its commercially reasonable efforts to obtain a price for the RSNs of each series to be remarketed that results in proceeds of at least 100% of the principal amount of all the RSNs offered in the remarketing. To obtain that price, the remarketing agent may, in consultation with the Company, in the case of any series of RSNs remarketed as fixed-rate notes, reset the interest rate on such series of RSNs and, in the case of any series of RSNs remarketed as floating-rate notes, determine the interest rate spread applicable to such series of RSNs, as described under “Description of the Remarketable Senior Notes—Interest Rate Reset.” The Company will request that the depository notify its participants holding Corporate Units, Treasury Units and separate RSNs of the final remarketing no later than seven days prior to the first day of the final remarketing period. In such notice, the Company will set forth the dates of the final remarketing period, applicable procedures for holders of separate RSNs to participate in the final remarketing, the applicable procedures for holders of Corporate Units to create Treasury Units and for holders of Treasury Units to recreate Corporate Units, the applicable procedures for holders of Corporate Units to settle their purchase contracts early and any other applicable procedures, including the procedures that must be followed by a holder of separate RSNs in the case of a failed remarketing if a holder of separate RSNs wishes to exercise its right to put its RSNs to the Company as described below and under “Description of the Remarketable

Senior Notes—Put Option upon Failed Remarketing.” The Company has the right to postpone the final remarketing in its sole and absolute discretion on any day prior to the last three business days of the final remarketing period.

A remarketing during the final remarketing period will be considered successful if the remarketing agent is able to remarket the RSNs for a price of at least 100% of the aggregate principal amount of all the RSNs offered in the remarketing.

If the final remarketing is successful:

•    settlement with respect to the remarketed RSNs will occur on the purchase contract settlement date;

•    interest on the RSNs will be payable semi-annually (except with respect to any series of RSNs remarketed as floating-rate notes);

•    in the case of any series of RSNs remarketed as fixed-rate notes, the interest rate on such series of RSNs will be reset and, in the case of any series of RSNs remarketed as floating-rate notes, the interest rate spread for such series of RSNs will be determined, by the remarketing agent in consultation with the Company, and will become effective on the reset effective date, which will be the purchase contract settlement date, as described under “Description of the Remarketable Senior Notes—Interest Rate Reset” below;

•    the other modifications to the terms of the RSNs, as described under “—Remarketing,” will become effective; and

•    the collateral agent will remit the portion of the proceeds equal to the total principal amount of the RSNs of each series underlying the Corporate Units to the Company to satisfy in full the Corporate Unit holders’ obligations to purchase Common Stock under the related purchase contracts, and any excess proceeds attributable to RSNs underlying Corporate Units that were remarketed will be remitted to the purchase contract agent for distribution pro rata to the holders of such RSNs and proceeds from the final remarketing attributable to the separate RSNs remarketed will be remitted to the custodial agent for distribution pro rata to the holders of the remarketed separate RSNs.

Unless a termination event has occurred, a holder has effected an early settlement or a fundamental change early settlement or there has been a successful remarketing, each Corporate Unit holder has the option at any time on or after the date the Company gives notice of a final remarketing to notify the purchase contract agent at any time prior to 4:00 p.m., New York City time, on the second business day immediately prior to the first day of the final remarketing period of its intention to settle the related purchase contracts on the purchase contract settlement date with separate cash and to provide that cash on or prior to the business day immediately prior to the first day of the final remarketing period, as described under “—Notice to Settle with Cash.” The RSNs of any holder of Corporate Units who has not given this notice or failed to deliver the cash will be remarketed during the final remarketing period. In addition, holders of RSNs that do not underlie Corporate Units may elect to participate in the remarketing as described under “Description of the Remarketable Senior Notes—Remarketing of RSNs That Are Not Included in Corporate Units.”

If, in spite of using its commercially reasonable efforts, the remarketing agent cannot remarket the RSNs during the final remarketing period at a price equal to or greater than 100% of the aggregate

principal amount of all the RSNs offered in the remarketing, a condition precedent set forth in the remarketing agreement has not been fulfilled or a successful remarketing has not occurred for any other reason, in each case resulting in a “failed remarketing,” holders of all RSNs will have the right to put their RSNs to the Company for an amount equal to the principal amount of their RSNs (the “put price”). The conditions precedent in the remarketing agreement will include, but not be limited to, the timely filing with the SEC of all material related to the remarketing required to be filed by the Company, the truth and correctness of certain representations and warranties made by the Company in the remarketing agreement, the furnishing of certain officer’s certificates to the remarketing agent and the receipt by the remarketing agent of customary “comfort letters” from the Company’s auditors and opinions of counsel. A holder of Corporate Units will be deemed to have automatically exercised this put right with respect to both series of RSNs underlying such Corporate Units unless the holder has provided a written notice to the purchase contract agent of its intention to settle the purchase contract with separate cash as described below under “—Notice to Settle with Cash” prior to 4:00 p.m., New York City time, on the second business day immediately prior to the purchase contract settlement date, and on or prior to the business day immediately preceding the purchase contract settlement date has delivered the $50 in cash per purchase contract. Settlement with separate cash may only be effected in integral multiples of 40 Corporate Units. If a holder of Corporate Units elects to settle with separate cash, upon receipt of the required cash payment, the related RSNs underlying the Corporate Units will be released from the pledge under the purchase contract and pledge agreement and delivered promptly to the purchase contract agent for delivery to the holder. The holder of the Corporate Units will then receive the applicable number of shares of Common Stock on the purchase contract settlement date. The cash received by the collateral agent upon this settlement with separate cash may, upon the Company’s written direction, be invested in permitted investments, as defined in the purchase contract and pledge agreement, and the portion of the proceeds equal to the aggregate purchase price of all purchase contracts of such holders will be paid to the Company on the purchase contract settlement date. Permitted investments may include investments for which the collateral agent or its affiliates serve as manager, investment advisor, administrator, shareholder, servicing agent and/or custodian or sub-custodian and for which the collateral agent may receive fees. Any excess funds received by the collateral agent in respect of any such permitted investments over the aggregate purchase price remitted to the Company in satisfaction of the obligations of the holders under the purchase contracts will be distributed to the purchase contract agent for ratable payment to the applicable holders who settled with separate cash. If a failed remarketing has occurred, unless a holder of Corporate Units has elected to settle the related purchase contracts with separate cash and delivered the separate cash on or prior to the business day immediately preceding the purchase contract settlement date, the holder will be deemed to have elected to apply the put price against the holder’s obligations to pay the aggregate purchase price for the shares of Common Stock to be issued under the related purchase contracts, thereby satisfying the obligations in full, and the Company will deliver to the holder Common Stock pursuant to the related purchase contracts.

If a successful final remarketing has not occurred on or prior to December 12, 2028 (the last day of the final remarketing period), the Company will cause a notice of the failed remarketing of the RSNs to be published no later than 9:00 a.m., New York City time, on the business day immediately following the last date of the final remarketing period. This notice will be validly published by furnishing such information on a Current Report on Form 8-K or making a timely release to any appropriate news agency, including Bloomberg Business News and the Dow Jones News Service.

Early Settlement

Subject to the conditions described below, a holder of Corporate Units or Treasury Units may settle the related purchase contracts at any time prior to 4:00 p.m., New York City time, on the second

business day immediately preceding the purchase contract settlement date, other than during a blackout period in the case of Corporate Units. An early settlement may be made only in integral multiples of 40 Corporate Units or 20 Treasury Units; however, if the Treasury portfolio has replaced the RSNs as a component of the Corporate Units following a successful optional remarketing, holders of Corporate Units may settle early only in integral multiples of 160,000 Corporate Units. In order to settle purchase contracts early, a holder of Equity Units must deliver to the purchase contract agent at the corporate trust office of the purchase contract agent or its agent, in each case, in Hartford, Connecticut (1) a completed “Election to Settle Early” form, along with the Corporate Unit or Treasury Unit certificate, if they are in certificated form and (2) a cash payment in immediately available funds in an amount equal to:

•    $50 times the number of purchase contracts being settled; plus

•    if the early settlement date occurs during the period from the close of business on any record date next preceding any contract adjustment payment date to the opening of business on such contract adjustment payment date, an amount equal to the contract adjustment payments payable on such contract adjustment payment date, unless the Company has elected to defer the contract adjustment payments payable on such contract adjustment payment date.

So long as you hold Equity Units as a beneficial interest in a global security certificate deposited with the depository, procedures for early settlement will also be governed by standing arrangements between the depository and the purchase contract agent.

The early settlement right is also subject to the condition that, if required under United States federal securities laws, the Company has a registration statement under the Securities Act of 1933, as amended, in effect and an available prospectus covering the shares of Common Stock and other securities, if any, deliverable upon settlement of a purchase contract. The Company has agreed that, if such a registration statement is required, the Company will use its commercially reasonable efforts to (1) have a registration statement in effect covering those shares of Common Stock and other securities, if any, to be delivered in respect of the purchase contracts being settled and (2) provide a prospectus in connection therewith, in each case in a form that may be used in connection with the early settlement right (it being understood that if there is a material business transaction or development that has not yet been publicly disclosed, the Company will not be required to file such registration statement or provide such a prospectus, and the early settlement right will not be available, until the Company has publicly disclosed such transaction or development; provided that the Company will use commercially reasonable efforts to make such disclosure as soon as it is commercially reasonable to do so). In the event that a holder seeks to exercise its early settlement right and a registration statement is required to be effective in connection with the exercise of such right but no such registration statement is then effective, the holder’s exercise of such right will be void unless and until such a registration statement is effective.

Upon early settlement, except as described below in “—Early Settlement Upon a Fundamental Change,” the Company will sell, and the holder will be entitled to buy, the minimum settlement rate of 0.4294 shares of Common Stock (or in the case of an early settlement following a reorganization event, such number of exchange property units, as described under “—Reorganization Events” below) for each purchase contract being settled (regardless of the market price of the Common Stock on the date of early settlement), subject to adjustment under the circumstances described under “—Anti-dilution Adjustments” below. The Company will cause, no later than the second business day after the applicable early settlement date, (1) the shares of Common Stock to be issued and (2) the related RSNs of each series or applicable ownership interests in the Treasury portfolio or Treasury

securities, as the case may be, underlying the Equity Units and securing such purchase contracts to be released from the pledge under the purchase contract and pledge agreement and delivered to the purchase contract agent for delivery to the holder. Upon early settlement, the holder will be entitled to receive any accrued and unpaid contract adjustment payments (including any accrued and unpaid deferred contract adjustment payments and compounded contract adjustment payments thereon) to, but excluding, the contract adjustment payment date immediately preceding the early settlement date. The holder’s right to receive future contract adjustment payments will also terminate.

If the purchase contract agent receives a completed “Election to Settle Early” form (along with the Corporate Unit or Treasury Unit certificate, if they are in certificated form) and payment of $50 for each purchase contract being settled (and, if required, an amount equal to the contract adjustment payments payable on the next contract adjustment payment date) prior to 4:00 p.m., New York City time, on any business day and all conditions to early settlement have been satisfied, then that day will be considered the early settlement date. If the purchase contract agent receives the foregoing at or after 4:00 p.m., New York City time, on any business day or at any time on a day that is not a business day, then the next business day will be considered the early settlement date.

Early Settlement Upon a Fundamental Change

If a “fundamental change” (as defined below) occurs prior to the 30th scheduled trading day preceding the purchase contract settlement date, then, following the fundamental change, each holder of a purchase contract, subject to certain conditions described herein, will have the right to accelerate and settle the purchase contract early on the fundamental change early settlement date (defined below) at the settlement rate determined as if the applicable market value were determined, for such purpose, based on the market value averaging period starting on the 23rd scheduled trading day prior to the fundamental change early settlement date and ending on the third scheduled trading day immediately preceding the fundamental change early settlement date, plus an additional make-whole amount of shares (such additional make-whole amount of shares being hereafter referred to as the “make-whole shares”).

This right is referred to as the “fundamental change early settlement right.” If 20 trading days for the Common Stock have not occurred during the deemed market value averaging period referred to in the preceding paragraph, all remaining trading days will be deemed to occur on the third scheduled trading day immediately prior to the fundamental change early settlement date and the VWAP of the Common Stock for each of the remaining trading days will be the VWAP of the Common Stock on that third scheduled trading day or, if such day is not a trading day, the closing price as of such day.

The Company will provide each of the holders with a notice of the completion of a fundamental change within four scheduled trading days after the effective date of a fundamental change. The notice will specify (1) a date (subject to postponement as described below, the “fundamental change early settlement date”), which will be at least 26 scheduled trading days after the date of the notice and one business day prior to the purchase contract settlement date, on which date the Company will deliver shares of Common Stock to holders who exercise the fundamental change early settlement right, (2) the date by which holders must exercise the fundamental change early settlement right, which will be no earlier than the second scheduled trading day before the fundamental change early settlement date, (3) the first scheduled trading day of the deemed market value averaging period; which will be the 23rd scheduled trading day prior to the fundamental change early settlement date, the reference price, the threshold appreciation price and the fixed settlement rates, (4) the amount and kind (per share of Common Stock) of the cash, securities and other

consideration receivable by the holder upon settlement and (5) the amount of accrued and unpaid contract adjustment payments (including any deferred contract adjustment payments and compounded contract adjustment payments thereon), if any, that will be paid upon settlement to holders exercising the fundamental change early settlement right. To exercise the fundamental change early settlement right, you must deliver to the purchase contract agent at the corporate trust office of the purchase contract agent or its agent, in each case, in Hartford, Connecticut during the period beginning on the date the Company delivers notice that a fundamental change has occurred and ending at 4:00 p.m., New York City time, on the second scheduled trading day immediately preceding the fundamental change early settlement date (such period, subject to extension as described below, the “fundamental change exercise period”), the certificate evidencing your Corporate Units or Treasury Units if they are held in certificated form, and payment of $50 for each purchase contract being settled in immediately available funds.

A “fundamental change” will be deemed to have occurred if any of the following occurs:

(1)     a “person” or “group” within the meaning of Section 13(d) of the Exchange Act, as in effect on the initial issue date of the Corporate Units, has become the direct or indirect “beneficial owner,” as defined in Rule 13d-3 under the Exchange Act, of shares of Common Stock representing more than 50% of the voting power of the Common Stock;

(2)    (A) the Company is involved in a consolidation with or merger into any other person, or any merger of another person into the Company, or any other similar transaction or series of related transactions (other than a merger, consolidation or similar transaction that does not result in the conversion or exchange of outstanding shares of Common Stock), in each case, in which 90% or more of the outstanding shares of Common Stock are exchanged for or converted into cash, securities or other property, greater than 10% of the value of which consists of cash, securities or other property that is not (or will not be upon or immediately following the effectiveness of such consolidation, merger or other transaction) common stock listed on the New York Stock Exchange, the Nasdaq Global Select Market or the Nasdaq Global Market (or any of their respective successors) or (B) the consummation of any sale, lease or other transfer in one transaction or a series of related transactions of all or substantially all of the Company’s consolidated assets to any person other than one of the Company’s subsidiaries;

(3)     the Common Stock ceases to be listed on at least one of the New York Stock Exchange, the Nasdaq Global Select Market and the Nasdaq Global Market (or any of their respective successors) or the announcement by any of such exchanges on which the Common Stock is then listed or admitted for trading that the Common Stock will no longer be so listed or admitted for trading, unless the Common Stock has been accepted for listing or admitted for trading on another of such exchanges; or

(4)     the Company’s stockholders approve the Company’s liquidation, dissolution or termination;

provided that a transaction or event or series of related transactions that constitute a fundamental change pursuant to both clauses (1) and (2) above will be deemed to constitute a fundamental change solely pursuant to clause (2) of this definition of “fundamental change.”

If you exercise the fundamental change early settlement right, the Company will deliver to you on the fundamental change early settlement date for each purchase contract with respect to which you have elected fundamental change early settlement, a number of shares (or exchange property units, if applicable) equal to the settlement rate described above plus the additional make-whole

shares. In addition, on the fundamental change early settlement date, the Company will pay you the amount of any accrued and unpaid contract adjustment payments (including any deferred contract adjustment payments and compounded contract adjustment payments thereon) to, but excluding, the fundamental change early settlement date, unless the date on which the fundamental change early settlement right is exercised occurs following any record date and prior to the related scheduled contract adjustment payment date, and the Company is not deferring the related contract adjustment payment, in which case the Company will instead pay all accrued and unpaid contract adjustment payments to the holder as of such record date. You will also receive on the fundamental change early settlement date the RSNs of each series or the applicable ownership interest in the Treasury portfolio or Treasury securities underlying the Corporate Units or Treasury Units, as the case may be, with respect to which you are effecting a fundamental change early settlement, which, in each case, shall have been released from the pledge under the purchase contract and pledge agreement. If you do not elect to exercise your fundamental change early settlement right, your Corporate Units or Treasury Units will remain outstanding and will be subject to normal settlement on the purchase contract settlement date.

The Company has agreed that, if required under the United States federal securities laws, the Company will use its commercially reasonable efforts to (1) have in effect throughout the fundamental change exercise period a registration statement covering the Common Stock and other securities, if any, to be delivered in respect of the purchase contracts being settled and (2) provide a prospectus in connection therewith, in each case in a form that may be used in connection with the fundamental change early settlement (it being understood that for so long as there is a material business transaction or development that has not yet been publicly disclosed (but in no event for a period longer than 90 days), the Company will not be required to file such registration statement or provide such a prospectus, and the fundamental change early settlement right will not be available, until the Company has publicly disclosed such transaction or development; provided that the Company will use commercially reasonable efforts to make such disclosure as soon as it is commercially reasonable to do so). In the event that a holder seeks to exercise its fundamental change early settlement right and a registration statement is required to be effective in connection with the exercise of such right but no such registration statement is then effective or a blackout period is continuing, the holder’s exercise of such right will be void unless and until such a registration statement is effective and no blackout period is continuing. The fundamental change exercise period will be extended by the number of days during such period on which no such registration statement is effective or a blackout period is continuing (provided that the fundamental change exercise period will not be extended beyond the third scheduled trading day preceding the purchase contract settlement date) and the fundamental change early settlement date will be postponed to the third business day following the end of the fundamental change exercise period. The Company will provide each of the holders with a notice of any such extension and postponement at least 23 scheduled trading days prior to any such extension or postponement.

Unless the Treasury portfolio has replaced the RSNs as a component of the Corporate Units as result of a successful optional remarketing, holders of Corporate Units may exercise the fundamental change early settlement right only in integral multiples of 40 Corporate Units. If the Treasury portfolio has replaced the RSNs as a component of Corporate Units, holders of the Corporate Units may exercise the fundamental change early settlement right only in integral multiples of 160,000 Corporate Units.

A holder of Treasury Units may exercise the fundamental change early settlement right only in integral multiples of 20 Treasury Units.

Calculation of Make-Whole Shares. The number of make-whole shares per purchase contract applicable to a fundamental change early settlement will be determined by the Company or its agent by reference to the table below, based on the date on which the fundamental change occurs or becomes effective (the “effective date”) and the “stock price” in the fundamental change, which will be:

•    in the case of a fundamental change described in clause (2) above where the holders of the Common Stock receive only cash in the fundamental change, the cash amount paid per share of Common Stock; or

•    otherwise, the average of the closing prices of the Common Stock over the 20 trading-day period ending on the trading day immediately preceding the effective date of the fundamental change.

	Stock Price
Effective Date	$20.00	$35.00	$50.00	$65.00	$80.00	$93.15	$105.00	$116.44	$130.00	$145.00	$160.00	$175.00	$200.00
November 6, 2025	0.3129	0.1645	0.1089	0.0744	0.0375	0.0000	0.0300	0.0562	0.0434	0.0370	0.0333	0.0303	0.0259
December 15, 2026	0.1987	0.1063	0.0713	0.0501	0.0235	0.0000	0.0177	0.0423	0.0299	0.0251	0.0225	0.0204	0.0173
December 15, 2027	0.0974	0.0532	0.0361	0.0265	0.0126	0.0000	0.0080	0.0277	0.0159	0.0131	0.0117	0.0105	0.0089
December 15, 2028	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000	0.0000

The stock prices set forth in the second row of the table (i.e., the column headers) will be adjusted upon the occurrence of certain events requiring anti-dilution adjustments to the fixed settlement rates in a manner inversely proportional to the adjustments to the fixed settlement rates.

Each of the make-whole share amounts in the table will be subject to adjustment in the same manner and at the same time as the fixed settlement rates as set forth under “—Anti-dilution Adjustments.”

The exact stock price and effective date applicable to a fundamental change may not be set forth on the table, in which case:

•    if the stock price is between two stock prices on the table or the effective date is between two effective dates on the table, the amount of make-whole shares will be determined by straight line interpolation between the make-whole share amounts set forth for the higher and lower stock prices and the two effective dates based on a 365-day year, as applicable;

•    if the stock price is in excess of $200.00 per share (subject to adjustment in the same manner as the stock prices set forth in the second row of the table as described above), then the make-whole share amount will be zero; and

•    if the stock price is less than $20.00 per share (subject to adjustment in the same manner as the stock prices set forth in the second row of the table as described above) (the “minimum stock price”), then the make-whole share amount will be determined as if the stock price equaled the minimum stock price, using straight line interpolation, as described above, if the effective date is between two effective dates on the table.

Notice to Settle with Cash

Unless a termination event has occurred, a holder effects an early settlement or a fundamental change early settlement with respect to the underlying purchase contract, or a successful remarketing has occurred, a holder of Corporate Units may settle the related purchase contract with separate cash by delivering the Corporate Unit certificate, if in certificated form, to the purchase contract agent at the corporate trust office of the purchase contract agent or its agent, in each case, in Hartford, Connecticut with the completed “Notice to Settle with Cash” form at any time on or after the date the Company gives notice of a final remarketing and prior to 4:00 p.m., New York City time, on the second business day immediately preceding the first day of the final remarketing period or, if there has been a failed final remarketing, on the second business day immediately preceding the purchase contract settlement date. Holders of Corporate Units may only cash-settle Corporate Units in integral multiples of 40 Corporate Units.

The holder must also deliver to the securities intermediary the required cash payment in immediately available funds. Such payment must be delivered prior to 4:00 p.m., New York City time, on the first business day immediately preceding the final remarketing period or, if there has been a failed remarketing, on the first business day immediately preceding the purchase contract settlement date.

Upon receipt of the cash payment, the related RSN of each series will be released from the pledge arrangement and transferred to the purchase contract agent for distribution to the holder of the related Corporate Units. The holder of the Corporate Units will then receive the applicable number of shares of Common Stock on the purchase contract settlement date.

If a holder of Corporate Units that has given notice of its election to settle with cash fails to deliver the cash by the applicable time and date specified above, such holder shall be deemed to have consented to the disposition of its RSNs in the final remarketing or to have exercised its put right (as described under “—Remarketing” above), in each case, as applicable.

Any cash received by the collateral agent upon cash settlement may, upon the Company’s written direction, be invested in permitted investments, as defined in the purchase contract and pledge agreement, and the portion of the proceeds equal to the aggregate purchase price of all purchase contracts of such holders will be paid to the Company on the purchase contract settlement date. Any excess funds received by the collateral agent in respect of permitted investments over the aggregate purchase price remitted to the Company in satisfaction of the obligations of the holders under the purchase contracts will be distributed to the purchase contract agent for payment to the holders who settled with cash.

Contract Adjustment Payments

Contract adjustment payments in respect of Corporate Units and Treasury Units will be fixed at a rate per year of 2.975% of the stated amount of $50 per purchase contract. Contract adjustment payments payable for any period will be computed on the basis of a 360-day year of twelve 30-day months. Contract adjustment payments have accrued from the date of issuance of the purchase contracts and are payable quarterly in arrears on March 15, June 15, September 15 and December 15 of each year, commencing on March 15, 2026.

Contract adjustment payments are payable to the holders of purchase contracts as they appear on the books and records of the purchase contract agent at the close of business on the relevant record dates, which will be the 15th day of the calendar month immediately preceding the calendar month in

which the relevant payment date falls (or, if such day is not a business day, the next preceding business day) or if the Corporate Units or Treasury Units, as applicable, are held in book-entry form, the “record date” will be the business day immediately preceding the applicable payment date. These distributions will be paid through the purchase contract agent, which will hold amounts received in respect of the contract adjustment payments for the benefit of the holders of the purchase contracts relating to the Equity Units.

If any date on which contract adjustment payments are to be made on the purchase contracts related to the Corporate Units or Treasury Units is not a business day, then payment of the contract adjustment payments payable on that date will be made on the next succeeding day that is a business day, and no interest or payment will be paid in respect of the delay.

For the avoidance of doubt, subject to the Company’s right to defer contract adjustment payments, all record holders of purchase contracts on any record date will be entitled to receive the full contract adjustment payment due on the related contract adjustment payment date regardless of whether the holder of such purchase contract elects to settle such purchase contract early (whether at its option or in connection with a fundamental change) following such record date.

The Company’s obligations with respect to contract adjustment payments are subordinated and junior in right of payment to the Company’s obligations under any of the Company’s Senior Indebtedness (as defined under “Description of the Junior Subordinated Notes—Subordination” above) and rank junior to the RSNs.

The Company may, at its option and upon prior written notice to the purchase contract agent, defer all or part of the contract adjustment payments, but not beyond the purchase contract settlement date (or, with respect to an early settlement upon a fundamental change, not beyond the fundamental change early settlement date or, with respect to an early settlement other than upon a fundamental change, not beyond the contract adjustment payment date immediately preceding the early settlement date).

Deferred contract adjustment payments will accrue additional contract adjustment payments at the rate equal to 7.125% per annum (which is equal to the rate of total distributions on the Corporate Units), compounded on each contract adjustment payment date, to, but excluding, the contract adjustment payment date on which such deferred contract adjustment payments are paid. The additional contract adjustment payments that accrue on deferred contract adjustment payments are referred to as “compounded contract adjustment payments.” The Company may pay any such deferred contract adjustment payments (including compounded contract adjustment payments thereon) on any scheduled contract adjustment payment date; provided that in order to pay deferred contract adjustment payments on any scheduled contract adjustment payment date other than the purchase contract settlement date, the Company must deliver written notice thereof to holders of the Equity Units and the purchase contract agent on or before the relevant record date. If the purchase contracts are terminated (upon the occurrence of certain events of bankruptcy, insolvency or similar reorganization with respect to the Company), the right to receive contract adjustment payments and deferred contract adjustment payments (including compounded contract adjustment payments thereon) will also terminate.

If the Company exercises its option to defer the payment of contract adjustment payments, then, until the deferred contract adjustment payments (including compounded contract adjustment payments thereon) have been paid, it will not (1) declare or pay any dividends on, or make any distributions on, or redeem, purchase or acquire, or make a liquidation payment with respect to, any

shares of the Company’s capital stock, (2) make any payment of principal of, or interest or premium, if any, on, or repay, repurchase or redeem any of the Company’s debt securities that rank on parity with, or junior to, the contract adjustment payments, or (3) make any guarantee payments under any guarantee by the Company of securities of any of its subsidiaries if the Company’s guarantee ranks on parity with, or junior to, the contract adjustment payments.

The restrictions listed above do not apply to:

(a)    purchases, redemptions or other acquisitions of the Company’s capital stock in connection with any employment contract, benefit plan or other similar arrangement with or for the benefit of employees, officers, directors, agents or consultants or a stock purchase or dividend reinvestment plan, or the satisfaction of the Company’s obligations pursuant to any contract or security outstanding on the date that the contract adjustment payment is deferred requiring the Company to purchase, redeem or acquire the Company’s capital stock;

(b)    any payment, repayment, redemption, purchase, acquisition or declaration of dividends described in clause (1) above as a result of a reclassification of the Company’s capital stock, or the exchange or conversion of all or a portion of one class or series of the Company’s capital stock, for another class or series of the Company’s capital stock;

(c)    the purchase of fractional interests in shares of the Company’s capital stock pursuant to the conversion or exchange provisions of the Company’s capital stock or the security being converted or exchanged, or in connection with the settlement of stock purchase contracts outstanding on the date that the contract adjustment payment is deferred;

(d)    dividends or distributions paid or made in the Company’s capital stock (or rights to acquire the Company’s capital stock), or repurchases, redemptions or acquisitions of capital stock in connection with the issuance or exchange of capital stock (or of securities convertible into or exchangeable for shares of the Company’s capital stock) and distributions in connection with the settlement of stock purchase contracts outstanding on the date that the contract adjustment payment is deferred;

(e)    redemptions, exchanges or repurchases of, or with respect to, any rights outstanding under a stockholder rights plan outstanding on the date that the contract adjustment payment is deferred or the declaration or payment thereunder of a dividend or distribution of or with respect to rights in the future;

(f)    payments on any trust preferred securities, subordinated notes or junior subordinated notes, or any guarantees of any of the foregoing, in each case, that rank equal in right of payment to the contract adjustment payments, so long as the amount of payments made on account of such securities or guarantees and the purchase contracts is paid on all such securities and guarantees and the purchase contracts then outstanding on a pro rata basis in proportion to the full payment to which each series of such securities, guarantees or purchase contracts is then entitled if paid in full; provided that, for the avoidance of doubt, the Company will not be permitted under the purchase contract and pledge agreement to make contract adjustment payments in part; or

(g)    any payment of deferred interest or principal on, or repayment, redemption or repurchase of, parity or junior securities that, if not made, would cause the Company to breach the terms of the instrument governing such parity or junior securities.

Anti-dilution Adjustments

Each fixed settlement rate will be subject to the following adjustments:

(1)     Stock Dividends. If the Company pays or makes a dividend or other distribution on the Common Stock in Common Stock, each fixed settlement rate in effect at the opening of business on the day following the date fixed for the determination of stockholders entitled to receive such dividend or other distribution will be increased by dividing:

•    each fixed settlement rate by

•    a fraction, the numerator of which will be the number of shares of Common Stock outstanding at the close of business on the date fixed for such determination and the denominator will be the sum of such number of shares and the total number of shares constituting the dividend or other distribution.

If any dividend or distribution in this paragraph (1) is declared but not so paid or made, the new fixed settlement rates shall be readjusted, on the date that the Company’s board of directors determines not to pay or make such dividend or distribution, to the fixed settlement rates that would then be in effect if such dividend or distribution had not been declared.

(2)    Stock Purchase Rights. If the Company issues to all or substantially all holders of the Common Stock rights, options, warrants or other securities (other than pursuant to a dividend reinvestment, share purchase or similar plan) entitling them to subscribe for or purchase shares of Common Stock for a period expiring within 45 days from the date of issuance of such rights, options, warrants or other securities at a price per share of Common Stock less than the current market price (as defined below) calculated as of the date fixed for the determination of stockholders entitled to receive such rights, options, warrants or other securities, each fixed settlement rate in effect at the opening of business on the day following the date fixed for such determination will be increased by dividing:

•    each fixed settlement rate by

•    a fraction, the numerator of which will be the number of shares of Common Stock outstanding at the close of business on the date fixed for such determination plus the number of shares of Common Stock which the aggregate consideration expected to be received by the Company upon the exercise of such rights, options, warrants or other securities would purchase at such current market price and the denominator of which will be the number of shares of Common Stock outstanding at the close of business on the date fixed for such determination plus the number of shares of Common Stock so offered for subscription or purchase.

If any right, option, warrant or other security described in this paragraph (2) is not exercised or converted prior to the expiration of the exercisability or convertibility thereof (and as a result no additional shares of Common Stock are delivered or issued pursuant to such right, option, or warrant or other security), the new fixed settlement rates shall be readjusted, as of the date of such expiration, to the fixed settlement rates that would then be in effect had the increase with respect to the issuance of such rights, options, warrants or other securities been made on the basis of delivery or issuance of only the number of shares of Common Stock actually delivered.

For purposes of this paragraph (2), in determining whether any rights, options, warrants or other securities entitle the holders to subscribe for or purchase shares of Common Stock at a price per

share of Common Stock less than the current market price on the date fixed for the determination of stockholders entitled to receive such rights, options, warrants or other securities, and in determining the aggregate price payable to exercise such rights, options, warrants or other securities, there shall be taken into account any consideration received by the Company for such rights, options, warrants or other securities and any amount payable on exercise or conversion thereof, the value of such consideration, if other than cash, to be determined in good faith by the Company’s board of directors.

(3)     Stock Splits; Reverse Splits; and Combinations. If outstanding shares of Common Stock shall be subdivided, split or reclassified into a greater number of shares of Common Stock, each fixed settlement rate in effect at the opening of business on the day following the day upon which such subdivision, split or reclassification becomes effective shall be proportionately increased, and, conversely, in case outstanding shares of Common Stock shall each be combined or reclassified into a smaller number of shares of Common Stock, each fixed settlement rate in effect at the opening of business on the day following the day upon which such combination or reclassification becomes effective shall be proportionately reduced.

(4)     Debt, Asset or Security Distributions. If the Company, by dividend or otherwise, distributes to all or substantially all holders of the Common Stock evidences of the Company’s indebtedness, assets or securities or any rights, options or warrants (or similar securities) to subscribe for, purchase or otherwise acquire evidences of the Company’s indebtedness, other assets or property of the Company or other securities (but excluding any rights, options, warrants or other securities referred to in paragraph (2) above, any dividend or distribution paid exclusively in cash referred to in paragraph (5) below (in each case, whether or not an adjustment to the fixed settlement rates is required by such paragraph) and any dividend paid in shares of capital stock of any class or series, or similar equity interests, of or relating to a subsidiary or other business unit of the Company in the case of a spin-off referred to below, or dividends or distributions referred to in paragraph (1) above), each fixed settlement rate in effect immediately prior to the close of business on the date fixed for the determination of stockholders entitled to receive such dividend or distribution shall be increased by dividing:

•    each fixed settlement rate by

•    a fraction, the numerator of which shall be the current market price of the Common Stock calculated as of the date fixed for such determination less the then fair market value (as determined in good faith by the Company’s board of directors) of the portion of the assets, securities or evidences of indebtedness so distributed applicable to one share of Common Stock and the denominator of which shall be such current market price.

Notwithstanding the foregoing, if the fair market value (as determined in good faith by the Company’s board of directors) of the portion of the assets, securities or evidences of indebtedness so distributed applicable to one share of Common Stock exceeds the current market price of the Common Stock on the date fixed for the determination of stockholders entitled to receive such distribution, in lieu of the foregoing increase, each holder of a purchase contract shall receive, for each purchase contract, at the same time and upon the same terms as holders of shares of Common Stock, the amount of such distributed assets, securities or evidences of indebtedness that such holder would have received if such holder owned a number of shares of Common Stock equal to the maximum settlement rate on the record date for such dividend or distribution.

In the case of the payment of a dividend or other distribution on the Common Stock of shares of capital stock of any class or series, or similar equity interests, of or relating to a subsidiary or other

business unit of the Company, which are or will, upon issuance, be listed on a United States securities exchange or quotation system, which is referred to as a “spin-off,” each fixed settlement rate in effect immediately before the close of business on the date fixed for determination of stockholders entitled to receive that distribution will be increased by dividing:

•    each fixed settlement rate by

•    a fraction, the numerator of which is the current market price of the Common Stock and the denominator of which is such current market price plus the fair market value, determined as described below, of those shares of capital stock or similar equity interests so distributed applicable to one share of Common Stock.

The adjustment to the fixed settlement rate under this paragraph (4) will occur on:

•    the 10th trading day from and including the effective date of the spin-off; or

•    if the spin-off is effected simultaneously with an initial public offering of the securities being distributed in the spin-off and the ex date for the spin-off occurs on or before the date that the initial public offering price of the securities being distributed in the spin-off is determined, the issue date of the securities being offered in such initial public offering.

For purposes of this paragraph (4), “initial public offering” means the first time securities of the same class or type as the securities being distributed in the spin-off are offered to the public for cash.

Subject to the immediately following paragraph, the fair market value of the securities to be distributed to holders of the Common Stock means the average of the closing sale prices of those securities on the principal United States securities exchange or quotation system on which such securities are listed or quoted at that time over the first 10 trading days following the effective date of the spin-off. Also, for purposes of such a spin-off, the current market price of the Common Stock means the average of the closing sale prices of the Common Stock on the principal United States securities exchange or quotation system on which the Common Stock is listed or quoted at that time over the first 10 trading days following the effective date of the spin-off.

If, however, an initial public offering of the securities being distributed in the spin-off is to be effected simultaneously with the spin-off and the ex date for the spin-off occurs on or before the date that the initial public offering price of the securities being distributed in the spin-off is determined, the fair market value of the securities being distributed in the spin-off means the initial public offering price, while the current market price of the Common Stock means the closing sale price of the Common Stock on the principal United States securities exchange or quotation system on which the Common Stock is listed or quoted at that time on the trading day on which the initial public offering price of the securities being distributed in the spin-off is determined.

If any dividend or distribution described in this paragraph (4) is declared but not so paid or made, the new fixed settlement rates shall be readjusted, as of the date the Company’s board of directors determines not to pay or make such dividend or distribution, to the fixed settlement rates that would then be in effect if such dividend or distribution had not been declared.

(5)     Cash Distributions. If the Company, by dividend or otherwise, makes distributions to all or substantially all holders of the Common Stock exclusively in cash during any quarterly period

in an amount that exceeds $0.74 per share per quarter in the case of a regular quarterly dividend (such per share amount being referred to as the “reference dividend”), then immediately after the close of business on the date fixed for determination of the stockholders entitled to receive such distribution, each fixed settlement rate in effect immediately prior to the close of business on such date will be increased by dividing:

•    each fixed settlement rate by

•    a fraction, the numerator of which will be equal to the current market price on the date fixed for such determination less the amount, if any, by which the per share amount of the distribution exceeds the reference dividend and the denominator of which will be equal to such current market price.

Notwithstanding the foregoing, if (x) the amount by which the per share amount of the cash distribution exceeds the reference dividend exceeds (y) the current market price of the Common Stock on the date fixed for the determination of stockholders entitled to receive such distribution, in lieu of the foregoing increase, each holder of a purchase contract shall receive, for each purchase contract, at the same time and upon the same terms as holders of shares of Common Stock, the amount of distributed cash that such holder would have received if such holder owned a number of shares of Common Stock equal to the maximum settlement rate on the record date for such cash dividend or distribution.

The reference dividend will be subject to an inversely proportional adjustment whenever each fixed settlement rate is adjusted, other than pursuant to this paragraph (5). For the avoidance of doubt, the reference dividend will be zero in the case of a cash dividend that is not a regular quarterly dividend.

If any dividend or distribution described in this paragraph (5) is declared but not so paid or made, the new fixed settlement rate shall be readjusted, as of the date the Company’s board of directors determines not to pay or make such dividend or distribution, to the fixed settlement rate that would then be in effect if such dividend or distribution had not been declared.

(6) Tender and Exchange Offers. In the case that a tender offer or exchange offer made by the Company or any subsidiary for all or any portion of the Common Stock shall expire and such tender or exchange offer (as amended through the expiration thereof) requires the payment to stockholders (based on the acceptance (up to any maximum specified in the terms of the tender offer or exchange offer) of purchased shares) of an aggregate consideration having a fair market value per share of Common Stock that exceeds the closing price of the Common Stock on the trading day next succeeding the last date on which tenders or exchanges may be made pursuant to such tender offer or exchange offer, then, immediately prior to the opening of business on the day after the date of the last time (which is referred to as the “expiration time”) tenders or exchanges could have been made pursuant to such tender offer or exchange offer (as amended through the expiration thereof), each fixed settlement rate in effect immediately prior to the close of business on the date of the expiration time will be increased by dividing:

•    each fixed settlement rate by

•    a fraction (1) the numerator of which will be equal to (a) the product of (i) the current market price on the date of the expiration time and (ii) the number of shares of Common Stock outstanding (including any purchased shares (as defined below)) on the date of the expiration time

less (b) the amount of cash plus the fair market value of the aggregate consideration payable to stockholders pursuant to the tender offer or exchange offer (assuming the acceptance by the Company of purchased shares), and (2) the denominator of which will be equal to the product of (x) the current market price on the date of the expiration time and (y) the result of (i) the number of shares of Common Stock outstanding (including any purchased shares) on the date of the expiration time less (ii) the number of all shares validly tendered, not withdrawn and accepted for payment on the date of the expiration time (such actually validly tendered or exchanged shares, up to any maximum acceptance amount specified by the Company in the terms of the tender offer or exchange offer, being referred to as the “purchased shares”).

For purposes of paragraphs (2) through (6) above (except as otherwise expressly provided therein with respect to spin-offs) above, the “current market price” per share of Common Stock or any other security on any day means the average VWAP of the Common Stock or such other security on the principal United States securities exchange or quotation system on which the Common Stock or such other security, as applicable, is listed or quoted at that time for the 10 consecutive trading days preceding the earlier of the trading day preceding the day in question and the trading day before the “ex date” with respect to the issuance or distribution requiring such computation. For purposes of paragraph (6) above, the last day of the measurement period shall be the trading day next succeeding the last date on which tenders or exchanges may be made pursuant to the relevant tender offer or exchange offer. The term “ex date,” when used with respect to any issuance or distribution on the Common Stock or any other security, means the first date on which the Common Stock or such other security, as applicable, trades, regular way, on the principal United States securities exchange or quotation system on which the Common Stock or such other security, as applicable, is listed or quoted at that time, without the right to receive the issuance or distribution.

The Company currently does not have a stockholders rights plan with respect to the Common Stock. To the extent that the Company has a stockholders rights plan involving the issuance of share purchase rights or other similar rights to all or substantially all holders of the Common Stock in effect upon settlement of a purchase contract, you will receive, in addition to the Common Stock issuable upon settlement of any purchase contract, the related rights for the Common Stock under the stockholders rights plan, unless, prior to any settlement of a purchase contract, the rights have separated from the Common Stock, in which case each fixed settlement rate will be adjusted at the time of separation as if the Company made a distribution to all holders of the Common Stock as described in paragraph (4) above, subject to readjustment in the event of the expiration, termination or redemption of the rights under the stockholder rights plan.

In addition, the Company may increase the fixed settlement rates if the Company’s board of directors deems it advisable to avoid or diminish any income tax to holders of the Common Stock resulting from any dividend or distribution of shares (or rights to acquire shares) or from any event treated as a dividend or distribution for income tax purposes or for any other reasons. The Company may only make such a discretionary adjustment if the Company makes the same proportionate adjustment to each fixed settlement rate.

Adjustments to the fixed settlement rates will be calculated to the nearest ten thousandth of a share. No adjustment to the fixed settlement rates will be required unless the adjustment would require an increase or decrease of at least one percent in one or both fixed settlement rates. If any adjustment is not required to be made because it would not change one or both fixed settlement rates by at least one percent, then the adjustment will be carried forward and taken into account in any subsequent adjustment. All anti-dilution adjustments will be made not later than each day of any

market value averaging period and the time at which the Company is otherwise required to determine the relevant settlement rate or amount of make-whole shares (if applicable) in connection with any settlement with respect to the purchase contracts.

No adjustment to the fixed settlement rates will be made if holders of Equity Units participate, as a result of holding the Equity Units and without having to settle the purchase contracts that form part of the Equity Units, in the transaction that would otherwise give rise to an adjustment as if they held a number of shares of Common Stock equal to the maximum settlement rate, at the same time and upon the same terms as the holders of Common Stock participate in the transaction.

The fixed settlement rates will not be adjusted (subject to the Company’s right to increase them if the Company’s board of directors deems it advisable as described in the third preceding paragraph):

•    upon the issuance of any shares of Common Stock pursuant to any present or future plan providing for the reinvestment of dividends or interest payable on the Company’s securities and the investment of additional optional amounts in shares of Common Stock under any plan;

•    upon the issuance of options, restricted stock or other awards in connection with any employment contract, executive compensation plan, benefit plan or other similar arrangement with or for the benefit of any one or more employees, officers, directors, consultants or independent contractors or the exercise of such options or other awards;

•    upon the issuance of any shares of Common Stock pursuant to any option, warrant, right or exercisable, exchangeable or convertible security outstanding as of the date the Equity Units were first issued;

•    for a change in the par value or no par value of the Common Stock; or

•    for accumulated and unpaid contract adjustment payments.

The Company will, as soon as practicable after the fixed settlement rate is adjusted, provide written notice of the adjustment to the holders of Equity Units and the purchase contract agent.

If an adjustment is made to the fixed settlement rates, an adjustment also will be made to the reference price and the threshold appreciation price on an inversely proportional basis solely to determine which of the clauses of the definition of settlement rate will be applicable to determine the settlement rate with respect to the purchase contract settlement date or any fundamental change early settlement date.

If any adjustment to the fixed settlement rates becomes effective, or any effective date, expiration time, ex date or record date for any stock split or reverse stock split, tender or exchange offer, issuance, dividend or distribution (relating to a required fixed settlement rate adjustment) occurs, during the period beginning on, and including, (i) the open of business on a first trading day of the 20 scheduled trading-day period during which the applicable market value is calculated or (ii) in the case of the optional early settlement or fundamental change early settlement, the relevant early settlement date or the date on which the fundamental change early settlement right is exercised and, in each case, ending on, and including, the date on which the Company delivers shares of Common Stock under the related purchase contract, the Company will make appropriate adjustments to the fixed settlement rates and/or the number of shares of Common Stock deliverable upon settlement with

respect to the purchase contract, in each case, consistent with the methodology used to determine the anti-dilution adjustments set forth above. If any adjustment to the fixed settlement rates becomes effective, or any effective date, expiration time, ex date or record date for any stock split or reverse stock split, tender or exchange offer, issuance, dividend or distribution (relating to a required fixed settlement rate adjustment) occurs, during the period used to determine the “stock price” or any other averaging period hereunder, the Company will make appropriate adjustments to the applicable prices, consistent with the methodology used to determine the anti-dilution adjustments set forth above.

Reorganization Events

The following events are defined as “reorganization events:”

•    any consolidation or merger of the Company with or into another person or of another person with or into the Company or a similar transaction (other than a consolidation, merger or similar transaction in which the Company is the continuing corporation and in which the shares of Common Stock outstanding immediately prior to the merger or consolidation are not exchanged for cash, securities or other property of the Company or another person);

•    any sale, transfer, lease or conveyance to another person of the property of the Company as an entirety or substantially as an entirety, as a result of which the shares of Common Stock are exchanged for cash, securities or other property;

•    any statutory exchange of Common Stock with another corporation (other than in connection with a merger or acquisition); and

•    any liquidation, dissolution or termination of the Company (other than as a result of or after the occurrence of a termination event described below under “—Termination”).

Following the effective date of a reorganization event, the settlement rate shall be determined by reference to the value of an exchange property unit, and the Company shall deliver, upon settlement of any purchase contract, a number of exchange property units equal to the number of shares of Common Stock that the Company would otherwise be required to deliver. An “exchange property unit” is the kind and amount of common stock, other securities, other property or assets (including cash or any combination thereof) receivable in such reorganization event (without any interest thereon, and without any right to dividends or distribution thereon which have a record date that is prior to the applicable settlement date) per share of Common Stock by a holder of Common Stock that is not a person with which the Company is consolidated or into which the Company is merged or which merged into the Company or to which such sale or transfer was made, as the case may be (any such person is referred to as a “constituent person”), or an affiliate of a constituent person, to the extent such reorganization event provides for different treatment of Common Stock held by the constituent person and/or the affiliates of the constituent person, on the one hand, and non-affiliates of a constituent person, on the other hand. In the event holders of the Common Stock (other than any constituent person or affiliate thereof) have the opportunity to elect the form of consideration to be received in such transaction, the exchange property unit that holders of the Corporate Units or Treasury Units are entitled to receive will be deemed to be (x) the weighted average of the types and amounts of consideration received by the holders of the Common Stock that affirmatively make an election or (y) if no holders of the Common Stock affirmatively make such an election, the types and amounts of consideration actually received by the holders of the Common Stock.

In the event of such a reorganization event, the person formed by such consolidation or merger or the person which acquires the Company’s assets shall execute and deliver to the purchase contract agent an agreement providing that the holder of each Equity Unit that remains outstanding after the reorganization event (if any) shall have the rights described in the preceding paragraph. Such supplemental agreement shall provide for adjustments to the amount of any securities constituting all or a portion of an exchange property unit and/or adjustments to the fixed settlement rates, which, for events subsequent to the effective date of such reorganization event, shall be as nearly equivalent as may be practicable to the adjustments provided for under “—Anti-dilution Adjustments” above. The provisions described in the preceding two paragraphs shall similarly apply to successive reorganization events.

In connection with any reorganization event, the Company will also adjust the reference dividend based on the number of shares of Common Stock comprising an exchange property unit and (if applicable) the value of any non-stock consideration comprising an exchange property unit. If an exchange property unit is composed solely of non-stock consideration, the reference dividend will be zero.

Termination

The purchase contract and pledge agreement provides that the purchase contracts and the obligations and rights of the Company and of the holders of Corporate Units and Treasury Units thereunder (including the holders’ obligation and right to purchase and receive shares of Common Stock and to receive accrued and unpaid contract adjustment payments, including deferred contract adjustment payments and compounded contract adjustment payments thereon) will immediately and automatically terminate upon the occurrence of a termination event (as defined below).

Upon any termination event, the Equity Units will represent the right to receive the RSNs underlying the undivided beneficial interest in the RSNs of each series, the applicable ownership interests in the Treasury portfolio or the Treasury securities, as the case may be, forming part of such Equity Units. Upon the occurrence of a termination event, the Company will promptly give the purchase contract agent, the collateral agent and the holders written notice of such termination event and the collateral agent will release the related interests in the RSNs, applicable ownership interests in the Treasury portfolio or Treasury securities, as the case may be, from the pledge arrangement and transfer such interests in the RSNs, applicable ownership interests in the Treasury portfolio or Treasury securities to the purchase contract agent for distribution to the holders of Corporate Units and Treasury Units. If a holder is entitled to receive RSNs in an aggregate principal amount that is not an integral multiple of $1,000 per series, the purchase contract agent will request that the Company issue RSNs in denominations of $25 and integral multiples thereof in exchange for RSNs in denominations of $1,000 or integral multiples thereof. In addition, if any holder is entitled to receive, with respect to its applicable ownership interests in the Treasury portfolio or its pledged Treasury securities, any securities having a principal amount at maturity of less than $1,000, the purchase contract agent will dispose of such securities for cash and pay the cash received to the holder in lieu of such applicable ownership in the Treasury portfolio or such Treasury securities. Upon any termination event, however, such release and distribution may be subject to a delay. In the event that the Company becomes the subject of a case under the United States Bankruptcy Code, such delay may occur as a result of the automatic stay under the United States Bankruptcy Code and continue until such automatic stay has been lifted. Moreover, claims arising out of the RSNs will be subject to the equitable jurisdiction and powers of the bankruptcy court.

A “termination event” means any of the following events with respect to the Company:

(1)     at any time on or prior to the purchase contract settlement date, a decree or order by a court having jurisdiction in the premises shall have been entered adjudicating the Company bankrupt or insolvent, or approving as properly filed a petition seeking reorganization arrangement, adjustment or composition of or in respect of the Company under the United States Bankruptcy Code or any other similar applicable federal or state law and such decree or order shall have been entered more than 90 days prior to the purchase contract settlement date and shall have continued undischarged and unstayed for a period of 90 consecutive days;

(2) at any time on or prior to the purchase contract settlement date, a decree or order of a court having jurisdiction in the premises shall have been entered for the appointment of a receiver, liquidator, trustee, assignee, sequestrator or other similar official in bankruptcy or insolvency of the Company or of all or any substantial part of the Company’s property, or for the winding up or liquidation of the Company’s affairs, and such decree or order shall have been entered more than 90 days prior to the purchase contract settlement date and shall have continued undischarged and unstayed for a period of 90 consecutive days; or

(3) at any time on or prior to the purchase contract settlement date, the Company shall institute proceedings to be adjudicated bankrupt or insolvent, or shall consent to the institution of bankruptcy or insolvency proceedings against it, or shall file a petition or answer or consent seeking reorganization under the United States Bankruptcy Code or any other similar applicable federal or state law, or shall consent to the filing of any such petition, or shall consent to the appointment of a receiver, liquidator, trustee, assignee, sequestrator or other similar official of the Company or of all or any substantial part of the Company’s property, or shall make an assignment for the benefit of creditors, or shall admit in writing its inability to pay its debts generally as they become due.

Pledged Securities and Pledge

The undivided beneficial ownership interests in each series of RSNs, or, following a successful optional remarketing, the applicable ownership interests in the portions of the Treasury portfolio described in the first and second bullets under “Remarketing—Optional Remarketing—Components of the Treasury Portfolio” above, that are a component of the Corporate Units or, if substituted, the beneficial ownership interest in the Treasury securities that are a component of the Treasury Units, collectively, the “pledged securities,” are or will be pledged to the collateral agent for the Company’s benefit pursuant to the purchase contract and pledge agreement to secure your obligation to purchase shares of Common Stock under the related purchase contracts. The rights of the holders of the Corporate Units and the Treasury Units with respect to the pledged securities are subject to the Company’s security interest therein. No holder of Corporate Units or Treasury Units is permitted to withdraw the pledged securities related to such Corporate Units or Treasury Units from the pledge arrangement except:

•    in the case of Corporate Units, to substitute a Treasury security for the related RSN of each series, as provided under “Description of the Equity Units—Creating Treasury Units by Substituting a Treasury Security for the RSNs;”

•    in the case of Treasury Units, to substitute an RSN of each series for the related Treasury security, as provided under “Description of the Equity Units—Recreating Corporate Units;” and

•    upon early settlement, settlement through the payment of separate cash or termination of the related purchase contracts.

Subject to the Company’s security interest and the terms of the purchase contract and pledge agreement, each holder of a Corporate Unit (unless the Treasury portfolio has replaced the RSNs as a component of the Corporate Unit) is entitled through the purchase contract agent and the collateral agent to all of the proportional rights and preferences of the related RSNs (including distribution, voting, redemption, repayment and liquidation rights). Each holder of Treasury Units and each holder of Corporate Units (if the Treasury portfolio has replaced the RSNs as a component of the Corporate Units) will retain beneficial ownership of the related Treasury securities or the applicable ownership interests in the Treasury portfolio, as applicable, pledged in respect of the related purchase contracts. The Company has no interest in the pledged securities other than the Company’s security interest.

Except as described in “Certain Provisions of the Purchase Contract and Pledge Agreement—General,” upon receipt of distributions on the pledged securities, the collateral agent will distribute such payments to the purchase contract agent, which in turn will distribute those payments to the holders in whose names the Corporate Units or the Treasury Units are registered at the close of business on the record date for the distribution.

Certain Provisions of the Purchase Contract and Pledge Agreement

The term “business day”, as used in this section, Certain Provisions of the Purchase Contract and Pledge Agreement, has the meaning ascribed to it under the caption “Description of the Equity Units” above.

General

In general, payments on the Corporate Units and the Treasury Units are payable, the purchase contracts will be settled and transfers of the Corporate Units and the Treasury Units are registrable at, the office of the purchase contract agent or its agent, in each case, in Hartford, Connecticut. In addition, if the Corporate Units or the Treasury Units do not remain in book-entry form, the Company will make payments on the Corporate Units and the Treasury Units by check mailed to the address of the person entitled thereto as shown on the security register or by a wire transfer to the account designated by the holder by a prior written notice at least five business days prior to the relevant payment date.

Shares of Common Stock will be delivered on the purchase contract settlement date (or earlier upon early settlement), or, if the purchase contracts have terminated, the related pledged securities will be delivered (subject to delays, including potentially as a result of the imposition of the automatic stay under the United States Bankruptcy Code, as described under “Description of the Purchase Contracts—Termination”) at the office of the purchase contract agent or its agent upon presentation and surrender of the applicable Corporate Unit or Treasury Unit certificate, if in certificated form.

If Corporate Units or Treasury Units are in certificated form and the holder fails to present and surrender the certificate evidencing the Corporate Units or the Treasury Units to the purchase contract agent on or prior to the purchase contract settlement date, the shares of Common Stock issuable upon settlement with respect to the related purchase contract will be registered in the name of the purchase contract agent or its nominee. The shares, together with any distributions, will be held by the purchase contract agent as agent for the benefit of the holder until the certificate is presented and surrendered or the holder provides satisfactory evidence that the certificate has been destroyed, lost or stolen, together with any indemnity and security that may be required by the purchase contract agent and the Company.

If the purchase contracts terminate prior to the purchase contract settlement date, the related pledged securities are transferred to the purchase contract agent for distribution to the holders and a holder fails to present and surrender the certificate evidencing the holder’s Corporate Units or Treasury Units, if in certificated form, to the purchase contract agent, the related pledged securities delivered to the purchase contract agent and payments on the pledged securities will be held by the purchase contract agent as agent for the benefit of the holder until the applicable certificate is presented, if in certificated form, or the holder provides the evidence and indemnity described above.

No service charge will be made for any registration of transfer or exchange of the Corporate Units or the Treasury Units, except for any tax or other governmental charge that may be imposed in connection therewith.

The purchase contract agent has no obligation to invest or to pay interest on any amounts it holds pending payment to any holder.

Modification

The purchase contract and pledge agreement contains provisions permitting the Company, the purchase contract agent and the collateral agent to modify the purchase contract and pledge agreement without the consent of the holders for any of the following purposes:

•    to evidence the succession of another person to the Company’s obligations;

•    to add to the covenants of the Company for the benefit of holders or to surrender any of the Company’s rights or powers under the purchase contract and pledge agreement;

•    to evidence and provide for the acceptance of appointment of a successor purchase contract agent or a successor collateral agent, securities intermediary or custodial agent;

•    to make provision with respect to the rights of holders pursuant to the requirements applicable to reorganization events; and

•    to cure any ambiguity or to correct or supplement any provisions that may be inconsistent with any other provision in the purchase contract and pledge agreement or to make such other provisions in regard to matters or questions arising under the purchase contract and pledge agreement that do not adversely affect the interests of any holders of Equity Units, it being understood that any amendments to conform the provisions of the purchase contract and pledge agreement to the description of such agreement, the Equity Units and the purchase contracts contained in the preliminary prospectus supplement for the Equity Units as supplemented and/or amended by the related pricing term sheet will be deemed not to adversely affect the interests of the holders.

The purchase contract and pledge agreement contains provisions allowing the Company, the purchase contract agent and the collateral agent, subject to certain limited exceptions, to modify the terms of the purchase contracts or the purchase contract and pledge agreement with the consent of the holders of not less than a majority of the outstanding Equity Units, with holders of Corporate Units and Treasury Units voting as a single class. However, no such modification may, without the consent of the holder of each outstanding purchase contract affected thereby:

•    subject to the Company’s right to defer contract adjustment payments, change any payment date;

•    impair the holders’ right to institute suit for the enforcement of a purchase contract or payment of any contract adjustment payments (including compounded contract adjustment payments);

•    except as required pursuant to any anti-dilution adjustment, reduce the number of shares of Common Stock purchasable under a purchase contract, increase the purchase price of the shares of Common Stock on settlement of any purchase contract, change the purchase contract settlement date or change the right to early settlement or fundamental change early settlement in a manner adverse to the holders or otherwise adversely affect the holder’s rights under any purchase contract, the purchase contract and pledge agreement or the remarketing agreement in any respect;

•    increase the amount or change the type of collateral required to be pledged to secure a holder’s obligations under the purchase contract and pledge agreement;

•    impair the right of the holder of any purchase contract to receive distributions on the collateral, or otherwise adversely affect the holder’s rights in or to such collateral;

•    reduce any contract adjustment payments or any deferred contract adjustment payments (including compounded contract adjustment payments) or change any place where, or the coin or currency in which, any contract adjustment payment is payable; or

•    reduce the percentage of the outstanding purchase contracts whose holders’ consent is required for the modification, amendment or waiver of the provisions of the purchase contracts and the purchase contract and pledge agreement.

However, if any amendment or proposal would adversely affect only the Corporate Units or only the Treasury Units, then only the affected class of holders will be entitled to vote on such amendment or proposal, and such amendment or proposal will not be effective except with the consent of the holders of not less than a majority of such class or, if referred to in the seven bullets above, each holder affected thereby.

No Consent to Assumption

Each holder of a Corporate Unit or a Treasury Unit is deemed under the terms of the purchase contract and pledge agreement, by the purchase of such Corporate Unit or Treasury Unit, to have expressly withheld any consent to the assumption under Section 365 of the United States Bankruptcy Code or otherwise of the related purchase contracts by the Company, the Company’s receiver, liquidator or trustee or person or entity performing similar functions in the event that the Company becomes a debtor under the United States Bankruptcy Code or other similar state or federal law providing for reorganization or liquidation.

Consolidation, Merger and Conveyance of Assets as an Entirety

The Company has agreed not to merge or consolidate with any other person or sell or convey all or substantially all of the Company’s assets to any person unless (i) either the Company is the continuing entity, or the successor entity (if other than the Company) is a corporation organized and existing under the laws of the United States of America or a State thereof or the District of Columbia and such corporation expressly assumes all of the Company’s responsibilities and liabilities under the purchase contracts, the Corporate Units, the Treasury Units, the purchase contract and pledge agreement, the remarketing agreement (if any) and the Senior Note Indenture by one or more supplemental agreements executed and delivered to the purchase contract agent, the collateral agent and the Senior Note Indenture Trustee by such corporation, and (ii) the Company or such successor corporation, as the case may be, will not, immediately after such merger or consolidation, or such sale or conveyance, be in default in the performance of any of its obligations or covenants under such agreements.

In case of any such consolidation, merger, sale or conveyance, and upon any such assumption by the successor corporation, such successor corporation shall succeed to and be substituted for the Company, with the same effect as if it had been named in the purchase contracts, the Corporate Units, the Treasury Units, the purchase contract and pledge agreement and the remarketing agreement (if any), and the Company shall be relieved of any further obligation under the purchase contracts, the Corporate Units, the Treasury Units, the purchase contract and pledge agreement and the remarketing agreement (if any).

Title

The Company, the purchase contract agent and the collateral agent may treat the registered owner of any Corporate Units or Treasury Units as the absolute owner of the Corporate Units or

Treasury Units for the purpose of making payment (subject to the record date provisions described above) and settling the related purchase contracts and for all other purposes.

Replacement of Equity Unit Certificates

In the event that physical certificates have been issued, any mutilated Corporate Unit or Treasury Unit certificate will be replaced by the Company at the expense of the holder upon surrender of the certificate to the purchase contract agent at the corporate trust office of the purchase contract agent or its agent, in each case, in Hartford, Connecticut. Corporate Unit or Treasury Unit certificates that become destroyed, lost or stolen will be replaced by the Company at the expense of the holder upon delivery to the Company and the purchase contract agent of evidence of their destruction, loss or theft satisfactory to the Company. In the case of a destroyed, lost or stolen Corporate Unit or Treasury Unit certificate, an indemnity and security satisfactory to the purchase contract agent and the Company may be required at the expense of the holder before a replacement certificate will be issued.

Notwithstanding the foregoing, the Company will not be obligated to issue any Corporate Unit or Treasury Unit certificates on or after the business day immediately preceding the purchase contract settlement date or the date on which the purchase contracts have terminated. The purchase contract and pledge agreement provides that, in lieu of the delivery of a replacement Corporate Unit or Treasury Unit certificate, the purchase contract agent, upon delivery of the evidence and indemnity and/or security described above, will, in the case of the purchase contract settlement date, deliver the shares of Common Stock issuable pursuant to the purchase contracts included in the Corporate Units or Treasury Units evidenced by the certificate, or, if the purchase contracts have terminated prior to the purchase contract settlement date, transfer the pledged securities included in the Corporate Units or Treasury Units evidenced by the certificate.

Governing Law

The purchase contracts and the purchase contract and pledge agreement are, and the remarketing agreement will be, governed by, and construed in accordance with, the laws of the State of New York (without regard to conflicts of laws principles thereof).

Information Concerning the Purchase Contract Agent

U.S. Bank Trust Company, National Association (or its successor) is the purchase contract agent. The purchase contract agent acts as the agent for the holders of Corporate Units and Treasury Units. The purchase contract agent is not obligated to take any discretionary action in connection with a default under the terms of the Corporate Units, the Treasury Units or the purchase contract and pledge agreement. All calculations and determinations of any make-whole shares, make-whole amounts, rates, market values and any adjustments to reference price or the threshold appreciation price shall be made by the Company or its agent based on their good faith calculations, and the purchase contract agent shall have no responsibility with respect thereto.

The purchase contract and pledge agreement contains provisions limiting the liability of the purchase contract agent. The purchase contract and pledge agreement also contains provisions under which the purchase contract agent may resign or be replaced. Such resignation or replacement will be effective upon the appointment of a successor.

In addition to serving as the purchase contract agent and collateral agent, as described below, U.S. Bank Trust Company, National Association serves as the custodial agent and securities intermediary under the purchase contract and pledge agreement for each series of RSNs.

Information Concerning the Collateral Agent

U.S. Bank Trust Company, National Association (or its successor) is the collateral agent. The collateral agent acts solely as the Company’s agent and does not assume any obligation or relationship of agency or trust for or with any of the holders of the Corporate Units and the Treasury Units except for the obligations owed by a pledgee of property to the owner thereof under the purchase contract and pledge agreement and applicable law.

The purchase contract and pledge agreement contains provisions limiting the liability of the collateral agent. The purchase contract and pledge agreement also contains provisions under which the collateral agent may resign or be replaced. Such resignation or replacement will be effective upon the appointment of a successor.

Miscellaneous

The purchase contract and pledge agreement provides that the Company will pay all fees and expenses related to (1) the retention of the purchase contract agent, the collateral agent, the custodial agent and the securities intermediary and (2) any enforcement by the purchase contract agent of the rights of the holders of the Corporate Units and the Treasury Units. Holders who elect to substitute the related pledged securities, thereby creating Treasury Units or recreating Corporate Units, however, will be responsible for any fees or expenses payable in connection with such substitution, as well as for any commissions, fees or other expenses incurred in acquiring the pledged securities to be substituted. The Company and the purchase contract agent are not responsible for any such fees or expenses. The purchase contract agent shall be under no obligation to exercise any of the rights or powers vested in it by the purchase contract and pledge agreement at the request or direction of any of the holders pursuant to the purchase contract and pledge agreement, unless such holders shall have offered to the purchase contract agent security or indemnity satisfactory to the purchase contract agent against the costs, expenses, fees and liabilities which might be incurred by it in compliance with such request or direction.

The purchase contract and pledge agreement also provides that any court of competent jurisdiction may in its discretion require, in any suit for the enforcement of any right or remedy under the purchase contract and pledge agreement, or in any suit against the purchase contract agent for any action taken, suffered or omitted by it as purchase contract agent, the filing by any party litigant in such suit of an undertaking to pay the costs of such suit, and that such court may in its discretion assess reasonable costs, including reasonable attorneys’ fees and costs against any party litigant in such suit, having due regard to the merits and good faith of the claims or defenses made by such party litigant. The foregoing shall not apply to any suit instituted by the purchase contract agent, to any suit instituted by any holder, or group of holders, holding in the aggregate more than 10% of the outstanding Equity Units, or to any suit instituted by any holder for the enforcement of any interest on any RSNs owed pursuant to such holder’s applicable ownership interests in RSNs or contract adjustment payments on or after the respective payment date therefor in respect of any Equity Unit held by such holder, or for enforcement of the right to purchase shares of Common Stock under the purchase contracts constituting part of any Equity Unit held by such holder.

Description of the Remarketable Senior Notes

The terms “Additional Interest”, “business day”, “Event of Default”, and “record date”, as used in this Description of the Remarketable Senior Notes, have the meanings ascribed to them in this Description of the Remarketable Senior Notes.

General

Each series of RSNs was issued as a series of debt securities under the Senior Note Indenture. The Company may issue an unlimited amount of other securities under the Senior Note Indenture which are on parity with the RSNs.

The RSNs are direct, unsecured and unsubordinated obligations of the Company ranking equally with all other unsecured and unsubordinated obligations of the Company from time to time outstanding.

The RSNs are issued in fully registered form only, without coupons. Any RSNs that are issued as separate securities as a result of the creation of Treasury Units or in connection with an early settlement, early settlement upon a fundamental change, a remarketing, a termination or a settlement with separate cash will be initially represented by one or more fully registered global securities (the “global securities”) deposited with the Senior Note Indenture Trustee, as custodian for DTC, as depository, and registered in the name of DTC or DTC’s nominee. A beneficial interest in a global security will be shown on, and transfers or exchanges thereof will be effected only through, records maintained by DTC and its participants. The authorized denominations of the RSNs are $1,000 and any larger amount that is an integral multiple of $1,000. However, if a holder is entitled to receive RSNs in an aggregate principal amount that is not an integral multiple of $1,000 upon termination of the purchase contracts as described under “Description of the Purchase Contracts—Termination” above, the purchase contract agent may request that the Company issues RSNs in denominations of $25 and integral multiples thereof. Except in certain limited circumstances, the RSNs that are issued as global securities will not be exchangeable for RSNs in definitive certificated form.

Each Corporate Unit includes a 1/40 undivided beneficial ownership interest in a Series 2025B RSN having a principal amount of $1,000 and a 1/40 undivided beneficial ownership interest in a Series 2025C RSN having a principal amount of $1,000 that correspond to the stated amount of $50 per Corporate Unit.

The RSNs are not subject to a sinking fund provision or repayable at the option of the holders and are not subject to defeasance.

The entire principal amount of the Series 2025B RSNs will mature and become due and payable, together with any accrued and unpaid interest thereon, on December 15, 2030. The entire principal amount of the Series 2025C RSNs will mature and become due and payable, together with any accrued and unpaid interest thereon, on December 15, 2033. As described below under “—Put Option upon Failed Remarketing,” holders will have the right to require the Company to purchase their RSNs under certain circumstances. The Senior Note Indenture does not contain any financial covenants or restrict the Company from paying dividends, making investments, incurring indebtedness or repurchasing the Company’s securities. Except for the covenants described under “—Consolidation, Merger or Sale,” the Senior Note Indenture does not contain provisions that afford holders of the RSNs protection in the event the Company is involved in a highly leveraged transaction or other similar transaction that may adversely affect such holders. The Senior Note Indenture does not limit the Company’s ability to issue or incur other debt or issue preferred stock.

The Company will not pay any additional amounts to holders of the RSNs in respect of any tax, assessment or governmental charge.

Ranking

The RSNs are direct, unsecured and unsubordinated obligations of the Company ranking equally with all other unsecured and unsubordinated obligations of the Company from time to time outstanding.

Since the Company is a holding company, the right of the Company and, hence, the right of creditors of the Company (including holders of the RSNs) to participate in any distribution of the assets of any subsidiary of the Company, whether upon liquidation, reorganization or otherwise, is structurally subordinated to the claims of creditors and any preferred stockholders of each subsidiary.

There are no terms of the RSNs that limit the Company’s ability to incur additional indebtedness or that limit its subsidiaries’ ability to incur additional debt or other liabilities or issue preferred and preference stock.

Principal and Interest

The Series 2025B RSNs mature on December 15, 2030 and currently bear interest at the rate of 4.15% per annum. The Series 2025C RSNs mature on December 15, 2033 and currently bear interest at a rate of 4.15% per annum. Subject to any changes to the interest payment dates made upon a successful remarketing, interest on each series of RSNs is payable quarterly on March 15, June 15, September 15 and December 15 of each year (each, an “interest payment date”), commencing on March 15, 2026, and at maturity. Subject to certain exceptions, the Senior Note Indenture provides for the payment of interest on an interest payment date only to persons in whose names the RSNs are registered at the close of business on the record date. The “record date” means the 15th day of the calendar month immediately preceding the calendar month in which the applicable interest payment date falls (or, if such day is not a business day, the next preceding business day); provided that if any of the RSNs or the Corporate Units are held by a securities depository in book-entry form, the record date for the RSNs will be the close of business on the business day immediately preceding the applicable interest payment date. Notwithstanding the foregoing, any interest payable at maturity or on a redemption date will be paid to the person to whom principal is payable. Interest is calculated on the basis of a 360-day year of twelve 30-day months, and with respect to any period less than a full calendar month, on the basis of the actual number of days elapsed per 30-day month; however, if any series of RSNs is remarketed as floating-rate notes, without the consent of any holder of RSNs, the Company may modify the basis on which interest will be calculated on such series of RSNs after the optional remarketing settlement date or the purchase contract settlement date, as applicable, to conform to the market convention applicable to floating-rate notes using the same interest rate index.

If any interest payment date, redemption date, maturity date or the date (if any) on which the Company is required to purchase RSNs is not a business day, then the applicable payment will be made on the next succeeding day that is a business day and no interest will accrue or be paid in respect of such delay. If any series of RSNs is remarketed as floating-rate notes, without the consent of any holder of RSNs, the Company may modify the interest payment dates for such series of RSNs to provide that if any March 15, June 15, September 15 and December 15 is not a business day, the relevant interest payment date shall be the immediately succeeding business day. A “business day” means any day that is not a Saturday or Sunday or a day on which banking institutions in the City of New York, New York or Hartford, Connecticut are authorized or required by law or executive order

to close or a day on which the Senior Note Indenture Trustee’s corporate trust office is closed for business.

The interest rate on the RSNs may be reset in connection with a successful remarketing, as described below under “Interest Rate Reset.” However, if there is not a successful remarketing, the interest rate will not be reset and each series of RSNs will continue to bear interest at the applicable initial interest rate, all as described below under “—Interest Rate Reset.” Except in the case of a failed final remarketing or with respect to any series of RSNs remarketed as floating-rate notes, interest on the applicable series of RSNs following the optional remarketing settlement date or the purchase contract settlement date, as applicable, will be payable on a semi-annual basis.

Remarketing

The RSNs will be remarketed as described under “Description of the Purchase Contracts— Remarketing.”

Following any successful remarketing of the RSNs:

•    the interest rate on each series of the RSNs may be reset as described below and under “—Interest Rate Reset” below;

•    interest on the RSNs will be payable semi-annually on June 15 and December 15 of each year (except with respect to any series of RSNs remarketed as floating-rate notes); and

•    the Series 2025C RSNs will cease to be redeemable at the Company’s option, and the provisions described under “—Redemption at the Company’s Option” and “—Redemption Procedures” below will no longer apply to the Series 2025C RSNs.

All such modifications will take effect only if the remarketing is successful, without the consent of holders, on the optional remarketing settlement date or the purchase contract settlement date, as the case may be, and will apply to all RSNs of such series, whether or not included in the remarketing. All other terms of the RSNs will remain unchanged.

The Company will use commercially reasonable efforts to ensure that, if required by applicable law, a registration statement, including a prospectus, with regard to the full amount of each series of RSNs to be remarketed will be effective under the securities laws in a form that may be used by the remarketing agent in connection with the remarketing (unless a registration statement is not required under the applicable laws and regulations that are in effect at that time or unless the Company conducts any remarketing in accordance with an exemption under the securities laws).

In order to remarket the RSNs, the remarketing agent, in consultation with the Company, may:

•remarket each series of RSNs as fixed-rate notes or floating-rate notes;

•in the case of any series of RSNs remarketed as fixed-rate notes, reset the interest rate on each series of RSNs (either upward or downward) and, in the case of any series of RSNs remarketed as floating-rate notes, determine the interest rate spread applicable to such series of RSNs, in order to produce the required price in the remarketing, as discussed under “Description of the Purchase Contracts—Remarketing”; and

•in the case of any series of RSNs remarketed as floating-rate notes, (i) provide that the interest on such series of RSNs will be equal to an interest rate index determined by the Company plus a spread determined by the remarketing agent, in consultation with the Company, in which case interest on such series of RSNs may be calculated on the basis of a 360-day year and the actual number of days elapsed (or such other basis as is customarily used for floating-rate notes bearing interest at a rate based on such interest rate index), and (ii) provide for provisions regarding calculation of the selected interest rate index and related benchmark transition provisions, in each case, that are customary for floating-rate notes bearing interest at a rate based on such interest rate index.

Remarketing of RSNs That Are Not Included in Corporate Units

At any time after the Company gives notice of a remarketing (other than during a blackout period), holders of RSNs of either series that do not underlie Corporate Units may elect to have their RSNs remarketed in such remarketing in the same manner as RSNs that underlie Corporate Units by delivering their RSNs along with a notice of this election to the custodial agent. The custodial agent will hold the RSNs separate from the collateral account in which the pledged securities will be held. Holders of RSNs electing to have their RSNs remarketed will also have the right to make or withdraw such election at any time on or prior to 4:00 p.m., New York City time, on the second business day immediately preceding the first day of an optional remarketing period or final remarketing period, as the case may be, in each case, other than during a blackout period. In the event of successful remarketing during an optional remarketing period, each holder of (i) separate Series 2025B RSNs that elects to have such RSNs remarketed will receive, for each $1,000 principal amount of such RSNs sold, the remarketing price per Series 2025B RSN and (ii) separate Series 2025C RSNs that elects to have such RSNs remarketed will receive, for each $1,000 principal amount of such RSNs sold, the remarketing price per Series 2025C RSN. The “remarketing price per Series 2025B RSN” means, for each $1,000 principal amount of Series 2025B RSNs, an amount in cash equal to the quotient of the portion of the Treasury portfolio purchase price attributable to the components of the Treasury portfolio described in the first and third or fourth bullets under “Remarketing—Optional Remarketing—Components of the Treasury Portfolio” above divided by the number of Series 2025B RSNs having a principal amount of $1,000 included in such remarketing that are held as components of Corporate Units. The “remarketing price per Series 2025C RSN” means, for each $1,000 principal amount of Series 2025C RSNs, an amount in cash equal to the quotient of the portion of the Treasury portfolio purchase price attributable to the components of the Treasury portfolio described in the second and fifth or sixth bullets under “Remarketing—Optional Remarketing—Components of the Treasury Portfolio” above divided by the number of Series 2025C RSNs having a principal amount of $1,000 included in such remarketing that are held as components of Corporate Units. For purposes of determining the proceeds that the remarketing agent will seek to obtain for the RSNs in an optional remarketing, the “separate RSNs purchase price” means the amount of cash equal to the sum of (i) the product of (A) the remarketing price per Series 2025B RSN and (B) the number of Series 2025B RSNs having a principal amount of $1,000 included in such remarketing that are not part of Corporate Units and (ii) the product of (A) the remarketing price per Series 2025C RSN and (B) the number of Series 2025C RSNs having a principal amount of $1,000 included in such remarketing that are not part of Corporate Units. In the event of a successful remarketing during the final remarketing period, each holder of separate RSNs that elects to have its RSNs remarketed will receive its pro rata portion of the proceeds of such final remarketing attributable to the remarketed separate RSNs, which, for each $1,000 principal amount of RSNs, will be an amount at least equal to $1,000 in cash. Any accrued and unpaid interest on such RSNs will be paid in cash by the Company, on the purchase contract settlement date.

Interest Rate Reset

The Company may elect to remarket each series of RSNs as fixed-rate notes or floating-rate notes. In connection with a successful remarketing, in the case of any series of RSNs remarketed as fixed-rate notes, the interest rate on such series of RSNs may be reset and, in the case of any series of RSNs remarketed as floating-rate notes, the interest rate on such series of RSNs may be changed to a floating rate equal to an interest rate index selected by the Company plus a reset spread, on the date of a successful remarketing and the relevant reset rate or reset spread, as the case may be, will become effective on the settlement date of the remarketing, which will be, in the case of an optional remarketing, the second business day following the optional remarketing date (or, if the remarketed RSNs are priced after 4:30 p.m., New York City time, on the optional remarketing date, the third business day following the optional remarketing date) and, in the case of the final remarketing period, the purchase contract settlement date. If a reset occurs pursuant to a successful optional remarketing, the reset rate (for any series of RSNs that the Company elects to remarket as fixed-rate notes) and the reset spread (for any series of RSNs that the Company elects to remarket as floating-rate notes) will be the interest rate or spread determined by the remarketing agent, in consultation with the Company, as the rate or spread, as the case may be, that each series of RSNs should bear in order for the remarketing proceeds to equal at least 100% of the Treasury portfolio purchase price plus the separate RSNs purchase price, if any. If a reset occurs pursuant to a successful final remarketing, the reset rate (for any series of RSNs that the Company elects to remarket as fixed-rate notes) and the reset spread (for any series of RSNs that the Company elects to remarket as floating-rate notes) will be the interest rate or spread determined by the remarketing agent, in consultation with the Company, as the rate or spread, as the case may be, that each series of RSNs should bear in order for the remarketing proceeds to equal at least 100% of the principal amount of the RSNs being remarketed. In any case, the reset rate (for any series of RSNs remarketed as fixed-rate notes) or the applicable interest rate index plus the reset spread (for any series of RSNs remarketed as floating-rate notes), as applicable, may be higher or lower than the initial interest rate on such series of RSNs depending on the results of the remarketing and market conditions at that time. However, in no event will the reset rate or the applicable interest rate index plus the reset spread, as the case may be, exceed the maximum rate permitted by applicable law. In addition, following a successful remarketing, interest on any series of RSNs remarketed as fixed-rate notes will be payable on a semi-annual basis on June 15 and December 15 of each year.

If the RSNs are not successfully remarketed, the interest rate will not be reset and the Series 2025B RSNs will continue to bear interest at the initial annual interest rate of 4.15% and the Series 2025C RSNs will continue to bear interest at the initial annual interest rate of 4.15%.

The remarketing agent is not obligated to purchase any RSNs that would otherwise remain unsold in the remarketing. None of the Company, the remarketing agent or any agent of the Company or the remarketing agent will be obligated in any case to provide funds to make payment upon tender of RSNs for remarketing.

Put Option upon Failed Remarketing

If the RSNs have not been successfully remarketed on or prior to the last day of the final remarketing period, holders of RSNs will have the right to require the Company to purchase their RSNs on the purchase contract settlement date, upon at least two business days’ prior notice in the case of RSNs that are not included in Corporate Units, at a price equal to the principal amount of such RSNs. In such circumstances, holders of RSNs that underlie Corporate Units will be deemed to have exercised such put right with respect to both series of RSNs as described under “Description of the

Purchase Contracts—Remarketing,” unless they settle the related purchase contracts with separate cash.

Redemption at the Company’s Option

The Series 2025B RSNs are not subject to optional redemption at any time. The Company may redeem the Series 2025C RSNs at the Company’s option only if there has been a failed final remarketing. In that event, any Series 2025C RSNs that remain outstanding after the purchase contract settlement date will be redeemable on or after December 15, 2030 at the Company’s option, in whole or in part, at any time and from time to time, at a redemption price equal to the principal amount thereof plus accrued and unpaid interest, if any, to but excluding the redemption date. The Company may at any time irrevocably waive the right to redeem the Series 2025C RSNs for any specified period (including the remaining term of the RSNs). The Company may not redeem the Series 2025C RSNs if the Series 2025C RSNs have been accelerated and such acceleration has not been rescinded or unless all accrued and unpaid interest has been paid in full on all outstanding Series 2025C RSNs for all interest periods terminating on or prior to the redemption date. Following a successful remarketing of the Series 2025C RSNs, the Series 2025C RSNs will cease to be redeemable at the Company’s option.

Redemption Procedures

The Company will mail notice of any optional redemption to the registered holder of the Series 2025C RSNs being redeemed not less than 10 days and not more than 60 days before the redemption date. The notice of redemption will identify, among other things, the redemption date, the redemption price and that, on the redemption date, the redemption price will become due and payable and that Series 2025C RSNs called for redemption will cease to accrue interest on and after the redemption date (unless there is a default on payment of the redemption price). Prior to the redemption date, the Company will deposit with the paying agent or the Senior Note Indenture Trustee money sufficient to pay the redemption price of the Series 2025C RSNs to be redeemed on that date. If the Company redeems less than all of the Series 2025C RSNs, the Senior Note Indenture Trustee will choose the Series 2025C RSNs to be redeemed by lot, for Series 2025C RSNs in definitive form, and, for Series 2025C RSNs held by DTC (or another depositary), in accordance with the applicable procedures of DTC (or such other depositary).

In the event the final remarketing fails and you do not settle the related purchase contracts with separate cash, if you hold RSNs as part of Corporate Units you will be deemed to exercise your option to put both series of RSNs to the Company unless you elect to settle the purchase contracts with separate cash as described under “Description of the Purchase Contracts—Notice to Settle with Cash,” and the Company will apply the put price against your obligations under the purchase contracts. This remedy has the effect similar to an automatic redemption of the RSNs, but the Company does not have to give you prior notice or follow any of the other redemption procedures.

The Company will not be required to register the transfer or exchange of (i) all Series 2025C RSNs during a period of 15 days immediately preceding the date notice is given of the selection of the Series 2025C RSNs for optional redemption or (ii) any Series 2025C RSNs being redeemed, except with respect to the unredeemed portion of any Series 2025C RSN being redeemed in part.

Events of Default

The Senior Note Indenture provides that any one or more of the following described events with respect to either series of the RSNs, which has occurred and is continuing, constitutes an “Event of Default” with respect to the RSNs of such series:

(a) failure for 30 days to pay interest on the RSNs of such series, when due on an interest payment date other than at maturity or upon earlier redemption; or

(b) failure to pay principal of, premium, if any, on or interest on the RSNs of such series when due at maturity or upon earlier redemption; or

(c) failure for three business days to deposit any sinking fund payment when due by the terms of a RSN of such series; or

(d) failure to observe or perform any other covenant or warranty of the Company in the Senior Note Indenture (other than a covenant or warranty which has expressly been included in the Senior Note Indenture solely for the benefit of one or more series of senior notes other than such series of RSNs) for 90 days after written notice to the Company from the Senior Note Indenture Trustee or the holders of at least 25% in principal amount of the outstanding Senior Notes of such series; or

(e) certain events of bankruptcy, insolvency or reorganization of the Company.

In addition, an “Event of Default” with respect to the RSNs will occur if the Company fails to pay the purchase price of any RSN on the purchase contract settlement date, if required under “Put Option upon Failed Remarketing” above.

The holders of not less than a majority in aggregate outstanding principal amount of the RSNs of any series have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Senior Note Indenture Trustee with respect to the RSNs of such series. If an Event of Default occurs and is continuing with respect to the RSNs of any series, then the Senior Note Indenture Trustee or the holders of not less than 25% in aggregate outstanding principal amount of the RSNs of such series may declare the principal amount of the RSNs of such series due and payable immediately by notice in writing to the Company (and to the Senior Note Indenture Trustee if given by the holders), and upon any such declaration such principal amount shall become immediately due and payable. At any time after such a declaration of acceleration with respect to the RSNs of any series has been made and before a judgment or decree for payment of the money due has been obtained as provided in Article Five of the Senior Note Indenture, the holders of not less than a majority in aggregate outstanding principal amount of the RSNs of such series may, by written notice to the Company and the Senior Note Indenture Trustee, rescind and annul such declaration and its consequences if the default has been cured or waived and the Company has paid or deposited with the Senior Note Indenture Trustee a sum sufficient to pay all matured installments of interest and principal due otherwise than by acceleration and all sums paid or advanced by the Senior Note Indenture Trustee, including reasonable compensation and expenses of the Senior Note Indenture Trustee.

The holders of not less than a majority in aggregate outstanding principal amount of the RSNs of any series may, on behalf of the holders of all the RSNs of such series, waive any past default with respect to such series of RSNs, except (i) a default in the payment of principal or interest or (ii) a default in respect of a covenant or provision which under Article Nine of the Senior Note Indenture

cannot be modified or amended without the consent of the holder of each outstanding RSN of such series affected.

Modification of Indenture

The Senior Note Indenture contains provisions permitting the Company and the Senior Note Indenture Trustee, with the consent of the holders of not less than a majority in principal amount of the outstanding RSNs of each series affected, to modify the Senior Note Indenture or the rights of the holders of the RSNs of such series; provided that no such modification may, without the consent of the holder of each outstanding RSN affected, (i) change the stated maturity of the principal of, or any installment of principal of or interest on, any RSN, or reduce the principal amount of any RSN or the rate of interest on any RSN or any premium payable upon the redemption of any RSN, or change the method of calculating the rate of interest on any RSN, or impair the right to institute suit for the enforcement of any such payment on or after the stated maturity of any RSN (or, in the case of redemption, on or after the redemption date), or (ii) reduce the percentage of principal amount of the outstanding RSNs of any series, the consent of whose holders is required for any such supplemental indenture, or the consent of whose holders is required for any waiver (of compliance with certain provisions of the Senior Note Indenture or certain defaults under the Senior Note Indenture and their consequences) provided for in the Senior Note Indenture, or (iii) modify any of the provisions of the Senior Note Indenture relating to supplemental indentures, waiver of past defaults or waiver of certain covenants, except to increase any such percentage or to provide that certain other provisions of the Senior Note Indenture cannot be modified or waived without the consent of the holder of each outstanding RSN affected thereby.

In addition to the purposes set forth above, the Company and the Senior Note Indenture Trustee may from time to time, without the consent of any holders of RSNs, amend and/or supplement the Senior Note Indenture for the following purposes:

•following the purchase contract settlement date, to supplement any of the provisions of the RSNs to such extent as shall be necessary to permit or facilitate the defeasance and discharge of the RSNs pursuant to the Senior Note Indenture, provided that any such action will not adversely affect the interests of any holder of any RSN in any material respect;

•set forth the terms of any series of RSNs following a successful remarketing to incorporate the reset interest rate or floating rate and reset spread (as the case may be), incorporate semi-annual interest payment dates (if applicable) and to eliminate the optional redemption provision in the Series 2025C RSNs; and

•to conform the terms of the Senior Note Indenture and the RSNs to the descriptions thereof contained in the “Description of the Remarketable Senior Notes,” “Description of the Equity Units,” “Description of the Purchase Contracts” and “Certain Provisions of the Purchase Contract and Pledge Agreement” sections in the preliminary prospectus supplement for the Equity Units, as supplemented and/or amended by the related pricing term sheet.

In addition, the Company and the Senior Note Indenture Trustee may execute, without the consent of any holders of RSNs, any supplemental indenture for certain other usual purposes, including the creation of any new series of senior notes under the Senior Note Indenture.

Consolidation, Merger and Sale

The Company shall not consolidate with or merge into any other corporation or convey, transfer or lease its properties and assets substantially as an entirety to any person, unless (1) such other corporation or person is a corporation organized and existing under the laws of the United States, any state in the United States or the District of Columbia and such other corporation or person expressly assumes, by supplemental indenture executed and delivered to the Senior Note Indenture Trustee, the payment of the principal of, premium, if any, on and interest on all the RSNs and the performance of every covenant of the Senior Note Indenture on the part of the Company to be performed or observed; (2) immediately after giving effect to such transactions, no Event of Default, and no event which, after notice or lapse of time or both, would become an Event of Default, shall have happened and be continuing; and (3) the Company has delivered to the Senior Note Indenture Trustee an officers’ certificate and an opinion of counsel, each stating that such transaction complies with the provisions of the Senior Note Indenture governing consolidation, merger, conveyance, transfer or lease and that all conditions precedent to the transaction have been complied with.

Information Concerning the Senior Note Indenture Trustee

The Senior Note Indenture Trustee, prior to an Event of Default with respect to RSNs of any series, undertakes to perform, with respect to RSNs of such series, only such duties as are specifically set forth in the Senior Note Indenture and, in case an Event of Default with respect to RSNs of any series has occurred and is continuing, shall exercise, with respect to RSNs of such series, the same degree of care as a prudent individual would exercise in the conduct of his or her own affairs. Subject to such provision, the Senior Note Indenture Trustee is under no obligation to exercise any of the powers vested in it by the Senior Note Indenture at the request of any holder of RSNs of any series, unless offered reasonable indemnity by such holder against the costs, expenses and liabilities which might be incurred by the Senior Note Indenture Trustee. The Senior Note Indenture Trustee is not required to expend or risk its own funds or otherwise incur any financial liability in the performance of its duties if the Senior Note Indenture Trustee reasonably believes that repayment or adequate indemnity is not reasonably assured to it.

Governing Law

The Senior Note Indenture and the RSNs are governed by, and construed in accordance with, the internal laws of the State of New York.

Miscellaneous

The Company has the right at all times to assign any of its rights or obligations under the Senior Note Indenture to a direct or indirect wholly-owned subsidiary of the Company; provided, that, in the event of any such assignment, the Company will remain primarily liable for all such obligations. Subject to the foregoing, the Senior Note Indenture will be binding upon and inure to the benefit of the parties to the Senior Note Indenture and their respective successors and assigns.

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Exhibit 10(a)13

TENTH AMENDMENT TO THE

SOUTHERN COMPANY EMPLOYEE SAVINGS PLAN

WHEREAS, Southern Company Services, Inc. adopted the latest amendment and restatement of The Southern Company Employee Savings Plan (“Plan”), effective as of January 1, 2018;

WHEREAS, pursuant to Section 15.1 of the Plan, the Southern Company Employee Savings Plan Committee (“Administrative Committee”) may amend the Plan, provided the amendment either (a) does not involve a substantial increase in cost to any Employing Company, or (b) is necessary, proper, or desirable in order to comply with applicable laws or regulations enacted or promulgated by any federal or state governmental authority and to maintain the qualified status of the Plan; and

WHEREAS, the Administrative Committee, in its settlor capacity, desires to amend the Plan to (i) provide for full vesting of employees of Mutual Savings Credit Union who are no longer Employees due to the divestiture that occurred on December 31, 2024, and provide for full vesting for the Accounts of such employees; and (ii) add special distributions and Plan loan relief for Participants impacted by federally-declared major disasters, as permitted under the SECURE Act 2.0 of 2022.

NOW, THEREFORE, pursuant to resolutions adopted on February 4, 2025, the Administrative Committee hereby amends the Plan as follows, effective as specified below:

1.

Effective as of December 31, 2024, Section 3.7 of the Plan is hereby amended by adding the following to the end thereof:

(k)    Mutual Savings Credit Union.

(1)    Cessation of Participation. Effective as of December 31, 2024, Mutual Savings Credit Union will cease to be an affiliated company of Southern Company Gas for purposes of determining Employing Company status under the Plan; and (ii) Participants who cease to be Employees due to the sale of Mutual Savings Credit Union will cease to be eligible to actively participate in the Plan.

(2)    Vesting Acceleration. Effective as of December 31, 2024, Participants who cease to be Employees due to the sale of Mutual Savings Credit Union will be deemed to be fully vested in their Accounts for all purposes hereunder.

2.

Effective as of March 1, 2025, Section 11.6 of the Plan is hereby amended by adding the following to the end thereof:

(i)    Loan-Related Relief for Qualified Disasters. Effective as of March 1, 2025, notwithstanding anything in this Section 11.6 to the contrary, the following rules apply to provide relief to a Qualified Individual with respect to a Qualified Disaster. The definitions set forth in Section 12.15(c) of the Plan will apply for purposes of this Section 11.6(i).

(1)    In the case of a Participant who is a Qualified Individual with respect to a Qualified Disaster, the maximum loan amount described in the first sentence of Section 11.6(b) is increased for any loan initiated during the period beginning on the Applicable Date and ending on the date that is 180 days after such Applicable Date by replacing “$50,000” in clause (1) with “$100,000” and replacing “fifty percent (50%)” in clause (2) with “one hundred percent (100%).”

(2)    A Participant who is a Qualified Individual with respect to a Qualified Disaster and who has an outstanding loan under the Plan on or after the Applicable Date for such Qualified Disaster may submit a request on a form acceptable to the Administrative Committee or its delegate to delay for a period of up to one year any repayment due date occurring during the period beginning on the first day of the Incident Period for the Qualified Disaster and ending on the date that is 180 days after the last day of the Incident Period. Any subsequent repayments with respect to such loan will be appropriately adjusted to reflect the delayed repayment due date and any interest accrued during such delay. Further, the Plan will disregard the period of delay when calculating the five-year period and the term of such loan under section Code Section 72(p)(2)(B) and (C).

3.

Effective as of March 1, 2025, Article XII of the Plan is hereby amended by adding the following to the end thereof:

12.15     Qualified Disaster Recovery Distributions. Effective as of March 1, 2025, notwithstanding any other Plan provisions restricting withdrawals prior to severance from employment, a Qualified Individual may obtain a Qualified Disaster Recovery Distribution, as defined in Code Section 72(t)(11), of up to $22,000 from his vested Account balance, provided that such distribution must be made on or after the first day of the Incident Period and within 179 days after the Applicable Date. The aggregate amount of Qualified Disaster Recovery Distributions received in all taxable years by a Qualified Individual with respect to the same Qualified Disaster shall not exceed $22,000 under the Plan or any other retirement plans maintained by the Company or any Affiliated Employer.

(a)    Repayment of Distribution. Qualified Individuals who receive a Qualified Disaster Recovery Distribution may, while eligible to make Rollover Contributions under the Plan, at any time during the three-year period beginning on

the day after the date on which such distribution was received, make one or more contributions in an aggregate amount not to exceed the amount of such distribution to an eligible retirement plan of which such individual is a beneficiary and to which a rollover contribution of such distribution could be made under Code Sections 402(c), 403(a)(4), 403(b)(8), 408(d)(3), or 457(e)(16).

(b)    Reliance. In determining whether a Participant is a Qualified Individual who is eligible for a Qualified Disaster Recovery Distribution, the Administrative Committee may rely on the Participant’s reasonable representation that the Participant is a Qualified Individual, unless the Administrative Committee has actual knowledge that is contrary to the representation.

(c)    Definitions. For purposes of Section 11.6(i) and this Section 12.15, the following terms will have the following meanings:

(1)    The “Applicable Date” of a Qualified Disaster is the later of (A) the first day of the Incident Period or (B) the date of the disaster declaration.

(2)    “Incident Period” is the period specified by the Federal Emergency Management Agency as the period during which the Qualified Disaster occurred.

(3)    “Qualified Disaster” means any disaster with respect to which a major disaster has been declared by the President under section 401 of the Robert T. Stafford Disaster Relief and Emergency Assistance Act after December 27, 2020.

(4)    “Qualified Disaster Area” means the area with respect to which the Qualified Disaster was declared, excluding an area which is a qualified disaster area solely by reason of section 301 of the Taxpayer Certainty and Disaster Tax Relief Act of 2020.

(5)    “Qualified Individual” with respect to a Qualified Disaster means a Participant whose principal place of residence is in the Qualified Disaster Area for the Qualified Disaster at any time during the Incident Period and who has sustained economic loss by reason of the Qualified Disaster.

4.

Except as amended by this Tenth Amendment, the Plan shall remain in full force and effect.

IN WITNESS WHEREOF, the Administrative Committee, through its authorized representative, has adopted this Tenth Amendment to The Southern Company Employee Savings Plan, as amended and restated as of January 1, 2018, this     12 day of     December    , 2025.

EMPLOYEE SAVINGS PLAN COMMITTEE

By:     /s/James M. Garvie

Name: James M. Garvie

Its: Chairperson

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Exhibit 10(a)16

CONSULTING AGREEMENT

This CONSULTING AGREEMENT (“Agreement”) is made and entered into as of August 11, 2025 by and between Southern Company Services, Inc. (the “Company”) and Daniel S. Tucker (“Consultant” and collectively with the Company the “Parties,” or individually each a “Party”).

WITNESSETH:

WHEREAS, the Company desires to retain Consultant to provide certain services to the Company, and Consultant desires to provide such services to the Company, all subject to the terms and conditions set forth herein.

NOW THEREFORE, for and in consideration of the premises, the mutual covenants and agreements contained herein, and for other good and valuable consideration, the receipt, sufficiency and adequacy of which are hereby acknowledged, the Parties hereby agree as follows:

1.    Engagement as an Independent Contractor.

The Company hereby agrees to engage Consultant as an independent contractor, and Consultant hereby accepts such engagement as an independent contractor, upon the terms and conditions set forth in this Agreement.

2.    Term.

The term of this Agreement shall commence on October 1, 2025 and shall expire on September 30, 2027 (“Term”). By mutual consent, the Parties may extend the Term of this Agreement by a written amendment that is signed by both Parties.

3.    Duties.

Consultant shall manage, perform and provide professional consulting services and advice (“Consulting Services”) as may be mutually agreed upon by the Chief Executive Officer (“CEO”) of The Southern Company (“Southern”) and Consultant from time to time. Consultant’s work, on average, will not exceed 20 hours per month; provided, however, that Consultant shall not be required to work any minimum number of hours during a month to perform the duties outlined in this section. Consultant shall be available on an “on call” basis to consult by telephone and email correspondence and will attend meetings as needed. During the Term, Consultant agrees to promote the best interests of the Company and its affiliates and to take no actions that in any way damage the public image or reputation of the Company or its affiliates or to knowingly assist, in any way, any competitor of the Company or its affiliates.

4.    Consultant as an Independent Contractor.

During the Term, Consultant will at all times be and remain an independent contractor. Consultant will be free to exercise Consultant’s own judgment as to the manner and method of providing the Consulting Services to the Company, subject to applicable laws and requirements

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reasonably imposed by the Company. Consultant acknowledges and agrees that, during the Term, Consultant will not be treated as an employee of the Company or any of its affiliates for purposes of federal, state, local or foreign income tax withholding, nor unless otherwise specifically provided by law, for purposes of the Federal Insurance Contributions Act, the Social Security Act, the Federal Unemployment Tax Act or any Worker's Compensation law of any state or country and for purposes of benefits provided to employees of the Company or any of its affiliates under any employee benefit plan. Consultant acknowledges and agrees that as an independent contractor, Consultant will be required to pay any applicable taxes on the fees paid to Consultant.

5.    Consulting Fee.

As payment for the Consulting Services rendered pursuant to this Agreement, the Company shall pay, and Consultant shall accept, an annual consulting fee in the amount of Three Hundred Thousand and 00/100 Dollars ($300,000.00) during the Term (the “Consulting Fee”). The Consulting Fee will be paid in substantially equal installments on a monthly basis, on or before the 15th day of the month following the month in which the Consulting Services are performed. The Company will reimburse Consultant for all reasonable documented expenses incurred by Consultant in the performance of the Consulting Services, in accordance with the Company’s policies and subject to the approval of the CEO of Southern.

6.    Termination.

The Parties to the Agreement may mutually agree in writing to terminate the Agreement prior to the expiration of the Term. The Company may, in its sole discretion, terminate the Agreement for cause if Consultant does not perform Consulting Services under this Agreement in a satisfactory manner that protects the business interests of the Company. Any remaining unpaid installments under Section 5 shall be forfeited by Consultant if the Agreement is terminated prior to the expiration of the Term.

7.    Confidential Information; Trade Secrets; Ownership of Work Product.

a.    For purposes of this Agreement, the following terms shall have the following respective meanings:

i.      "Confidential Information” shall mean all valuable, proprietary and confidential data, information, documents, or materials (whether oral, written, electronic, or otherwise) belonging to or pertaining to the Company or any current or former subsidiaries or affiliates of Southern (collectively, “Southern Entities”), other than Trade Secrets (as defined below), that is generally known only to the Southern Entities and those of their employees, independent contractors, clients or agents to whom such information must be confided for internal business purposes.

ii.    “Entity or Entities” shall mean any person; business; individual; partnership; joint venture; agency; governmental agency, body, or subdivision; association; firm; corporation; limited liability company; or other entity of any kind.

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iii.    “Trade Secrets” shall mean the “trade secrets” of Southern Entities as defined under applicable laws.

iv.    “Work Product” shall mean all work product, property, data, documentation, information or materials relating to the Southern Entities that were conceived, discovered, created, or developed by Consultant in performing the Consulting Services; for the avoidance of doubt, Work Product shall not include any work product, property, data, documentation, information or materials relating to or containing information deemed classified by a United States government agency for reasons of national security.

b.    In recognition of the need of the Company to protect its legitimate business interests, Confidential Information and Trade Secrets, Consultant hereby covenants and agrees that Consultant shall regard and treat Trade Secrets and all Confidential Information as strictly confidential and wholly-owned by the Southern Entities and shall not, for any reason, in any fashion, either directly or indirectly, use, sell, lend, lease, distribute, license, give, transfer, assign, show, disclose, disseminate, reproduce, copy, misappropriate, or otherwise communicate any such item or information to any third party Entity for any purpose other than in accordance with the Agreement or as required by applicable law: (A) with regard to each item constituting a Trade Secret, at all times such information remains a trade secret under applicable law and (B) with regard to any Confidential Information, for a period of five years following the end of the Term of the Agreement.

c.    Consultant shall exercise best efforts to ensure the continued confidentiality of all Trade Secrets and Confidential Information and shall immediately notify the Company of any unauthorized disclosure or use of any Trade Secrets or Confidential Information of which Consultant becomes aware. Consultant shall assist the Southern Entities, to the extent necessary, in the protection of or procurement of any intellectual property protection or other rights in any of the Trade Secrets or Confidential Information.

d.    U.S. DEFEND TRADE SECRETS ACT NOTICE OF IMMUNITY. The U.S. Defend Trade Secrets Act of 2016 (“DTSA”) provides that an individual shall not be criminally or civilly liable under any federal or state trade secret law for the disclosure of a trade secret that (1) is made (A) in confidence to a federal, state or local government official, either directly or indirectly, or to an attorney; and (B) solely for the purpose of reporting or investigating a suspected violation of law or (2) is made in a complaint or other document filed in a lawsuit or other proceeding, if such filing is made under seal. In addition, the DTSA provides that an individual who files a lawsuit for retaliation by an employer for reporting a suspected violation of law may disclose the trade secret to the attorney of the individual and use the trade secret information in the court proceeding, if the individual (x) files any document containing the trade secret under seal and (y) does not disclose the trade secret, except pursuant to court order.

e.    All Work Product shall be owned exclusively by the Company. To the greatest extent possible, any Work Product shall be deemed to be work made for hire (as defined in the Copyright Act, 17 U.S.C.A. § 101 et seq., as amended), and Consultant hereby unconditionally and irrevocably transfers and assigns to the Company all right, title,

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and interest Consultant currently has or may have by operation of law or otherwise in or to any Work Product, including, without limitation, all patents, copyrights, trademarks (and the goodwill associated therewith), trade secrets, service marks (and the goodwill associated therewith), and other intellectual property rights. Consultant agrees to execute and deliver to the Company any transfers, assignments, documents or other instruments which the Company may deem necessary or appropriate, from time to time, to protect the rights granted herein or to vest complete title and ownership of any and all Work Product, and all associated intellectual property and other rights therein, exclusively in the Company.

f.    Notwithstanding anything herein to the contrary, nothing in this Agreement will prevent Consultant from providing truthful testimony under oath in a judicial or administrative proceeding or prevent Consultant from providing information to a federal, state, or local agency or commission (“Government Agencies”) in connection with the lawful exercise of such Government Agency’s functions. Moreover, nothing in this Agreement is intended to prohibit Consultant from engaging in protected activities under applicable law (including protected activities described in Section 211 of the Energy Reorganization Act). Consultant further understands nothing in this Agreement limits Consultant’s ability to file a charge or complaint with the Securities and Exchange Commission or any other Government Agency. Nothing in this Agreement limits Consultant’s ability to communicate with any Government Agencies or otherwise participate in any investigation or proceeding that may be conducted by a Government Agency, including providing documents or information without notice to the Company. This Agreement does not limit Consultant’s right to receive an award for information provided to any Government Agency.

8.    Non-Solicitation.

During the Term (or if earlier, the date that is 30 days after the Company receives written notice from Consultant that the Company has materially breached this Agreement if such breach is not cured by the Company within such 30-day period), Consultant will not, directly or indirectly, for himself or on behalf of any person or entity, solicit or attempt to solicit any of the Southern Entities’ employees to leave their employment. The provisions of this Section 8 shall only apply to those persons employed by a Southern Entity at the time of the solicitation or attempted solicitation, shall not restrict the hiring of any person which occurred without any recruitment or solicitation by Consultant (including by reason of placing a general advertisement to hire which is not targeted at employees of the Southern Entities), and shall not prevent Consultant from responding to contact initiated by such employees or providing references if requested by any such employee.

9.    Remedies.

The Parties represent and agree that any disclosure or use of any Trade Secrets or Confidential Information by Consultant except as otherwise permitted under this Agreement or authorized by the Company in writing, or any other violation of Sections 7 or 8, would be wrongful and cause immediate, significant, continuing and irreparable injury and damage to the Company that is not fully compensable by monetary damages. Should Consultant breach or

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threaten to breach any provisions of Sections 7 or 8, the Company shall be entitled to obtain immediate relief and remedies in a court of competent jurisdiction (including but not limited to damages, preliminary or permanent injunctive relief and an accounting for all profits and benefits arising out of Consultant’s breach), cumulative of and in addition to any other rights or remedies to which Company may be entitled by this Agreement, at law or in equity.

10.    Return of Materials.

Immediately upon termination of the Agreement, or at any point prior to or after that time upon the specific request of Company, the Consultant shall return to the Company all written or descriptive materials of any kind belonging or relating to the Company or any Southern Entity, including, without limitation, any Work Product, Confidential Information and Trade Secrets in Consultant’s possession or control.

11.    Laws, Regulations and Public Ordinances.

Consultant shall comply with all federal, state and local statutes, regulations and public ordinances governing his work hereunder and shall indemnify, defend and hold the Company harmless from any and all liability, damage, cost, fine, penalty, fee, and expense arising from Consultant’s failure to do so.

12.    Notice.

All notices required, necessary or desired to be given pursuant to this Agreement shall be in writing and shall be effective when delivered or on the third day following the date upon which such notice is deposited, postage prepaid, in the United States mail, certified return receipt requested, and addressed to the Party at the address set forth below:

If to Consultant:                                                                 If to the Company:

Daniel S. Tucker                                                                 Southern Company Services, Inc.

Home Address on File                                                        30 Ivan Allen Jr. Blvd., NW

Atlanta, GA 30308

Attention: Sterling A. Spainhour

13.    Indemnification.

Consultant shall and does hereby expressly agree to indemnify and hold harmless the Southern Entities and their officers, directors, shareholders, and employees against any and all liabilities, costs and expenses (including, without limitation, all court costs and attorneys’ fees) arising out of or related to any acts or omissions of Consultant, his agents, employees or subcontractors. Consultant further agrees to defend any and all such actions in any court or in arbitration.

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14.    Waiver of Breach.

The waiver by any Party to this Agreement of a breach of any provision, section or paragraph of this Agreement shall not operate or be construed as a waiver of any subsequent breach of the same, or of a different provision, section or paragraph, by any Party hereto.

15.    Assignment by Consultant.

Consultant may not assign, transfer or subcontract any of his rights or obligations under this Agreement to any party without the prior written consent of the Company. Consultant’s obligations under this Agreement shall be binding on Consultant’s successors and permitted assigns. Any assignment, transfer or subcontracting in violation of this provision shall be null and void.

16.    Governing Law.

This Agreement shall be construed and enforced in accordance with the laws of the State of Georgia.

17.    Severability.

The unenforceability or invalidity of any particular provision of this Agreement shall not affect its other provisions, and to the extent necessary to give such other provisions effect, they shall be deemed severable. The judicial body interpreting this Agreement shall be authorized and instructed to rewrite any of the sections which are unenforceable as written in such a fashion so that they may be enforced to the greatest extent legally possible. Consultant acknowledges and agrees that the covenants and agreements contained in this Agreement shall be construed as covenants and agreements independent of each other or any other contract between the Parties hereto and that the existence of any claim or cause of action by Consultant against the Company or any Southern Entity, whether predicated upon this Agreement or any other contract, shall not constitute a defense to the enforcement by the Company or any Southern Entity of said covenants and agreements.

18.    Interpretation.

The judicial body interpreting or construing the Agreement shall not construe the terms hereof more strictly against one Party, it being agreed that all Parties and/or their agents have participated in the preparation hereof.

19.    Survival.

Notwithstanding any expiration or termination of this Agreement, the provisions of Sections 7 through 18 hereof shall survive and remain in full force and effect, as shall any other provision hereof that, by its terms or reasonable interpretation thereof, sets forth obligations that extend beyond the termination of this Agreement.

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20.    Counterparts.

This Agreement may be executed in separate counterparts, each of which shall be deemed to be an original and both of which taken together shall constitute one and the same agreement.

21.    Entire Agreement.

This Agreement embodies the entire agreement of the Parties and supersedes all prior agreements between the Parties hereto relating to the subject matter hereof. This Agreement may not be modified or amended except by a written instrument signed by both Consultant and an authorized representative of the Company.

[Signatures are on following page]

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IN WITNESS WHEREOF, the Parties hereto have executed this Agreement effective as of the date first set forth above.

COMPANY                                                                CONSULTANT

/s/Christopher C. Womack                                          /s/Daniel S. Tucker

Printed Name: Christopher C. Womack                     Daniel S. Tucker

Title:   Chairman, President and Chief

Executive Officer of

The Southern Company

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Document

Exhibit 10(a)17

DEFERRED COMPENSATION AGREEMENT

THIS DEFERRED COMPENSATION AGREEMENT (“Agreement”) is made and entered into by THE SOUTHERN COMPANY (“Southern”) and SOUTHERN COMPANY SERVICES, INC. (“Company”) (collectively “Southern Parties”) and DAVID POROCH (“Employee”), this 4th day of January 2012 (“Effective Date”).

W I T N E S S E T H

WHEREAS, Employee is a highly compensated employee of the Company and is a member of its management;

WHEREAS, although Employee’s career with the Southern Company system began on January 3, 2012, his valuable experience began at an earlier date with his work with the Company’s independent registered public accounting firm; and

WHEREAS, the Southern Parties desire to set forth the manner in which the benefits provided to Employee under the Agreement as a result of the recognition of his prior valuable experience will be shared.

NOW, THEREFORE, in consideration of the premises, and the agreements of the parties set forth herein, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto, intending to be legally bound, hereby covenant and agree as follows:

1.    Eligibility for Supplemental Retirement Benefits.

(a)    Subject to the terms of this Agreement, if the Employee remains employed with the Company for five (5) years from the Effective Date (the “Service Requirement”), the Southern Parties shall pay to Employee (or if Payment continues, to Employee’s designated beneficiary, as the case may be, in the event of Employee’s death as described in Section 1(c) hereof) the supplemental retirement payment (the “Payment”) described in Section 1(b) hereof (to be shared among the Southern Parties in such pro rata portions as set forth in Sections 2 or 3 hereof).

The Service Requirement shall not apply if the Employee is terminated under circumstances that result in eligibility for severance benefits under The Southern Company Executive Change in Control Severance Plan.

(b)    In the event Employee satisfies the requirements of this Agreement, the Payment shall be an amount equal to the difference between:

(i)    the amounts payable to Employee under the Pension Plan, the Southern Company Supplemental Benefit Plan (“SBP”) and the Southern Company Supplemental Executive Retirement Plan (“SERP”) (collectively, the “Retirement Plans”) as each shall then be in effect, determined as if Employee had an additional eight (8) years of Accredited Service under the Pension Plan; and

(ii)    the amounts Employee is actually entitled to receive under the Retirement Plans at Employee’s retirement, as each shall then be in effect, as further determined and payable in accordance with Section 1(d) hereof.

(c)    Payment in the Event of Death. In the event Employee dies and Payment continues to Employee’s designated beneficiary (the “Death Benefit”), such Payment shall be made in accordance with Section 1(d) hereof.

(d)    Calculation, Form and Timing of Payment. The calculation (including actuarial assumptions), form and timing of the Payment or Death Benefit upon the occurrence of a “separation from service” as defined in Section 409A of the Internal Revenue Code and the regulations promulgated thereunder (“Separation from Service”) shall be the same as the calculation (including actuarial assumptions), form and timing of similar payments to Employee or designated beneficiary as the case may be, under the terms of the SERP and the SBP (but, as to the SBP, only concerning the “Pension Benefit” provided thereunder) as each may be amended from time to time.

(e)    Termination for Cause. In the event of Employee’s termination of employment for Cause at any time, the Employee shall forfeit the entire benefit provided in this Section 1, and Southern and the Company and any of their respective affiliates (the “Southern Entities”) shall have no further obligations with respect to any amount under the Agreement. As used in the Agreement, the term “Cause” shall mean gross negligence or willful misconduct in the performance of the duties and services required in the course of employment by the Company; the final conviction of a felony or misdemeanor involving moral turpitude; the carrying out of any activity or the making of any statement which would prejudice the good name and standing of any of the Southern Entities or would bring any of the Southern Entities into contempt, ridicule or would reasonably shock or offend any community in which any of the Southern Entities is located; a material breach of the fiduciary obligations owed by an officer and

an employee to any of the Southern Entities; or the Employee’s unsatisfactory performance of the duties and services required by his employment.

(f)    Misconduct. Notwithstanding the foregoing, in the event the Employee engages in Misconduct, as defined below, before or after the Employee’s termination date but prior to receiving all of the payments described in this Section 1, the Company may cease making payments to the Employee under this Section 1, and the Company shall have no further obligations with respect to any amounts under this Agreement. For purposes of this Section 1(f), “Misconduct” shall mean (i) the final conviction of any felony, or (ii) the carrying out of any activity or the making of any public statement which materially diminishes the good name and standing of any Southern Entity or materially and untruthfully brings one or all of the Southern Entities into contempt, ridicule or materially and reasonably shocks or offends the community in which a Southern Entity is located.

2.    Sharing of Expense. In the event that the Employee is employed at more than one subsidiary or affiliate of Southern, the liability for amounts paid under this Agreement shall be apportioned so that each such company is obligated in accordance with this Section 2 to cover their percentage of the total liability as determined below. Each company’s share of the liability shall be calculated by multiplying the Payment by a fraction where the numerator of such fraction is the base rate of pay received by the Employee at the respective company on his date of termination of employment or transfer, as applicable, multiplied by the Accredited Service as defined in the Pension Plan earned by the Employee at the respective company and where the denominator of such fraction is the sum of all numerators calculated for each respective company by which the Employee has been employed.

3.    Transfer of Employment to a Southern Subsidiary or Affiliate. In the event that Employee’s employment by the Company is terminated and Employee shall become immediately re-employed by a subsidiary or an affiliate of Southern, the Company shall assign this Agreement pursuant to an Assignment Agreement substantially in the form of Exhibit 1 attached hereto, and such assignee shall become the “Company” for all purposes hereunder. Such subsidiary or affiliate shall accept such assignment, but if for any reason this does not occur, Southern shall accept such assignment. In the event of such assignment, liability for any amounts to be paid under this Agreement shall be shared pro rata by the Company, Southern, SCS and any such

assignee (collectively “Contract Obligors”) based upon the allocation methodology set forth in Section 2.

4.    Business Protection Provisions.

(a)    Preamble. As a material inducement to the Southern Parties to enter into this Agreement, and the recognition of the valuable experience, knowledge and proprietary information Employee gained from his employment with the Company, Employee warrants and agrees he will abide by and adhere to the following business protection provisions in this Section 4.

(b)    Definitions. For purposes of this Section 4, the following terms shall have the following meanings:

(i)    “Competitive Position” shall mean any employment, consulting, advisory, directorship, agency, promotional or independent contractor arrangement between Employee and any Entity (as defined below) engaged wholly or in material part in the business that the Company is engaged in whereby Employee is required to or does perform services on behalf of or for the benefit of such Entity which are substantially similar to the services Employee participated in or directed while employed by the Company or any other Southern Entity.

(ii)    “Confidential Information” shall mean the proprietary or confidential data, information, documents or materials (whether oral, written, electronic or otherwise) belonging to or pertaining to the Company or any of the other Southern Entities, other than “Trade Secrets” (as defined below), which is of tangible or intangible value to any of the Southern Entities and the details of which are not generally known to the competitors of the Southern Entities. Confidential Information shall also include: (A) any items that any of the Southern Entities have marked “CONFIDENTIAL” or some similar designation or are otherwise identified as being confidential; (B) all non-public information known by or in the possession of Employee related to or regarding any proceedings involving or related to the Southern Entities before any federal or state regulatory agencies; and (C) all communications, research, analysis, reports, opinions, recommendations and presentations prepared, reviewed, edited or possessed by Employee at any time during his employment, whether marked

Confidential or not, which relate to electric utilities, electric generation or transmission in the United States, or the building, acquisition or ownership of electric utility assets in the United States.

(iii)    “Entity” or “Entities” shall mean any person, business, individual, partnership, joint venture, agency, governmental agency, body or subdivision, association, firm, corporation, limited liability company or other entity of any kind.

(iv)    “Territory” shall mean the service territory of the Southern Entities and those states contiguous to such service territory or otherwise connected through regional electric markets.

(v)    “Trade Secrets” shall mean information or data of or about any of the Southern Entities, including, but not limited to, technical or non-technical data, formulas, patterns, compilations, programs, devices, methods, techniques, drawings, processes, financial data, financial plans, product plans or lists of actual or potential customers or suppliers that: (A) derives economic value, actual or potential, from not being generally known to, and not being readily ascertainable by proper means by, other persons who can obtain economic value from its disclosure or use; and (B) is the subject of efforts that are reasonable under the circumstances to maintain its secrecy. Employee agrees that trade secrets include non-public information related to the rate making process of the Southern Entities and any other information which is defined as a “trade secret” under applicable law, regardless of the process through which Employee would have become aware of or possessed such information.

(vi)    “Work Product” shall mean all tangible work product, memoranda, working papers, property, data, documentation, concepts or plans, inventions, improvements, techniques and processes (and drafts thereof) relating to the Southern Entities that were conceived, discovered, created, written, revised or developed by Employee during the term of his employment with SCS and the Company.

(c)    Nondisclosure: Ownership of Proprietary Property. In recognition of the need of the Company to protect its legitimate business interests, Confidential Information and Trade Secrets, Employee hereby covenants and agrees that Employee shall regard and treat Trade Secrets and all Confidential Information as strictly confidential and wholly-owned by the Company and shall not, for any reason, in any fashion, either directly or indirectly, use, sell, lend, lease, distribute, license, give, transfer, assign, show, disclose, disseminate, reproduce, copy, misappropriate or otherwise communicate any such item or information to any third party Entity for any purpose other than in accordance with this Agreement or as required by applicable law: (A) with regard to each item constituting a Trade Secret, at all times such information remains a “trade secret” under applicable law, and (B) with regard to any Confidential Information, for a period of three (3) years following the Employee’s date of Separation from Service (hereafter the “Restricted Period”).Employee shall exercise best efforts to ensure the continued confidentiality of all Trade Secrets and Confidential Information, and he shall immediately notify the Company of any unauthorized disclosure or use of any Trade Secrets or Confidential Information of which Employee becomes aware. Employee shall assist the Company, to the extent necessary, in the protection of or procurement of any intellectual property protection or other rights in any of the Trade Secrets or Confidential Information. All Work Product shall be owned exclusively by the Company. To the greatest extent possible, any Work Product shall be deemed to be “work made for hire” (as defined in the Copyright Act, 17 U.S.C.A. § 101 et seq., as amended), and Employee hereby unconditionally and irrevocably transfers and assigns to the Company all right, title and interest Employee currently has or may have by operation of law or otherwise in or to any Work Product, including, without limitation, all patents, copyrights, trademarks (and the goodwill associated therewith), trade secrets, service marks (and the goodwill associated therewith) and other intellectual property rights. Employee agrees to execute and deliver to the Company any transfers, assignments, documents or other instruments which the Company may deem necessary or appropriate, from time to time, to protect the rights granted herein or to vest complete title and ownership of any and all Work Product, and all associated intellectual property and other rights therein, exclusively in the Company.

(d)    Non-Interference with Employees. Employee covenants and agrees that during the Restricted Period he will not, either directly or indirectly, alone or in conjunction with any Entity: (i) actively recruit, solicit, attempt to solicit, or induce any person who, during such

Restricted Period, or within one year prior to his date of Separation from Service, was an exempt employee of the Company or any of its subsidiaries, or was an officer of any of the other Southern Entities to leave or cease such employment for any reason whatsoever; or (ii) hire or engage the services of any such person described in Section 4(d)(i) in any business substantially similar or competitive with that in which the Southern Entities were engaged during his employment.

(e)    Non-Interference with Customers.

(i)    Employee acknowledges that in the course of employment, he has learned about the Company’s business, services, materials, programs, plans, processes, and products and the manner in which they are developed, marketed, serviced and provided. Employee knows and acknowledges that the Company has invested considerable time and money in developing its business, services, materials, programs, plans, processes, products and marketing techniques and that they are unique and original. Employee further acknowledges that the Company must keep secret all pertinent information divulged to Employee regarding the Company’s business concepts, services, materials, ideas, programs, plans and processes, products and marketing techniques, so as not to aid the Company’s competitors. Accordingly, the parties agree that the Company is entitled to the following protection, which Employee agrees is reasonable:

(ii)    Employee covenants and agrees that for a period of two (2) years following his date of Separation from Service, he will not, on his own behalf or on behalf of any Entity, solicit, direct, appropriate, call upon, or initiate communication or contact with any Entity or any representative of any Entity, with whom Employee had contact during his employment, with a view toward the sale or the providing of any product, equipment or service sold or provided or under development by the Company during the period of two (2) years immediately preceding the date of Employee’s date of Separation from Service. The restrictions set forth in this Section shall apply only to Entities with whom Employee had actual contact during the two (2) years prior to Employee’s date of Separation from Service with a view toward the sale or providing of any product, equipment or service sold, provided, or under development by the Company.

(f)    Non-Interference with Business.

(i)    Employee and the Company expressly covenant and agree that the scope, territorial, time and other restrictions contained in this entire Agreement constitute the most reasonable and equitable restrictions possible to protect the business interests of the Company given: (A) the business of the Company; (B) the competitive nature of the Company’s industry; and (C) that Employee’s skills are such that he could easily find alternative, commensurate employment or consulting work in his field which would not violate any of the provisions of this Agreement.

(ii)    Employee covenants and agrees to not obtain or work in a Competitive Position within the Territory for a period of two (2) years from the date of Separation from Service, except as expressly approved by the Chief Executive Officer of the Company.

5.    Publicity; No Disparaging Statement. Except as otherwise provided in Section 9 hereof, Employee and the Company covenant and agree that they shall not engage in any communications which shall disparage one another or interfere with their existing or prospective business relationships. Such communications include, but are not necessarily limited to, remarks, comments, observations, analysis, opinions, statements, whether solicited or unsolicited, written or verbal, which reflect in any manner on the market, operating, financial, communications, people or other business strategies or actions of the Southern Entities, and their officers, directors, employees and agents.

6.    No Employment. Employee agrees that he shall not unilaterally seek re-employment as an employee, temporary employee, leased employee or independent contractor with any of the Southern Entities, for a period of two (2) years following the Employee’s date of Separation from Service. Further, neither the Company nor any of the other Southern Entities shall rehire Employee as an employee, temporary employee, leased employee or independent contractor for a period of two (2) years following Employee’s date of Separation from Service, unless a necessary business reason exists for rehiring Employee and a committee, comprised of (a) an officer from the business unit of the Southern Entity seeking to rehire Employee and (b) the Chief Executive Officer of the Company, approves of such rehiring.

7.    Return of Materials. By no later than the Employee’s date of Separation from Service, Employee agrees to return to the Company all property of the Company and other Southern Entities, including but not limited to data, lists, information, memoranda, documents, identification cards, parking cards, keys, computers, fax machines, beepers, phones, files and any and all written or descriptive materials of any kind belonging or relating to the Company or any other Southern Entity, including, without limitation, any originals, copies and abstracts containing any Work Product, intellectual property, Confidential Information and Trade Secrets in Employee’s possession or control.

8.    Cooperation. The parties agree that as a result of Employee’s duties and activities during his employment, Employee’s reasonable availability may be necessary for the Company to meaningfully respond to or address actual or threatened litigation, or government inquiries or investigations, or required filings with state, federal or foreign agencies (hereinafter “Company Matters”). Upon request of the Company, and at any point following Employee’s date of Separation from Service, Employee will make himself available to the Company for reasonable periods not inconsistent with his future employment, if any, by other Entities and will cooperate with the Company’s agents and attorneys as reasonably required by such Company Matters. The Company will reimburse Employee for any reasonable out-of-pocket expenses associated with providing such cooperation.

9.    Confidentiality and Legal Process. Employee represents and agrees that he will keep the terms, amount and fact of this Agreement confidential and that he will not hereafter disclose any information concerning this Agreement to anyone other than his personal agents, including, but not limited to, any past, present, or prospective employee or applicant for employment with the Company. Notwithstanding the foregoing, nothing in this Agreement is intended to prohibit Employee from performing any duty or obligation that shall arise as a matter of law. Specifically, Employee shall continue to be under a duty to truthfully respond to any legal and valid subpoena or other legal process. This Agreement is not intended in any way to proscribe Employee’s right and ability to provide information to any federal, state or local government in the lawful exercise of such governments’ governmental functions.

10.    Successors and Assigns; Applicable Law. This Agreement shall be binding upon and inure to the benefit of Employee and his heirs, administrators, representatives, executors, successors and assigns, and shall be binding upon and inure to the benefit of the Contract

Obligors and their officers, directors, employees, agents, shareholders, parent corporation, and affiliates, and their respective predecessors, successors, assigns, heirs, executors and administrators and each of them, and to their heirs, administrators, representatives, executors, successors, and assigns. This Agreement shall be construed and interpreted in accordance with the laws of the State of Georgia (without giving effect to principles of conflicts of laws), to the extent such laws are not otherwise superseded by the laws of the United States.

11.    Complete Agreement. This Agreement shall constitute the full and complete agreement between the parties concerning its subject matter and fully supersedes any and all other prior agreements or understandings between the parties concerning the subject matter hereof. This Agreement shall not be modified or amended except by a written instrument signed by both Employee and an authorized representative of the Company and Southern.

12.    Severability. The unenforceability or invalidity of any particular provision of this Agreement shall not affect its other provisions, and to the extent necessary to give such other provisions effect, they shall be deemed severable. If any of the provisions of this Agreement are determined by any court of law or equity with jurisdiction over this matter to be unreasonable or unenforceable, in whole or in part, as written, the parties hereby consent to and affirmatively request that said court reform the provision so as to be reasonable and enforceable and that said court enforce the provision as reformed. Employee acknowledges and agrees that the covenants and agreements contained in this Agreement, including, without limitation, the covenants and agreements contained in Sections 4, 5, 6, 7 and 8 shall be construed as covenants and agreements independent of each other or any other contract between the parties hereto and that the existence of any claim or cause of action by Employee, whether predicated upon this Agreement or any other contract, shall not constitute a defense to the enforcement by the Southern Parties of said covenants and agreements.

13.    Waiver of Breach; Specific Performance. The waiver of a breach of any provision of this Agreement shall not operate or be construed as a waiver of any other breach. Each of the parties to this Agreement will be entitled to enforce its or his rights under this Agreement, specifically, to recover damages by reason of any breach of any provision of this Agreement and to exercise all other rights existing in its or his favor. The parties hereto agree and acknowledge that money damages may not be an adequate remedy for any breach of the provisions of this Agreement and that any party may in its or his sole discretion apply to any court of law or equity

of competent jurisdiction for specific performance or injunctive relief in order to enforce or prevent any violations of the provisions of this Agreement.

14.    Unsecured General Creditor. The Contract Obligors shall neither reserve nor specifically set aside funds for the payment of its obligations under this Agreement, and such obligations shall be paid solely from the general assets of the Contract Obligors. Notwithstanding that Employee may be entitled to receive the value of his benefit under the terms and conditions of this Agreement, the assets from which such amount may be paid shall at all times be subject to the claims of the Contract Obligors’ creditors.

15.    No Effect on other Arrangements. It is expressly understood and agreed that the payments made in accordance with this Agreement are in addition to any other benefits or compensation to which Employee may be entitled or for which he may be eligible, whether funded or unfunded, by reason of his employment with the Contract Obligors.

16.    Tax Withholding and Implications. There shall be deducted from any payment under this Agreement the amount of any tax required by any governmental authority to be withheld and paid over by the Company to such governmental authority for the account of Employee.

17.    Notices. All notices required, necessary or desired to be given pursuant to this Agreement shall be in writing and shall be effective when delivered or on the third day following the date upon which such notice is deposited, postage prepaid, in the United States mail, certified return receipt requested, and addressed to the party at the address set forth below:

If to Employee:	If to the Company:
David Poroch<br><br>4971 Oak Trail Drive<br>Dunwoody, Georgia 30338	Patricia L. Roberts<br><br>Vice President and Associate General Counsel<br><br>Southern Company Services, Inc.<br><br>Bin # SC1204<br><br>30 Ivan Allen Jr. Blvd., NW<br><br>Atlanta, GA 30308

18.    Compensation and/or Earnings. Any compensation paid on behalf of Employee under this Agreement shall not be considered “compensation,” as such term is defined in The Southern Company Employee Savings Plan or “earnings” as such term is defined in the Pension Plan. Payments under this Agreement shall not be considered wages, salaries or compensation under any other employee benefit plan of the Company or any other Southern Entity.

19.    No Guarantee of Employment. No provision of this Agreement shall be construed to affect in any manner the existing rights of the Company to suspend, end, alter, or modify, whether or not for cause, the employment relationship of Employee and the Company.

20.    Interpretation. The judicial body interpreting this Agreement shall not more strictly construe the terms of this Agreement against one party, it being agreed that both parties and/or their attorneys or agents have negotiated and participated in the preparation hereof.

IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first above written.

THE SOUTHERN COMPANY

By: _/s/Patricia L. Roberts _____________

Its: __Assistant Secretary_______________

SOUTHERN COMPANY SERVICES, INC.

By: _/s/Patricia L. Roberts_______________

Its: __Vice President____________________

DAVID POROCH

_/s/David Poroch_______________________

Exhibit 1

FORM OF ASSIGNMENT AGREEMENT

THIS ASSIGNMENT AGREEMENT by and between Southern Company Services, Inc. (“Assignor”) and ____________________ (“Assignee”) dated this ____ day of ___________, 20__.

WHEREAS Assignor entered into that certain Deferred Compensation Agreement by and between Assignor, The Southern Company and David Poroch (“Employee”) on or about January 3, 2012 (the “DCA”);

WHEREAS Employee, Assignor and Assignee desire for Employee to transfer his employment from Assignor to Assignee; and

WHEREAS Assignor desires to assign its rights and further obligations under the DCA to Assignee and Assignee desires to accept such assignment.

NOW THEREFORE, in consideration of the premises, and the agreements of the parties set forth in this agreement, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto, intending to be legally bound, hereby covenant and agree as follows:

Pursuant to the terms of the DCA, Assignor assigns its further obligations under the DCA to Assignee and Assignee accepts such assignment; provided, however, that such assignment does not relieve Assignor of any accrued obligations to Employee or any other party under the DCA as of the date of this Assignment Agreement.

IN WITNESS WHEREOF parties hereto have executed this Agreement as follows:

ASSIGNOR

SOUTHERN COMPANY SERVICES, INC.

By: ________________________________

Its: _________________________________

Date: _______________________________

ASSIGNEE

___________COMPANY

By: ________________________________

Its: _________________________________

Date: _______________________________

13

Document

Exhibit 21(a)

Subsidiaries of the Registrant(1)

Name of Company	Jurisdiction of Organization
The Southern Company	Delaware
Alabama Power Company	Alabama
Alabama Property Company	Alabama
Southern Electric Generating Company	Alabama
Georgia Power Company	Georgia
Southern Electric Generating Company	Alabama
Mississippi Power Company	Mississippi
Southern Power Company	Delaware
SP Deuel Harvest Wind Energy Class B Holdings, LLC	Delaware
SP Deuel Harvest Wind Energy Holdings, LLC (2)	Delaware
Deuel Harvest Wind Energy Holdings, LLC (3)	Delaware
Deuel Harvest Wind Energy, LLC	Delaware
SP Diamond State Class B Holdings, LLC	Delaware
Diamond State Generation Partners, LLC (4)	Delaware
Beech Ridge Energy II Holdings, LLC (5)	Delaware
Beech Ridge Energy II, LLC	Delaware
SP Skookumchuck Investment, LLC (6)	Delaware
SP Skookumchuck Holdings, LLC (7)	Delaware
SP Skookumchuck Wind Energy Project, LLC	Delaware
Reading Wind Energy Class B Holdings, LLC	Delaware
Reading Wind Energy Holdings, LLC (8)	Delaware
Reading Wind Energy, LLC	Delaware
SP Roserock Investment, Inc.	Delaware
RE Roserock Holdings, LLC (9)	Delaware
RE Roserock LLC	Delaware
Southern Renewable Energy, Inc.	Delaware
Glass Sands Wind Energy, LLC	Delaware
SP Wildhorse Class B Holdings, LLC	Delaware
SP Wildhorse Holdings, LLC (10)	Delaware
---	---
Wildhorse Wind Energy, LLC	Delaware
SP Solar GP, Inc.	Delaware
SP Solar Holdings I, LP (11)	Delaware
SP Solar Storage Class B Holdings, LLC (12)	Delaware
SP Solar Storage OpCo, LLC (13)	Delaware
SP Garland Solar Storage, LLC	Delaware
SP Tranquillity Solar Storage, LLC	Delaware
BNB Lamesa Solar, LLC	Delaware
East Pecos Solar, LLC	Delaware
SP Butler Solar, LLC	Delaware
SP Butler Solar Farm, LLC	Delaware
SP Decatur County Solar, LLC	Delaware
SP Decatur Parkway Solar, LLC	Delaware
SP Pawpaw Solar, LLC	Delaware
SP Sandhills Solar, LLC	Delaware
SP Solar Farms, LLC	Delaware
Adobe Solar, LLC	Delaware
Apex Nevada Solar, LLC	Delaware
Calipatria, LLC	Delaware
Campo Verde Solar, LLC	Delaware
Granville Solar, LLC	Delaware
Macho Springs Solar, LLC	Delaware
Macho Springs Solar 2, LLC	Delaware
Morelos Solar, LLC	Delaware
Rutherford Farm, LLC	Delaware
Spectrum Nevada Solar, LLC	Delaware
SP Cimarron I, LLC	Delaware
SP Cimarron Capital, LLC	Delaware
Southern Renewable Partnerships, LLC	Delaware
BSP Holding Company, LLC (14)	Delaware
Boulder Solar Power Parent, LLC	Delaware
Boulder Solar Power, LLC	Delaware
---	---
Desert Stateline Holdings, LLC (15)	Delaware
Desert Stateline, LLC	Delaware
Lost Hills Blackwell Holdings, LLC (14)	Delaware
Lost Hills Solar Holdco, LLC	Delaware
Lost Hills Solar, LLC	Delaware
Blackwell Solar Holdings, LLC	Delaware
Blackwell Solar, LLC	Delaware
NS Solar Holdings, LLC (14)	Delaware
North Star Solar, LLC	Delaware
Parrey Holding Company, LLC (14)	Delaware
Parrey Parent, LLC	Delaware
Parrey, LLC	Delaware
RE Silverlake Holdings, LLC (14)	Delaware
RE Garland Holdings LLC	Delaware
RE Garland, LLC	Delaware
RE Garland A, LLC	Delaware
RE Tranquillity Holdings, LLC (14)	Delaware
RE Tranquillity, LLC	Delaware
RE Tranquillity BAAH, LLC	Delaware
SG2 Holdings, LLC (14)	Delaware
SG2 Imperial Valley LLC	Delaware
SP Wind Holdings II, LLC	Delaware
Bethel Wind Farm Class B Holdings LLC	Delaware
Bethel Wind Farm Holdings LLC	Delaware
Bethel Wind Farm LLC	Delaware
Grant Plains Wind, LLC	Delaware
Grant Wind, LLC	Delaware
Grant County Interconnect, LLC (16)	Delaware
Kay Wind, LLC	Delaware
Passadumkeag Windpark, LLC	Delaware
Salt Fork Wind, LLC	Delaware
Tyler Bluff Wind Project, LLC	Delaware
---	---
WWH LLC	Delaware
Wake Wind Class B Holdings LLC	Delaware
Wake Wind Holdings LLC	Delaware
Wake Wind Energy LLC	Delaware
SP TEP Class B Holdings I, Inc.	Delaware
SP Gaskell West 1 Class B Holdings, LLC	Delaware
SP Gaskell West 1 Holdings, LLC (17)	Delaware
RE Gaskell West 1, LLC	Delaware
SP Wind Development Holdings, LLC	Delaware
SP TEP Formations, Inc.	Delaware
SP Cactus Flats Class B Holdings, LLC	Delaware
Cactus Flats Holdings, LLC (18)	Delaware
SP Cactus Flats Wind Energy, LLC	Delaware
Millers Branch Solar, LLC	Delaware
South Cheyenne Solar, LLC	Delaware
Southern Company Gas	Georgia
Southern Company Gas Capital Corporation	Alabama
Atlanta Gas Light Company	Georgia
Georgia Natural Gas Company	Georgia
SouthStar Energy Services LLC	Delaware
Ottawa Acquisition LLC	Illinois
Northern Illinois Gas Company (19)	Illinois
Southern Company Gas Investments, Inc.	Georgia
Southern Company Gas Pipeline Holdings LLC	Georgia
Evergreen Enterprise Holdings LLC	Georgia
Virginia Natural Gas, Inc.	Georgia

(1)This information is as of December 31, 2025. In addition, this list omits certain subsidiaries pursuant to paragraph (b)(21)(ii) of Regulation S-K, Item 601.

(2)SP Deuel Harvest Wind Energy Class B Holdings, LLC and Southern Renewable Energy, Inc. own 99% and 1% of the Class B membership interests, respectively, in the tax equity partnership.

(3)SP Deuel Harvest Wind Energy Holdings, LLC owns 80%.

(4)SP Diamond State Class B Holdings, LLC owns 100% of the Class B membership interests.

(5)Southern Power Company owns 100% of the Class A membership interests and is entitled to 90% of all cash distributions.

(6)Southern Power Company owns 51%.

(7)SP Skookumchuck Investment, LLC owns 100% of the Class B membership interests in the tax equity partnership.

(8)Reading Wind Energy Class B Holdings, LLC owns 100% of the Class B membership interests in the tax equity partnership.

(9)Southern Power Company owns 100% of the Class A membership interests and is entitled to 51% of all cash distributions and SP Roserock Investment Inc. owns 100% of the Class B membership interests and is entitled to 49% of all cash distributions

(10)SP Wildhorse Class B Holdings, LLC owns 100% of the Class B membership interests in the tax equity partnership.

(11)Southern Renewable Energy, Inc. and SP Solar GP, Inc. own 66% and 1%, respectively.

(12)SP Solar Holdings I, LP and SP Solar GP, Inc. own 99% and 1% of the Class A membership interests, respectively, as well as 50% and 1% of the entirety of the entities through their Class A membership interests, respectively.

(13)SP Solar Storage Class B Holdings, LLC owns 100% of the Class B membership interests in the tax equity partnership.

(14)Southern Renewable Partnerships, LLC owns 100% of the Class A membership interests and is entitled to 51% of all cash distributions.

(15)Southern Renewable Partnerships, LLC owns 100% of the Class A membership interests and is entitled to 66% of all cash distributions.

(16)Grant Wind, LLC and Grant Plains Wind, LLC own 50.4% and 49.6%, respectively.

(17)SP Gaskell West 1 Class B Holdings, LLC owns 100% of the Class B membership interests in the tax equity partnership.

(18)SP Cactus Flats Class B Holdings, LLC and SP TEP Class B Holdings I, Inc. own 95% and 5%, respectively, of the Class B membership interests in the tax equity partnership.

(19)Doing business as Nicor Gas Company.

Document

Exhibit 23(a)1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 2-78617, 33-54415, 33-58371, 33-60427, 333-44127, 333-118061, 333-166709, 333-174704, 333-174707, 333-204618, 333-212783, 333-229841, 333-237951, 333-256558, and 333-279103 on Form S-8 and Registration Statement Nos. 333-277137 and 333-277138 on Form S-3 of our reports dated February 18, 2026, relating to the financial statements of The Southern Company, and the effectiveness of The Southern Company’s internal control over financial reporting, appearing in this Annual Report on Form 10-K for the year ended December 31, 2025.

/s/ Deloitte & Touche LLP

Atlanta, Georgia February 18, 2026

Document

Exhibit 23(b)1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-269983 on Form S-3 of our report dated February 18, 2026, relating to the financial statements of Alabama Power Company, appearing in this Annual Report on Form 10-K for the year ended December 31, 2025.

/s/ Deloitte & Touche LLP

Birmingham, Alabama February 18, 2026

Document

Exhibit 23(c)1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-285111 on Form S-3 of our report dated February 18, 2026, relating to the financial statements of Georgia Power Company, appearing in this Annual Report on Form 10-K for the year ended December 31, 2025.

/s/ Deloitte & Touche LLP

Atlanta, Georgia February 18, 2026

Document

Exhibit 23(d)1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-273697 on Form S-3 of our report dated February 18, 2026, relating to the financial statements of Mississippi Power Company, appearing in this Annual Report on Form 10-K for the year ended December 31, 2025.

/s/ Deloitte & Touche LLP

Atlanta, Georgia February 18, 2026

Document

Exhibit 23(e)1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-289172 on Form S-3 of our report dated February 18, 2026, relating to the financial statements of Southern Power Company, appearing in this Annual Report on Form 10-K for the year ended December 31, 2025.

/s/ Deloitte & Touche LLP

Atlanta, Georgia February 18, 2026

Document

Exhibit 23(f)1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-285115 on Form S-3 and Registration Statement Nos. 333-26963 and 333-154965 on Form S-8 of our report dated February 18, 2026, relating to the financial statements of Southern Company Gas, appearing in this Annual Report on Form 10-K for the year ended December 31, 2025.

/s/ Deloitte & Touche LLP

Atlanta, Georgia February 18, 2026

Document

Exhibit 23(f)2

Consent of Independent Registered Public Accounting Firm

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-285115) and Form S-8 (No. 333-26963 and 333-154965) of Southern Company Gas of our report dated February 5, 2026, relating to the consolidated financial statements of Southern Natural Gas Company, L.L.C., which appears in this Annual Report on Form 10-K of Southern Company Gas.

/s/ BDO USA, P.C.

Houston, Texas

February 18, 2026

Document

Exhibit 24(a)1

December 8, 2025

Laura O. Hewett and Melissa K. Caen

Ms. Hewett and Ms. Caen:

The Southern Company (the “Company”) proposes to file or join in the filing of reports under the Securities Exchange Act of 1934, as amended, with the Securities and Exchange Commission with respect to the following: (1) the Company’s Annual Report on Form 10-K for the year ended December 31, 2025 and (2) the Company’s Quarterly Reports on Form 10-Q during 2026.

The Company and the undersigned directors and officers of the Company, individually as a director and/or as an officer of the Company, hereby make, constitute and appoint each of you our true and lawful Attorney for each of us and in each of our names, places and steads to sign and cause to be filed with the Securities and Exchange Commission in connection with the foregoing said Annual Report on Form 10-K, said Quarterly Reports on Form 10-Q and any necessary or appropriate amendment or amendments to any such reports, to be accompanied in each case by any necessary or appropriate exhibits or schedules thereto.

Yours very truly,
THE SOUTHERN COMPANY
By	/s/Christopher C. Womack
	Christopher C. Womack<br><br>Chairman, President and<br><br>Chief Executive Officer

• 2 -

/s/Janaki Akella	/s/David E. Meador
Janaki Akella	David E. Meador
/s/Shantella E. Cooper	/s/William G. Smith, Jr.
Shantella E. Cooper	William G. Smith, Jr
/s/Anthony F. Earley, Jr.	/s/Kristine L. Svinicki
Anthony F. Earley, Jr.	Kristine L. Svinicki
/s/James O. Etheredge	/s/Lizanne Thomas
James O. Etheredge	Lizanne Thomas
/s/David J. Grain	/s/John M. Turner, Jr.
David J. Grain	John M. Turner, Jr.
/s/Donald M. James	/s/Christopher C. Womack
Donald M. James	Christopher C. Womack
/s/John D. Johns	/s/David P. Poroch
John D. Johns	David P. Poroch
/s/Dale E. Klein	/s/Matthew M. Kim
Dale E. Klein	Matthew M. Kim

-3-

Extract from minutes of meeting of the board of directors of The Southern Company.

---

RESOLVED: That for the purpose of signing the reports under the Securities Exchange Act of 1934 to be filed with the Securities and Exchange Commission with respect to the filing of the Company’s Annual Report on Form 10-K for the year ended December 31, 2025 and its 2026 Quarterly Reports on Form 10-Q, and any necessary or appropriate amendment or amendments to any such reports, the Company, the members of its Board of Directors and its officers be and hereby are authorized to give their several powers of attorney to Laura O. Hewett and Melissa K. Caen.

---

The undersigned officer of The Southern Company does hereby certify that the foregoing is a true and correct copy of a resolution duly and regularly adopted at a meeting of the board of directors of The Southern Company, duly held on December 8, 2025, at which a quorum was in attendance and voting throughout, and that said resolution has not since been rescinded but is still in full force and effect.

Dated: February 18, 2026	THE SOUTHERN COMPANY
	By	/s/Melissa K. Caen
		Melissa K. Caen<br>Assistant Secretary

Document

Exhibit 24(b)1

600 North 18th Street<br><br>Post Office Box 2641<br><br>Birmingham, Alabama 35291-0001<br><br><br><br>Tel   205 257 1000

January 23, 2026

David P. Poroch	Melissa K. Caen
30 Ivan Allen Jr. Blvd., N.W.	30 Ivan Allen Jr. Blvd., N.W.
Atlanta, Georgia 30308	Atlanta, Georgia 30308

Dear Mr. Poroch and Ms. Caen:

Alabama Power Company (the “Company”) proposes to file or join in the filing of reports under the Securities Exchange Act of 1934, as amended, with the Securities and Exchange Commission with respect to the following: (1) the Company’s Annual Report on Form 10-K for the year ended December 31, 2025 and (2) the Company’s Quarterly Reports on Form 10-Q during 2026.

The Company and the undersigned directors and officers of the Company, individually as a director and/or as an officer of the Company, hereby make, constitute and appoint each of you our true and lawful Attorney for each of us and in each of our names, places and steads to sign and cause to be filed with the Securities and Exchange Commission in connection with the foregoing said Annual Report on Form 10-K, said Quarterly Reports on Form 10-Q and any necessary or appropriate amendment or amendments to any such reports, to be accompanied in each case by any necessary or appropriate exhibits or schedules thereto.

Yours very truly,
ALABAMA POWER COMPANY
By	/s/J. Jeffrey Peoples
	J. Jeffrey Peoples<br><br>Chairman, President and<br><br>Chief Executive Officer

• 2 -

/s/Angus R. Cooper, III	/s/Kevin B. Savoy
Angus R. Cooper, III	Kevin B. Savoy
/s/Lee C. Goodloe	/s/Charisse D. Stokes
Lee C. Goodloe	Charisse D. Stokes
/s/O. B. Grayson Hall, Jr.	/s/Phillip M. Webb
O. B. Grayson Hall, Jr.	Phillip M. Webb
/s/Larry R. Howell, Jr.	/s/William B. Wilson
Larry R. Howell, Jr.	William B. Wilson
/s/Anthony A. Joseph	/s/Moses H. Feagin
Anthony A. Joseph	Moses H. Feagin
/s/Barbara J. Knight	/s/Anita D. Allcorn
Barbara J. Knight	Anita D. Allcorn
/s/J. Jeffrey Peoples
J. Jeffrey Peoples

-3-

Extract from minutes of meeting of the board of directors of Alabama Power Company.

---

RESOLVED: That for the purpose of signing the reports under the Securities Exchange Act of 1934 to be filed with the Securities and Exchange Commission with respect to the filing of this Company’s Annual Report on Form 10-K for the year ended December 31, 2025 and its 2026 Quarterly Reports on Form 10-Q, and any necessary or appropriate amendment or amendments to any such reports, this Company, the members of its board of directors and its officers are authorized to give their several powers of attorney to David P. Poroch and Melissa K. Caen.

---

The undersigned officer of Alabama Power Company does hereby certify that the foregoing is a true and correct copy of a resolution duly and regularly adopted at a meeting of the board of directors of Alabama Power Company, duly held on January 23, 2026, at which a quorum was in attendance and voting throughout, and that said resolution has not since been rescinded but is still in full force and effect.

Dated: February 18, 2026	ALABAMA POWER COMPANY
	By	/s/Melissa K. Caen
		Melissa K. Caen<br>Assistant Secretary

Document

Exhibit 24(c)1

November 19, 2025

Tyler M. Cook, David P. Poroch and Melissa K. Caen

Ladies and Mr. Poroch:

Georgia Power Company (the “Company”) proposes to file or join in the filing of reports under the Securities Exchange Act of 1934, as amended, with the Securities and Exchange Commission with respect to the following: (1) the Company’s Annual Report on Form 10-K for the year ended December 31, 2025 and (2) the Company’s Quarterly Reports on Form 10-Q during 2026.

The Company and the undersigned directors and officers of the Company, individually as a director and/or as an officer of the Company, hereby make, constitute and appoint each of you our true and lawful Attorney for each of us and in each of our names, places and steads to sign and cause to be filed with the Securities and Exchange Commission in connection with the foregoing said Annual Report on Form 10-K, said Quarterly Reports on Form 10-Q and any necessary or appropriate amendment or amendments to any such reports, to be accompanied in each case by any necessary or appropriate exhibits or schedules thereto.

Yours very truly,
GEORGIA POWER COMPANY
By	/s/Kimberly S. Greene
	Kimberly S. Greene<br><br>Chairman, President and Chief Executive Officer

• 2 -

/s/Jill Bullock	/s/Virgil R. Miller
Jill Bullock	Virgil R. Miller
/s/Mark L. Burns	/s/Valerie Montgomery Rice
Mark L. Burns	Valerie Montgomery Rice
/s/Andrew W. Evans	/s/Tonialo Smith
Andrew W. Evans	Tonialo Smith
/s/Steven R. Ewing	/s/Kessel D. Stelling, Jr.
Steven R. Ewing	Kessel D. Stelling, Jr.
/s/Kimberly S. Greene	/s/Tyler M. Cook
Kimberly S. Greene	Tyler M. Cook
/s/Thomas M. Holder	/s/Adam D. Houston
Thomas M. Holder	Adam D. Houston

• 3 -

Extract from unanimous written consent of the board of directors of Georgia Power Company.

---

RESOLVED: That for the purpose of signing the reports under the Securities Exchange Act of 1934 to be filed with the Securities and Exchange Commission with respect to the filing of this Company’s Annual Report on Form 10-K for the year ended December 31, 2025 and its 2026 Quarterly Reports on Form 10-Q, and any necessary or appropriate amendment or amendments to any such reports, the Company, the members of its board of directors and its officers are authorized to give their several powers of attorney to Tyler M. Cook, David P. Poroch and Melissa K. Caen.

---

The undersigned officer of Georgia Power Company does hereby certify that the foregoing is a true and correct copy of a resolution duly and regularly adopted at a meeting of the board of directors of Georgia Power Company, duly held on November 19, 2025, at which a quorum was in attendance and voting throughout, and that said resolution has not since been rescinded but is still in full force and effect.

Dated: February 18, 2026	GEORGIA POWER COMPANY
	By	/s/Melissa K. Caen
		Melissa K. Caen<br>Assistant Secretary

Document

Exhibit 24(d)1

October 20, 2025

Mr. David P. Poroch<br><br>The Southern Company<br><br>30 Ivan Allen Jr. Blvd., NW<br><br>Atlanta, GA 30308	Ms. Melissa K. Caen<br><br>Southern Company Services, Inc.<br><br>30 Ivan Allen Jr. Blvd., NW<br><br>Atlanta, GA 30308

Mr. Poroch and Ms. Caen:

Mississippi Power Company (the “Company”) proposes to file or join in the filing of reports under the Securities Exchange Act of 1934, as amended, with the Securities and Exchange Commission with respect to the following: (1) the Company’s Annual Report on Form 10-K for the year ended December 31, 2025 and (2) the Company’s Quarterly Reports on Form 10-Q during 2026.

The Company and the undersigned directors and officers of the Company, individually as a director and/or as an officer of the Company, hereby make, constitute and appoint each of you our true and lawful Attorney for each of us and in each of our names, places and steads to sign and cause to be filed with the Securities and Exchange Commission in connection with the foregoing said Annual Report on Form 10-K, said Quarterly Reports on Form 10-Q and any necessary or appropriate amendment or amendments to any such reports, to be accompanied in each case by any necessary or appropriate exhibits or schedules thereto.

Yours very truly,

MISSISSIPPI POWER COMPANY
By	/s/Pedro P. Cherry
	Pedro P. Cherry<br><br>Chairman, President and Chief<br><br>Executive Officer

• 2 -

/s/Pedro P. Cherry	/s/Kara R. Wilkinson
Pedro P. Cherry	Kara R. Wilkinson
/s/Augustus Leon Collins	/s/Camille Scales Young
Augustus Leon Collins	Camille Scales Young
/s/Thomas M. Duff	/s/Matthew P. Grice
Thomas M. Duff	Matthew P. Grice
/s/Mary S. Graham	/s/Shawn S. Shurden
Mary S. Graham	Shawn S. Shurden
/s/David B. Hall	/s/Pascal B. Gill
David B. Hall	Pascal B. Gill
/s/Mark E. Keenum
Mark E. Keenum

• 3 -

Extract from minutes of meeting of the board of directors of Mississippi Power Company.

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RESOLVED, That for the purpose of signing the reports under the Securities Exchange Act of 1934, as amended, to be filed with the Securities and Exchange Commission with respect to the filing of the Company’s Annual Report on Form 10-K for the year ended December 31, 2025 and its 2026 Quarterly Reports on Form 10-Q, and any necessary or appropriate amendment or amendments to any such reports, the Company, the members of its board of directors and its officers are authorized to give their several powers of attorney to David P. Poroch and Melissa K. Caen.

---

The undersigned officer of Mississippi Power Company does hereby certify that the foregoing is a true and correct copy of a resolution duly and regularly adopted at a meeting of the board of directors of Mississippi Power Company, duly held on October 20, 2025, at which a quorum was in attendance and voting throughout, and that said resolution has not since been rescinded but is still in full force and effect.

Dated: February 18, 2026	MISSISSIPPI POWER COMPANY
	By	/s/Melissa K. Caen
		Melissa K. Caen<br>Assistant Secretary

Document

Exhibit 24(e)1

November 3, 2025

Mr. Gary Kerr<br><br>Southern Power Company<br><br>3535 Colonnade Parkway<br><br>Birmingham, AL 35243	Mr. D. Matt Madison<br><br>Southern Power Company<br><br>3535 Colonnade Parkway<br><br>Birmingham, AL 35243	Ms. Melissa K. Caen<br><br>Southern Company Services, Inc.<br><br>30 Ivan Allen Jr. Blvd, NW<br><br>Atlanta, GA 30308

Mr. Kerr, Mr. Madison and Ms. Caen:

Southern Power Company (the “Company”) proposes to file or join in the filing of reports under the Securities Exchange Act of 1934, as amended, with the Securities and Exchange Commission with respect to the following: (1) the Company’s Annual Report on Form 10-K for the year ended December 31, 2025 and (2) the Company’s Quarterly Reports on Form 10-Q during 2026.

The Company and the undersigned directors and officers of the Company, individually as a director and/or as an officer of the Company, hereby make, constitute and appoint each of you our true and lawful Attorney for each of us and in each of our names, places and steads to sign and cause to be filed with the Securities and Exchange Commission in connection with the foregoing said Annual Report on Form 10-K, said Quarterly Reports on Form 10-Q and any necessary or appropriate amendment or amendments to any such reports, to be accompanied in each case by any necessary or appropriate exhibits or schedules thereto.

Yours very truly,
SOUTHERN POWER COMPANY
By	/s/Christopher Cummiskey
	Christopher Cummiskey<br><br>Chairman and Chief Executive Officer

• 2 -

/s/Bryan D. Anderson	/s/Sterling A. Spainhour
Bryan D. Anderson	Sterling A. Spainhour
/s/Stanley W. Connally, Jr.	/s/Christopher C Womack
Stanley W. Connally, Jr.	Christopher C. Womack
/s/Christopher Cummiskey	/s/Gary Kerr
Christopher Cummiskey	Gary Kerr
/s/Sloane N. Drake	/s/Jelena Andrin
Sloane N. Drake	Jelena Andrin
/s/James Y. Kerr II	/s/D. Matt Madison
James Y. Kerr II	D. Matt Madison
/s/David P. Poroch
David P. Poroch

-3-

Extract from minutes of meeting of the board of directors of Southern Power Company.

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RESOLVED: That for the purpose of signing the reports under the Securities Exchange Act of 1934 to be filed with the Securities and Exchange Commission with respect to the filing of the Company’s Annual Report on Form 10-K for the year ended December 31, 2025 and its 2026 Quarterly Reports on Form 10-Q, and any necessary or appropriate amendment or amendments to any such reports, the Company, the members of its board of directors and its officers are authorized to give their several powers of attorney to Gary Kerr, D. Matt Madison and Melissa K. Caen.

---

The undersigned officer of Southern Power Company does hereby certify that the foregoing is a true and correct copy of a resolution duly and regularly adopted at a meeting of the board of directors of Southern Power Company, duly held on November 3, 2025, at which a quorum was in attendance and voting throughout, and that said resolution has not since been rescinded but is still in full force and effect.

Dated: February 18, 2026	SOUTHERN POWER COMPANY
	By	/s/Melissa K. Caen
		Melissa K. Caen<br><br>Assistant Secretary

Document

Exhibit 24(f)1

October 22, 2025

Laura O. Hewett and Melissa K. Caen

Ms. Hewett and Ms. Caen:

Southern Company Gas (the “Company”) proposes to file or join in the filing of reports under the Securities Exchange Act of 1934, as amended, with the Securities and Exchange Commission with respect to the following: (1) the Company’s Annual Report on Form 10-K for the year ended December 31, 2025 and (2) the Company’s Quarterly Reports on Form 10-Q during 2026.

The Company and the undersigned directors and officers of the Company, individually as a director and/or as an officer of the Company, hereby make, constitute and appoint each of you our true and lawful Attorney for each of us and in each of our names, places and steads to sign and cause to be filed with the Securities and Exchange Commission in connection with the foregoing said Annual Report on Form 10-K, said Quarterly Reports on Form 10-Q and any necessary or appropriate amendment or amendments to any such reports, to be accompanied in each case by any necessary or appropriate exhibits or schedules thereto.

Yours very truly,
SOUTHERN COMPANY GAS
By	/s/James Y. Kerr II
	James Y. Kerr II<br><br>Chairman, President and<br><br>Chief Executive Officer

• 2 -

/s/Sandra N. Bane	/s/J. Bret Lane
Sandra N. Bane	J. Bret Lane
/s/Stephen A. Edwards	/s/Eric S. Smith
Stephen A. Edwards	Eric S. Smith
/s/Vanessa C. Harrison	/s/A. Benjamin Spencer
Vanessa C. Harrison	'A. Benjamin Spencer
/s/Bradley J. Henderson	/s/Grace A. Kolvereid
Bradley J. Henderson	Grace A. Kolvereid
/s/Norman G. Holmes	/s/Sarah P. Adams
Norman G. Holmes	Sarah P. Adams
/s/James Y. Kerr II	/s/Marcia R. DeMar
James Y. Kerr II	Marcia R. DeMar

-3-

Extract from minutes of meeting of the board of directors of Southern Company Gas.

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RESOLVED: That for the purpose of signing the reports under the Securities Exchange Act of 1934 to be filed with the Securities and Exchange Commission with respect to the filing of the Company’s Annual Report on Form 10-K for the year ended December 31, 2025 and its 2026 Quarterly Reports on Form 10-Q, and any necessary or appropriate amendment or amendments to any such reports, the Company, the members of its Board of Directors and its officers be and hereby are authorized to give their several powers of attorney to Laura O. Hewett and Melissa K. Caen.

---

The undersigned officer of Southern Company Gas does hereby certify that the foregoing is a true and correct copy of a resolution duly and regularly adopted at a meeting of the board of directors of Southern Company Gas, duly held on October 22, 2025, at which a quorum was in attendance and voting throughout, and that said resolution has not since been rescinded but is still in full force and effect.

Dated: February 18, 2026	SOUTHERN COMPANY GAS
	By	/s/Melissa K. Caen
		Melissa K. Caen<br>Assistant Secretary

Document

Exhibit 31(a)1

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Christopher C. Womack, certify that:

1.I have reviewed this annual report on Form 10-K of The Southern Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  February 18, 2026

/s/Christopher C. Womack
Christopher C. Womack
Chairman, President and<br>Chief Executive Officer

Document

Exhibit 31(a)2

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, David P. Poroch, certify that:

1.I have reviewed this annual report on Form 10-K of The Southern Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 18, 2026

/s/David P. Poroch
David P. Poroch
Executive Vice President and<br> Chief Financial Officer

Document

Exhibit 31(b)1

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, J. Jeffrey Peoples, certify that:

1.I have reviewed this annual report on Form 10-K of Alabama Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  February 18, 2026

/s/J. Jeffrey Peoples
J. Jeffrey Peoples
Chairman, President and Chief Executive Officer

Document

Exhibit 31(b)2

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Moses H. Feagin, certify that:

1.I have reviewed this annual report on Form 10-K of Alabama Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  February 18, 2026

/s/Moses H. Feagin
Moses H. Feagin
Executive Vice President, Chief Financial Officer<br>and Treasurer

Document

Exhibit 31(c)1

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Kimberly S. Greene, certify that:

1.I have reviewed this annual report on Form 10-K of Georgia Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 18, 2026

/s/Kimberly S. Greene
Kimberly S. Greene
Chairman, President and Chief Executive Officer

Document

Exhibit 31(c)2

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Tyler M. Cook, certify that:

1.I have reviewed this annual report on Form 10-K of Georgia Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  February 18, 2026

/s/Tyler M. Cook
Tyler M. Cook
Senior Vice President, Chief Financial Officer and Treasurer

Document

Exhibit 31(d)1

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Pedro P. Cherry, certify that:

1.I have reviewed this annual report on Form 10-K of Mississippi Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 18, 2026

/s/Pedro P. Cherry
Pedro P. Cherry
Chairman, President and Chief Executive Officer

Document

Exhibit 31(d)2

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Matthew P. Grice, certify that:

1.I have reviewed this annual report on Form 10-K of Mississippi Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 18, 2026

/s/Matthew P. Grice
Matthew P. Grice
Vice President, Treasurer and<br>Chief Financial Officer

Document

Exhibit 31(e)1

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Christopher Cummiskey, certify that:

1.I have reviewed this annual report on Form 10-K of Southern Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  February 18, 2026

/s/Christopher Cummiskey
Christopher Cummiskey
Chairman and Chief Executive Officer

Document

Exhibit 31(e)2

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Gary Kerr, certify that:

1.I have reviewed this annual report on Form 10-K of Southern Power Company;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 18, 2026

/s/Gary Kerr
Gary Kerr
Senior Vice President, Chief<br>Financial Officer and Treasurer

Document

Exhibit 31(f)1

SOUTHERN COMPANY GAS

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, James Y. Kerr II, certify that:

1.I have reviewed this annual report on Form 10-K of Southern Company Gas;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 18, 2026

/s/James Y. Kerr II
James Y. Kerr II
Chairman, President and Chief<br><br>Executive Officer

Document

Exhibit 31(f)2

SOUTHERN COMPANY GAS

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Grace A. Kolvereid, certify that:

1.I have reviewed this annual report on Form 10-K of Southern Company Gas;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 18, 2026

/s/Grace A. Kolvereid
Grace A. Kolvereid
Executive Vice President, Chief Financial<br>Officer and Treasurer

Document

Exhibit 32(a)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Annual Report on Form 10-K of The Southern Company for the year ended December 31, 2025, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)such Annual Report on Form 10-K of The Southern Company for the year ended December 31, 2025, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in such Annual Report on Form 10-K of The Southern Company for the year ended December 31, 2025, fairly presents, in all material respects, the financial condition and results of operations of The Southern Company.

/s/Christopher C. Womack
Christopher C. Womack
Chairman, President and<br>Chief Executive Officer
/s/David P. Poroch
David P. Poroch
Executive Vice President and Chief Financial<br> Officer

February 18, 2026

Document

Exhibit 32(b)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Annual Report on Form 10-K of Alabama Power Company for the year ended December 31, 2025, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)such Annual Report on Form 10-K of Alabama Power Company for the year ended December 31, 2025, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in such Annual Report on Form 10-K of Alabama Power Company for the year ended December 31, 2025, fairly presents, in all material respects, the financial condition and results of operations of Alabama Power Company.

/s/J. Jeffrey Peoples
J. Jeffrey Peoples
Chairman, President and Chief Executive Officer
/s/Moses H. Feagin
Moses H. Feagin
Executive Vice President,<br>Chief Financial Officer and Treasurer

February 18, 2026

Document

Exhibit 32(c)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Annual Report on Form 10-K of Georgia Power Company for the year ended December 31, 2025, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)such Annual Report on Form 10-K of Georgia Power Company for the year ended December 31, 2025, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in such Annual Report on Form 10-K of Georgia Power Company for the year ended December 31, 2025, fairly presents, in all material respects, the financial condition and results of operations of Georgia Power Company.

/s/Kimberly S. Greene
Kimberly S. Greene
Chairman, President and Chief Executive Officer
/s/Tyler M. Cook
Tyler M. Cook
Senior Vice President, Chief Financial Officer and Treasurer

February 18, 2026

Document

Exhibit 32(d)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Annual Report on Form 10-K of Mississippi Power Company for the year ended December 31, 2025, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)such Annual Report on Form 10-K of Mississippi Power Company for the year ended December 31, 2025, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in such Annual Report on Form 10-K of Mississippi Power Company for the year ended December 31, 2025, fairly presents, in all material respects, the financial condition and results of operations of Mississippi Power Company.

/s/Pedro P. Cherry
Pedro P. Cherry
Chairman, President and Chief Executive Officer
/s/Matthew P. Grice
Matthew P. Grice
Vice President, Treasurer and<br>Chief Financial Officer

February 18, 2026

Document

Exhibit 32(e)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Annual Report on Form 10-K of Southern Power Company for the year ended December 31, 2025, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)such Annual Report on Form 10-K of Southern Power Company for the year ended December 31, 2025, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in such Annual Report on Form 10-K of Southern Power Company for the year ended December 31, 2025, fairly presents, in all material respects, the financial condition and results of operations of Southern Power Company.

/s/Christopher Cummiskey
Christopher Cummiskey
Chairman and Chief Executive Officer
/s/Gary Kerr
Gary Kerr
Senior Vice President, Chief Financial Officer and Treasurer

February 18, 2026

Document

Exhibit 32(f)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Annual Report on Form 10-K of Southern Company Gas for the year ended December 31, 2025, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1)such Annual Report on Form 10-K of Southern Company Gas for the year ended December 31, 2025, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)the information contained in such Annual Report on Form 10-K of Southern Company Gas for the year ended December 31, 2025, fairly presents, in all material respects, the financial condition and results of operations of Southern Company Gas.

/s/James Y. Kerr II
James Y. Kerr II
Chairman, President and Chief Executive Officer
/s/Grace A. Kolvereid
Grace A. Kolvereid
Executive Vice President, Chief Financial<br><br>Officer and Treasurer

February 18, 2026