UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

FORM 10-K

(Mark One)

☒ 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	Registrants;						I.R.S. Employer
File Number	Address and Telephone Number					States of Incorporation	Identification Nos.
1-3525	AMERICAN ELECTRIC POWER CO INC.					New York	13-4922640
333-221643	AEP TEXAS INC.					Delaware	51-0007707
333-217143	AEP TRANSMISSION COMPANY, LLC					Delaware	46-1125168
1-3457	APPALACHIAN POWER COMPANY					Virginia	54-0124790
1-3570	INDIANA MICHIGAN POWER COMPANY					Indiana	35-0410455
1-6543	OHIO POWER COMPANY					Ohio	31-4271000
0-343	PUBLIC SERVICE COMPANY OF OKLAHOMA					Oklahoma	73-0410895
1-3146	SOUTHWESTERN ELECTRIC POWER COMPANY					Delaware	72-0323455
	1 Riverside Plaza,		Columbus,	Ohio	43215-2373
	Telephone	(614)	716-1000

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

Registrant	Title of each class	Trading Symbol	Name of Each Exchange on Which Registered
American Electric Power Company Inc.	Common Stock, $6.50 par value	AEP	The NASDAQ Stock Market LLC

Securities registered pursuant to Section 12(g) of the Act:  None

Indicate by check mark if AEP Texas Inc., AEP Transmission Company, LLC and Public Service Company of Oklahoma, are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.	Yes	x	No	¨
Indicate by check mark if American Electric Power Company, Inc., Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company and Southwestern Electric Power Company are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.	Yes	¨	No	x
Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.	Yes	¨	No	x
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 (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).	Yes	x	No	¨

Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large Accelerated filer	x	Accelerated filer	☐	Non-accelerated filer	☐
Smaller reporting company	☐	Emerging growth company	☐

Indicate by check mark whether AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers, smaller reporting companies, or emerging growth companies.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large Accelerated filer	☐	Accelerated filer	☐	Non-accelerated filer	x
Smaller reporting company	☐	Emerging growth company	☐

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
	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 registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No x

AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to such Form 10-K.

	Aggregate Market Value of Voting and Non-Voting Common Equity Held by Nonaffiliates of the Registrants as of June 30, 2025 the Last Trading Date of the Registrants' Most Recently Completed Second Fiscal Quarter	Number of Shares of Common Stock Outstanding of the Registrants as of December 31, 2025
American Electric Power Company, Inc.	$56,119,786,438	540,861,473
		($6.50 par value)
AEP Texas Inc.	None	100
		($0.01 par value)
AEP Transmission Company, LLC (a)	None	NA
Appalachian Power Company	None	13,499,500
		(no par value)
Indiana Michigan Power Company	None	1,400,000
		(no par value)
Ohio Power Company	None	27,952,473
		(no par value)
Public Service Company of Oklahoma	None	9,013,000
		($15 par value)
Southwestern Electric Power Company	None	3,680
		($18 par value)

(a)100% interest is held by AEP Transmission Holdco.

NA    Not applicable.

Note on Market Value of Common Equity Held by Nonaffiliates

American Electric Power Company, Inc. owns all of the common stock of AEP Texas Inc., Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company and, indirectly, all of the LLC membership interest in AEP Transmission Company, LLC (see Item 12 herein).

Documents Incorporated By Reference

Description	Part of Form 10-K into which Document is Incorporated
Portions of Proxy Statement of American Electric Power Company, Inc. for 2026 Annual Meeting of Shareholders.	Part III

This combined Form 10-K is separately filed by American Electric Power Company, Inc., AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company.  Information contained herein relating to any individual registrant is filed by such registrant on its own behalf.  Except for American Electric Power Company, Inc., each registrant makes no representation as to information relating to the other registrants.

You can access financial and other information at AEP’s website, including AEP’s Principles of Business Conduct, certain committee charters and Principles of Corporate Governance.  The address is www.AEP.com.  Investors can obtain copies of our SEC filings from this site free of charge, as well as from the SEC website at www.sec.gov.

TABLE OF CONTENTS

Item Number		Page Number
	Glossary of Terms	i
	Forward-Looking Information	vii
PART I
1	Business
	General	1
	Business Segments	6
	Vertically Integrated Utilities	6
	Transmission and Distribution Utilities	13
	AEP Transmission Holdco	14
	Generation & Marketing	17
	Executive Officers of AEP	18
1A	Risk Factors	19
1B	Unresolved Staff Comments	31
1C	Cybersecurity	31
2	Properties	33
	Generation Facilities	33
	Transmission and Distribution Facilities	35
	Title to Property	35
	System Transmission Lines and Facility Siting	35
	Construction Program	36
	Potential Uninsured Losses	36
3	Legal Proceedings	37
4	Mine Safety Disclosure	37
PART II
5	Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	38
6	Reserved	39
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
7A	Quantitative and Qualitative Disclosures about Market Risk	39
8	Financial Statements and Supplementary Data	39
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	337
9A	Controls and Procedures	337
9B	Other Information	337
9C	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	337
	PART III
10	Directors, Executive Officers and Corporate Governance	338
11	Executive Compensation	338
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	339
13	Certain Relationships and Related Transactions and Director Independence	339
14	Principal Accounting Fees and Services	340
PART IV
15	Exhibits and Financial Statement Schedules
	Financial Statements	341
16	Form 10-K Summary	342
	Signatures	343
	Index of Financial Statement Schedules	S-1
	Exhibit Index	E-1

GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.

Term	Meaning
AEGCo	AEP Generating Company, an AEP electric utility subsidiary.
AEP	American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit	AEP Credit, Inc., a consolidated VIE of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP Development Services, LLC	AEP Development Services, LLC, a consolidated VIE of AEP formed for the purpose of developing, constructing, and installing energy projects for the regulated operating companies of AEP.
AEP East Companies	APCo, I&M, KGPCo, KPCo, OPCo and WPCo.
AEP Energy	AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.
AEP Energy Supply, LLC	A nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
AEP OnSite Partners	A former division of AEP Energy Supply, LLC that builds, owns, operates and maintains customer solutions utilizing existing and emerging distributed technologies.
AEP Renewables	A former division of AEP Energy Supply, LLC that develops and/or acquires large scale renewable projects that are backed with long-term contracts with creditworthy counter parties.
AEP System	American Electric Power System, an electric system, owned and operated by AEP subsidiaries.
AEP Texas	AEP Texas Inc., an AEP electric utility subsidiary. AEP Texas engages in the transmission and distribution of electric power to retail customers in west, central and southern Texas.
AEP Transmission Holdco / AEPTHCo	AEP Transmission Holding Company, LLC, a subsidiary of AEP, an intermediate holding company that owns transmission operations joint ventures and AEPTCo.
AEPEP	AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in deregulated markets.
AEPSC	American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo	AEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, is an intermediate holding company that owns the State Transcos.
AEPTCo Parent	AEP Transmission Company, LLC, the holding company of Midwest Transmission Holdings and the State Transcos within the AEPTCo consolidation.
AFUDC	Allowance for Funds Used During Construction.
AGR	AEP Generation Resources Inc., a competitive AEP subsidiary in the Generation & Marketing segment.
AI	Artificial Intelligence.
ALJ	Administrative Law Judge.
AOCI	Accumulated Other Comprehensive Income.
APCo	Appalachian Power Company, an AEP electric utility subsidiary. APCo engages in the generation, transmission and distribution of electric power to retail customers in the southwestern portion of Virginia and southern West Virginia.
Appalachian Consumer Rate Relief Funding	Appalachian Consumer Rate Relief Funding, LLC, a wholly-owned subsidiary of APCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance.
APSC	Arkansas Public Service Commission.
APTCo	AEP Appalachian Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
ARO	Asset Retirement Obligations.
ASU	Accounting Standards Update.
ATM	At-the-Market.
BESS	Battery Energy Storage System.

i

Term	Meaning
BHE	Berkshire Hathaway Energy.
CAA	Clean Air Act.
CAMT	Corporate Alternative Minimum Tax.
CCN	Certificate of Convenience and Necessity.
CCR	Coal Combustion Residual.
CEO	Chief Executive Officer.
CLECO	Central Louisiana Electric Company, a nonaffiliated utility company.
CO2	Carbon dioxide and other greenhouse gases.
CODM	Chief Operating Decision Maker.
Cook Plant	Donald C. Cook Nuclear Plant, a two-unit, 2,296 MW nuclear plant owned by I&M.
Cost Recovery Funding	KPCo Cost Recovery Funding, LLC, a wholly-owned subsidiary of KPCo and consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to plant retirement costs, deferred storm costs, deferred purchased power expenses, under-recovered purchased power rider costs and issuance-related expenses.
CPCN	Certificate of Public Convenience and Necessity.
CRES Provider	Competitive Retail Electric Service providers under Ohio law that target retail customers by offering alternative generation service.
CSAPR	Cross-State Air Pollution Rule.
CSPCo	Columbus Southern Power Company, a former AEP electric utility subsidiary that was merged into OPCo effective December 31, 2011.
CWIP	Construction Work in Progress.
DCC Fuel	DCC Fuel XVII, DCC Fuel XVIII, DCC Fuel XIX, DCC Fuel XX, DCC Fuel XXI and DCC Fuel XXII consolidated VIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DHLC	Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo. DHLC is a non-consolidated VIE of SWEPCo.
DIR	Distribution Investment Rider.
Diversion	Diversion, acquired in December 2024, consists of 201 MWs of wind generation in Texas.
DOE	U. S. Department of Energy.
Eastern Region	AEP’s eastern service territory includes the areas where APCo, I&M, KGPCo, KPCo, OPCo and WPCo engage in the generation, transmission and distribution of electric power to customers.
EIS	Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated VIE of AEP.
ELG	Effluent Limitation Guidelines.
ENEC	Expanded Net Energy Cost.
Equity Units	AEP’s Equity Units issued in August 2020 and March 2019.
ERCOT	Electric Reliability Council of Texas regional transmission organization.
ESP	Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
ETT	Electric Transmission Texas, LLC, an equity interest joint venture between AEP Transmission Holdco and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.
Excess ADIT	Excess Accumulated Deferred Income Taxes.
FAC	Fuel Adjustment Clause.
FASB	Financial Accounting Standards Board.
Federal EPA	United States Environmental Protection Agency.
FERC	Federal Energy Regulatory Commission.
FGD	Flue Gas Desulfurization or Scrubbers.
FIP	Federal Implementation Plan.

ii

Term	Meaning
FTR	Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP	Generally Accepted Accounting Principles in the United States of America.
GHG	Greenhouse gas.
Gigawatt AI	Gigawatt AI Inc., an equity interest joint venture formed to build the AI-centric operating system for utilities.
G&M	Generation & Marketing.
I&M	Indiana Michigan Power Company, an AEP electric utility subsidiary. I&M engages in the generation, transmission and distribution of electric power to retail customers in northern and eastern Indiana and southwestern Michigan.
IMTCo	AEP Indiana Michigan Transmission Company, Inc., a wholly-owned transmission subsidiary of Midwest Transmission Holdings.
IRA	On August 16, 2022 President Biden signed into law legislation commonly referred to as the “Inflation Reduction Act” (IRA).
IRC	Internal Revenue Code.
IRP	Integrated Resource Plan.
IRS	Internal Revenue Service.
ITC	Investment Tax Credit.
IURC	Indiana Utility Regulatory Commission.
KGPCo	Kingsport Power Company, an AEP electric utility subsidiary. KGPCo provides electric service to retail customers in Kingsport, Tennessee and eight neighboring communities in northeastern Tennessee.
KPCo	Kentucky Power Company, an AEP electric utility subsidiary. KPCo engages in the generation, transmission and distribution of electric power to retail customers in eastern Kentucky.
KPSC	Kentucky Public Service Commission.
KTCo	AEP Kentucky Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
kV	Kilovolt.
KWh	Kilowatt-hour.
Liberty	Liberty Utilities Co., a subsidiary of Algonquin Power & Utilities Corporation.
LPSC	Louisiana Public Service Commission.
MATS	Mercury and Air Toxic Standards.
Maverick	Maverick, part of the North Central Wind Energy Facilities, consists of 287 MWs of wind generation in Oklahoma.
Midcontinent Grid Solutions	Midcontinent Grid Solutions, LLC, a holding company formed by Transource Energy and an affiliate of Berkshire Hathaway Energy in 2025, which is 43.25% owned by AEP.
Midwest Transmission Holdings	Midwest Transmission Holdings, LLC, a subsidiary of AEPTCo Parent that owns all of the issued and outstanding stock of IMTCo and OHTCo.
MISO	Midcontinent Independent System Operator.
Mitchell Plant	A two unit, 1,560 MW coal-fired power plant located in Moundsville, West Virginia. The plant is jointly owned by KPCo and WPCo.
MMBtu	Million British Thermal Units.
MPSC	Michigan Public Service Commission.
MTM	Mark-to-Market.
MW	Megawatt.
MWh	Megawatt-hour.
NAAQS	National Ambient Air Quality Standards.
NCWF	North Central Wind Energy Facilities, a joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,484 MWs of wind generation.
NERC	North American Electric Reliability Corporation.
NMRD	New Mexico Renewable Development, LLC.

iii

Term	Meaning
Nonutility Money Pool	Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
NOL	Net Operating Losses.
NOLC	Net Operating Loss Carryforward.
NOx	Nitrogen Oxide.
NRC	Nuclear Regulatory Commission.
OATT	Open Access Transmission Tariff.
OCC	Corporation Commission of the State of Oklahoma.
ODEQ	Oklahoma Department of Environmental Quality.
OHTCo	AEP Ohio Transmission Company, Inc., a wholly-owned transmission subsidiary of Midwest Transmission Holdings.
OKTCo	AEP Oklahoma Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
OPCo	Ohio Power Company, an AEP electric utility subsidiary. OPCo engages in the transmission and distribution of electric power to retail customers in Ohio.
OPEB	Other Postretirement Benefits.
Operating Agreement	Agreement, dated January 1, 1997, as amended, by and among PSO and SWEPCo governing generating capacity allocation, energy pricing, and revenues and costs of third-party sales.  AEPSC acts as the agent.
OTC	Over-the-counter.
OVEC	Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
Parent	American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PATH-WV	PATH West Virginia Transmission Company, LLC, a joint venture-owned 50% by FirstEnergy and 50% by AEP.
PBA	Performance Based Accreditation.
PCA	Power Coordination Agreement among APCo, I&M, KPCo and WPCo.
PFD	Proposal for Decision.
PJM	Pennsylvania – New Jersey – Maryland regional transmission organization.
PLR	Private Letter Ruling.
PM	Particulate Matter.
PPA	Power Purchase Agreement.
PSA	Purchase and Sale Agreement.
PSO	Public Service Company of Oklahoma, an AEP electric utility subsidiary. PSO engages in the generation, transmission and distribution of electric power to retail customers in eastern and southwestern Oklahoma.
PTC	Production Tax Credit.
PUCO	Public Utilities Commission of Ohio.
PUCT	Public Utility Commission of Texas.
Registrant Subsidiaries	AEP subsidiaries which are SEC registrants: AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Registrants	SEC registrants: AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
REP	Texas Retail Electric Provider.
Restoration Funding	AEP Texas Restoration Funding LLC, a wholly-owned subsidiary of AEP Texas and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to storm restoration in Texas primarily caused by Hurricane Harvey.
Risk Management Contracts	Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant	A generation plant, jointly-owned by AEGCo and I&M, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana.
ROE	Return on Equity.
RPM	Reliability Pricing Model.

iv

Term	Meaning
RTO	Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine	Sabine Mining Company, a lignite mining company that is a consolidated VIE for AEP and SWEPCo.
SEC	U.S. Securities and Exchange Commission.
SIP	State Implementation Plan.
SNF	Spent Nuclear Fuel.
SO2	Sulfur Dioxide.
SPP	Southwest Power Pool regional transmission organization.
SSO	Standard Service Offer.
State Transcos	AEPTCo’s five wholly-owned and two majority-owned, FERC regulated, transmission only electric utilities, which are geographically aligned with AEP's existing utility operating companies.
Storm Recovery Funding	SWEPCo Storm Recovery Funding, LLC, a wholly-owned subsidiary of SWEPCo and consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to storm restoration in Louisiana.
Sundance	Sundance, acquired in April 2021 as part of the North Central Wind Energy Facilities, consists of 199 MWs of wind generation in Oklahoma.
SWEPCo	Southwestern Electric Power Company, an AEP electric utility subsidiary. SWEPCo engages in the generation, transmission and distribution of electric power to retail customers in northeastern and panhandle of Texas, northwestern Louisiana and western Arkansas.
SWTCo	AEP Southwestern Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.
TA	Transmission Agreement, effective November 2010, among APCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent.
Tax Reform	On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.
TCA	Transmission Coordination Agreement dated January 1, 1997, by and among, PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two public utility subsidiaries.
T&D	Transmission and Distribution Utilities.
TPUC	Tennessee Public Utilities Commission.
Transition Funding	AEP Texas Central Transition Funding III LLC, a wholly-owned subsidiary of AEP Texas and consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to restructuring legislation in Texas.
Transource Energy	Transource Energy, LLC, a consolidated VIE formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. Transource Energy is 86.5% owned by AEPTHCo.
Traverse	Traverse, part of the North Central Wind Energy Facilities, consists of 998 MWs of wind generation in Oklahoma.
Turk Plant	John W. Turk, Jr. Plant, a 650 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.
UMWA	United Mine Workers of America.
UPA	Unit Power Agreement.
Utility Money Pool	Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
UTM	Unified Tracker Mechanism.
Valley Link	Valley Link Transmission Company, LLC, a holding company formed by Transource Energy, affiliates of Dominion Energy and FirstEnergy in 2024, which is 31.14% owned by AEP.
VIE	Variable Interest Entity.
Virginia SCC	Virginia State Corporation Commission.
VIU	Vertically Integrated Utilities.

v

Term	Meaning
Western Region	AEP’s western service territory includes the areas where AEP Texas, PSO and SWEPCo engage in the generation, transmission and distribution of electric power to customers.
WPCo	Wheeling Power Company, an AEP electric utility subsidiary. WPCo provides electric service to retail customers in northern West Virginia.
WVPSC	Public Service Commission of West Virginia.
WVTCo	AEP West Virginia Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary.

vi

FORWARD-LOOKING INFORMATION

This report made by the Registrants contains forward-looking statements, and for the Registrants other than Parent, this report contains forward looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Many forward-looking statements appear in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations,” but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, management undertakes no obligation to update or revise any forward-looking statement.  Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:

• Changes in economic conditions, electric market demand and demographic patterns in AEP service territories.

• The economic impact of increased global conflicts and trade tensions, and the adoption or expansion of economic sanctions, tariffs, trade restrictions or changes in trade policy.

• Inflationary or deflationary interest rate trends.

• New legislation or regulations adopted in the states in which we operate or federal legislation or regulations adopted that alters the regulatory framework or that prevents the timely recovery of costs and investments.

• Volatility and disruptions in financial markets precipitated by any cause, including fiscal and monetary policy or instability in the banking industry; particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt.

• The availability and cost of funds to finance working capital and capital needs, particularly (a) if expected sources of capital such as proceeds from the sale of tax credits and anticipated securitizations do not materialize or do not materialize at the level anticipated, and (b) during periods when the time lag between incurring costs and recovery is long and the costs are material.

• Changing demand for electricity, including large load contractual commitments.

• The risks and uncertainties associated with wildfires, including damages caused by wildfires, the extent of each Registrant’s liability in connection with wildfires, investigations and outcomes associated with legal proceedings, demands or similar actions, inability to recover wildfire costs through insurance or through rates and the impact on financial condition and the reputation of each Registrant.

• The impact of extreme weather conditions, natural disasters and catastrophic events such as storms, hurricanes, wildfires and drought conditions that pose significant risks including potential litigation and the inability to recover significant damages and restoration costs incurred.

• Limitations or restrictions on the amounts and types of insurance available to cover losses that might arise in connection with natural disasters, wildfires or operations.

• The cost of fuel and its transportation, the creditworthiness and performance of parties who supply and transport fuel and the cost of storing and disposing of used fuel, including coal ash and SNF.

• The availability of fuel and necessary generation capacity and the performance of generation plants.

• The ability to recover fuel and other energy costs through regulated or competitive electric rates.

• The ability to build or acquire generation (including from renewable sources and battery storage), transmission lines and facilities (including the ability to obtain any necessary regulatory approvals and permits) to meet the demand for electricity at acceptable prices and terms, including favorable tax treatment, cost caps imposed by regulators and other operational commitments to regulatory commissions and customers for generation projects, to recover all related costs and to earn a reasonable return.

• The disruption of AEP’s business operations due to impacts of economic or market conditions, costs of compliance with potential government regulations, electricity usage, supply chain issues, customers, service providers, vendors and suppliers caused by natural disasters or other events.

• Construction and development risks associated with the completion of the 2026-2030 capital investment plan, including shortages or delays in labor, materials, equipment or parts.

• Prolonged or recurring U.S. federal government shutdowns could adversely affect AEP’s operations, regulatory approvals, and financial performance and could cause volatility in the capital markets which may interrupt our access to capital.

• New legislation, litigation or government regulation, including changes to tax laws and regulations, oversight of nuclear generation, evolving environmental standards, energy commodity trading and new or modified requirements related to emissions of sulfur, nitrogen, mercury, carbon, soot or PM and other substances that could impact the continued operation, cost recovery and/or profitability of generation plants and related assets.

vii

• The impact of tax legislation or associated Department of Treasury guidance, including potential changes to existing tax incentives, on capital plans, results of operations, financial condition, cash flows or credit ratings.

• The risks before, during and after generation of electricity associated with the fuels used or the by-products and wastes of such fuels, including coal ash and SNF.

• Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.

• Resolution of litigation or regulatory proceedings or investigations.

• The ability to efficiently manage and recover operation, maintenance and development project costs.

• Prices and demand for power generated and sold in wholesale markets.

• Changes in technology, including new, developing, alternative or distributed sources of generation and energy storage.

• The ability to recover through rates any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.

• Volatility and changes in markets for coal and other energy-related commodities, particularly changes in the price of natural gas.

• The impact of changing expectations and demands of customers, regulators, investors and stakeholders, including development, adoption, and use of AI by us, our customers and our third party vendors and evolving expectations related to sustainability.

• Customer affordability considerations may impact regulatory recovery outcomes and future rate design.

• Changes in utility regulation and the allocation of costs within RTOs including ERCOT, PJM and SPP and the impacts of potential market changes within those RTOs.

• Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market.

• Actions of rating agencies, including changes in issuer ratings impacting the cost of debt.

• The impact of volatility in the capital markets on the value of the investments held by the pension, OPEB and nuclear decommissioning trust funds and a captive insurance entity and the impact of such volatility on future funding requirements.

• Accounting standards periodically issued by accounting standard-setting bodies.

• The ability to successfully defend against cybersecurity threats.

• Other risks and unforeseen events, including wars and military conflicts, the effects of terrorism (including increased security costs), embargoes, labor strikes impacting material supply chains, global information technology disruptions and other catastrophic events.

• The ability to attract and retain the requisite work force and key personnel, including senior management.

The forward-looking statements of the Registrants speak only as of the date of this report or as of the date they are made.  The Registrants expressly disclaim any obligation to update any forward-looking information, except as required by law.  For a more detailed discussion of these factors, see “Risk Factors” in Part I of this report. The disclosures in this section reflect AEP’s beliefs and opinions as to factors that could materially and adversely affect AEP in the future. References to past events are provided by way of example only and are not intended to be a complete listing or a representation as to whether or not such factors have occurred in the past or their likelihood of occurring in the future.

The Registrants may use AEP’s website as a distribution channel for material company information. Financial and other important information regarding the Registrants is routinely posted on and accessible through AEP’s website at www.aep.com/investors/. In addition, you may automatically receive email alerts and other information about the Registrants when you enroll your email address by visiting the “Email Alerts” section at www.aep.com/investors/.

Company Website and Availability of SEC Filings

Our principal corporate website address is www.aep.com. Information on our website is not incorporated by reference herein and is not part of this Form 10-K. We make available free of charge through our website our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after such documents are electronically filed with, or furnished to, the SEC. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements and other information regarding AEP.

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PART I

ITEM 1.   BUSINESS

GENERAL

Overview and Description of Major Subsidiaries

AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. It is a public utility holding company that directly owns all of the outstanding common stock of the public utility subsidiaries identified below.

The service areas of AEP’s public utility subsidiaries cover portions of the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. Transmission networks are interconnected with extensive distribution facilities in the territories served. The public utility subsidiaries of AEP have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. Restructuring laws in Michigan, Ohio and the ERCOT area of Texas have caused AEP public utility subsidiaries in those states to unbundle previously integrated regulated rates for their retail customers.

The member companies of AEP have contractual, financial and other business relationships with the other member companies, such as participation in AEP savings and retirement plans and tax returns, sales of electricity and transportation and handling of fuel. The member companies of AEP also obtain certain accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost from a common provider, AEPSC.

As of December 31, 2025, the subsidiaries of AEP had a total of 17,581 employees. As a holding company rather than an operating company, AEP has no employees.

Summary information related to AEP subsidiary operating companies as of December 31, 2025 is shown in the table below:

	AEP Texas	AEPTCo	APCo	I&M	KGPCo (a)	KPCo	OPCo (b)	PSO	SWEPCo	WPCo
State of Incorporation	Delaware, 1925	Delaware, 2006	Virginia, 1926	Indiana, 1907	Virginia, 1917	Kentucky, 1919	Ohio, 1907	Oklahoma, 1913	Delaware, 1912	West Virginia, 1883
AEP Reportable Segment	T&D	AEPTHCo	VIU	VIU	VIU	VIU	T&D	VIU	VIU	VIU
RTO Affiliation	ERCOT	(c)	PJM	PJM	PJM	PJM	PJM	SPP	SPP	PJM
Approximate Number of Retail Customers	1,133,000	(c)	971,000	621,000	50,000	161,000	1,547,000	588,000	558,000	41,000
Number of Employees	1,730	(c)	1,682	2,152	48	304	1,556	1,150	1,392	229

(a)KGPCo does not own any generating facilities and purchases electric power from APCo for distribution to its customers.

(b)OPCo purchases energy and capacity at auction to serve generation service customers who have not switched to a competitive generation supplier.

(c)AEPTCo is a holding company for the State Transcos, other than IMTCo and OHTCo, and Midwest Transmission Holdings. Five State Transcos are members of PJM and two State Transcos are members of SPP. Neither AEPTCo nor its subsidiaries have any employees. Instead, AEPSC and certain AEP utility subsidiaries provide services to these entities.

Service Company Subsidiary

AEPSC is a service company subsidiary that provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to AEP subsidiaries. The executive officers of AEP and certain of the executive officers of its public utility subsidiaries are employees of AEPSC. As of December 31, 2025, AEPSC had 6,994 employees.

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Principal Industries Served

The following table illustrates the principal industries and wholesale electric markets served by AEP’s public utility subsidiaries.

	AEP Texas	APCo	I&M	KGPCo	KPCo	OPCo	PSO	SWEPCo	WPCo
Principal Industries Served:
Petroleum and Coal Products Manufacturing	X				X	X	X
Chemical Manufacturing	X	X	X	X	X	X		X	X
Oil and Gas Extraction	X				X		X	X
Pipeline Transportation	X	X			X	X		X	X
Primary Metal Manufacturing	X	X	X			X		X	X
Data Processing (a)	X		X			X
Coal-Mining		X			X				X
Paper Manufacturing				X			X	X
Transportation Equipment		X	X
Plastics and Rubber Products			X	X			X		X
Fabricated Metals Product Manufacturing			X			X
Food Manufacturing				X			X	X
Supply and Market Electric Power at Wholesale to:
Other Electric Utility Companies		X	X		X		X	X	X
Rural Electric Cooperatives		X	X					X
Municipalities		X	X		X		X	X
Other Market Participants		X	X		X		X	X	X

(a)Primarily includes data centers and cryptocurrency operations.

Public Utility Subsidiaries by Jurisdiction

The following table illustrates certain regulatory information with respect to the jurisdictions in which the public utility subsidiaries of AEP operate:

Principal Jurisdiction	AEP Utility Subsidiaries Operating in that Jurisdiction	Authorized Return on Equity (a)
Arkansas	SWEPCo	9.65	%	(b)
FERC	AEPTCo - APTCo, IMTCo, KTCo, WVTCo	10.35	%
FERC	AEPTCo - OHTCo	9.85	%
FERC	AEPTCo - OKTCo and SWTCo	10.50	%
Indiana	I&M	9.85	%
Kentucky	KPCo	9.75	%
Louisiana	SWEPCo	9.50	%
Michigan	I&M	9.86	%
Ohio	OPCo	9.70	%
Oklahoma	PSO	9.50	%
Tennessee	KGPCo	9.50	%
Texas	AEP Texas	9.76	%
Texas	SWEPCo	9.25	%
Virginia	APCo	9.75	%
West Virginia	APCo	9.25	%
West Virginia	WPCo	9.25	%

(a)Identifies the predominant current authorized ROE, and may not include other, less significant, permitted recovery.  Actual ROE varies from authorized ROE.

(b)The APSC issued an order approving a 9.65% ROE effective February 2026. See “2025 Arkansas Base Rate Case” section of Note 4 for additional information.

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CLASSES OF SERVICE

AEP and subsidiaries recognize revenues from customers for retail and wholesale electricity sales and electricity transmission and distribution delivery services. AEP’s subsidiaries within the Vertically Integrated Utilities, Transmission and Distribution Utilities, AEP Transmission Holdco and Generation & Marketing segments derive revenue from the following sources: Retail Revenues, Wholesale and Competitive Retail Revenues, Other Revenues from Contracts with Customers and Alternative Revenues. For further information relating to the sources of revenue for the Registrants, see Note 20 - Revenues from Contracts with Customers for additional information.

FINANCING

General

AEP subsidiaries generally use short-term debt to finance working capital needs.  Short-term debt may also be used to finance acquisitions, construction and redemption or repurchase of outstanding securities until such needs can be financed with long-term funding.  In recent history, short-term funding needs have been provided for by cash from operations, AEP’s commercial paper program and term loan issuances.  Funds are made available to subsidiaries under the AEP corporate borrowing program.  Certain public utility subsidiaries of AEP also sell accounts receivable to provide liquidity.  Sources of long-term funding include issuance of long-term debt, long-term asset securitizations, leasing agreements, hybrid securities or common stock. See “Financial Condition” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

AEP’s revolving credit agreements (which backstop the commercial paper program) include covenants and events of default typical for these types of facilities, including a maximum debt-to-total capitalization test.  In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of its major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $100 million, would cause an event of default under the credit agreements. As of December 31, 2025, AEP was in compliance with its debt covenants.  With the exception of a voluntary bankruptcy or insolvency, any event of default has either or both a cure period or notice requirement before termination of the applicable agreement.  A voluntary bankruptcy or insolvency of AEP or one of its significant subsidiaries would be considered an immediate termination event.  See “Financial Condition” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

ENVIRONMENTAL AND OTHER MATTERS

AEP subsidiaries are currently subject to regulation by federal, state and local authorities with regard to air and water-quality control, solid and hazardous waste disposal and other environmental matters, and are subject to zoning and other regulation by local authorities.  Current and proposed environmental laws and regulations will have an impact on AEP’s operations. Management continues to monitor developments in the regulations and evaluate the economic feasibility and refine cost estimates for compliance. AEP is unable to predict how future changes in regulations, regulatory guidance, legal interpretations, policy positions and implementation actions will impact AEP’s operations. For additional information on these laws and regulations, see “Environmental Issues” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations.

HUMAN CAPITAL MANAGEMENT

Attracting, developing and retaining high-performing employees with the skills and experience needed to serve customers efficiently and effectively is crucial to AEP’s growth and competitiveness and is central to the Company’s long-term strategy. AEP invests in employees and continues to build a high performance and inclusive culture that inspires leadership, encourages innovative thinking and welcomes everyone.

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The following table shows AEP’s number of employees by subsidiary as of December 31, 2025:

Subsidiary	Number of Employees
AEPSC	6,994
AEP Texas	1,730
APCo	1,682
I&M	2,152
KGPCo	48
KPCo	304
OPCo	1,556
PSO	1,150
SWEPCo	1,392
WPCo	229
Other (a)	344
Total AEP (b)	17,581

(a) Primarily relates to AEP Energy employees.

(b) Approximately 24% of AEP’s total workforce was represented by labor unions.

Safety

Safety is integral to culture and is one of AEP’s core values. AEP is dedicated to the safety of employees, contractors, customers and the communities AEP serves. AEP has policies, procedures, programs, training and initiatives in place to help provide a safety conscious work environment. AEP is committed to fundamentally embedding layers of protection in its operations. This includes focusing efforts to prevent serious injuries and fatalities, strengthening pre-job briefing effectiveness, learning from safety incidents, providing appropriate training and education and improving proactive safety initiatives and data analysis to identify and address potential performance gaps.

In 2025, the company experienced a workplace fatality involving one employee. AEP learned from this event and has taken action to better protect employees and all those who support AEP.

Safety Metric	2025	2024
DART	0.436	0.556
TRIR	0.755	0.913

AEP’s employee Days Away, Restricted and Transferred (DART) rate and Total Recordable Incident Rate (TRIR) improved in 2025. A DART event is a work-related incident that results in one or more restricted work days or an employee transferring to a different job within the company. The DART rate is the number of DART events multiplied by 200,000 and divided by total hours worked, normalizing the results to injuries per 100 full-time equivalent employees annually. A recordable event is a work-related event that results in death, days away from work, restricted work or transfer to another job, medical treatment beyond first aid, loss of consciousness or a significant injury or illness diagnosed by a physician or other licensed health care professional. TRIR shows how often these recordable injuries happen. It is a mathematical calculation (number of recordable events multiplied by 200,000 and divided by total hours worked) expressing the number of recordable incidents per 100 full-time employees annually. AEP has made progress reducing injury rates and is reaffirming its commitment to continuous improvement in safety and health to provide a safer work environment for all.

Culture

AEP aims to foster a culture of belonging, where every employee can thrive and contribute their best to support AEP’s mission, vision and core principles. AEP recognizes that an engaged, collaborative and innovative workforce helps better serve employees, customers, suppliers and other key stakeholders. AEP is focused on building a performance-based and accountable culture to effectively support its operating companies and enhance customer service. AEP’s culture progress is measured in part through the annual Employee Voice Survey. The Employee Voice Survey is an opportunity for employees to provide feedback about their experience at AEP. It also serves as a means for the Company to understand how to foster a workplace

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focused on performance, accountability, collaboration and customer orientation. 2025 marks AEP’s twelfth consecutive year of formally surveying employees about their experience.

Training and Professional Development

Attracting, developing, and retaining high-performing employees with the skills and experience needed to serve customers efficiently and effectively is crucial to AEP’s growth and long-term strategy. AEP is preparing its workforce for the future by providing opportunities to learn new skills and engaging higher education institutions to better prepare the next generation of workers. AEP offers co-op and internship programs in partnership with high schools, technical/vocational schools and colleges across AEP’s 11-state service territory. AEP also provides a broad range of training and assistance that supports lifelong learning and development. This includes operational skills training, professional training, leadership development, educational assistance, ongoing performance coaching and other forms of development that offer career pathways for employees.

Compensation and Benefits

AEP is committed to the well-being of employees, and offers programs to foster employee financial well-being, physical and emotional health, and social connectedness. AEP provides market-competitive compensation and benefits, including medical and dental coverage, life insurance, and well-being programs designed to support employees and their families. Eligible AEP employees participate in an annual incentive program that rewards individual performance and achievement of business goals, fostering a high-performance culture. AEP also offers paid time off in the form of vacation, holidays, sick time and parental leave.

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BUSINESS SEGMENTS

AEP’s Reportable Segments

AEP’s primary business is the generation, transmission and distribution of electricity.  Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight applicable to each public utility subsidiary.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments are as follows:

•Vertically Integrated Utilities

•Transmission and Distribution Utilities

•AEP Transmission Holdco

•Generation & Marketing

The remainder of AEP’s activities are presented as Corporate and Other, which is not considered a reportable segment. See Note 9 - Business Segments for additional information on AEP’s segments.

Seasonality

The consumption and delivery of electric power is generally seasonal which impacts the results of operations of AEP’s reportable segments.  In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time.  In some areas, power demand peaks during the cold winter months.  The pattern of this fluctuation may change due to the nature and location of AEP’s facilities and the terms of power sale contracts into which AEP enters.  In addition, AEP has historically sold and delivered less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could diminish AEP’s results of operations.  Conversely, unusually extreme weather temperatures could increase AEP’s results of operations.

VERTICALLY INTEGRATED UTILITIES

GENERAL

The Vertically Integrated Utilities operations are engaged in the generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.  AEPSC, as agent for AEP’s public utility subsidiaries, performs marketing, generation dispatch, fuel procurement and power-related risk management and trading activities on behalf of each of these subsidiaries.

ELECTRIC GENERATION

Facilities

As of December 31, 2025, the Vertically Integrated Utilities owned approximately 25,400 MWs of generation.  See Item 2 – Properties for more information regarding the generation capacity of vertically integrated public utility subsidiaries.

Fuel Supply

The following table shows the owned and leased generation sources by type (including wind purchase agreements), on an actual net generation (MWhs) basis, used by the Vertically Integrated Utilities:

	2025	2024	2023
Coal and Lignite	43%	40%	37%
Nuclear	19%	22%	22%
Natural Gas	22%	22%	22%
Renewables	16%	16%	19%

An increase/decrease in one or more generation types relative to previous years reflects changes in resource mix and price changes in one or more fuel commodity sources relative to the pricing of other fuel commodity sources. AEP’s overall 2025

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fossil fuel costs for the Vertically Integrated Utilities increased 0.5% on a dollar per MMBtu basis from 2024. AEP’s resource mix is driven by the needs and desires of the states AEP serves and continued focus on cost effective economic dispatch to AEP’s customers.

Coal and Lignite

The Vertically Integrated Utilities procure coal under a combination of purchasing arrangements, including long-term contracts and spot agreements with various producers and marketers. 

Management has coal contracts in place with suppliers through 2031 for a portion of the Company’s projected coal requirements. As of December 31, 2025, through subsidiaries, the Vertically Integrated Utilities own, lease or control 3,009 railcars, 270 barges, 4 towboats and a coal handling terminal with approximately 18 million tons of annual capacity to move and store coal for use in AEP generating facilities. The Vertically Integrated Utilities will secure additional railcar and barge/towboat capacity as needed to support demand.

The Vertically Integrated Utilities’ strategy for purchasing coal includes maintaining a target inventory level by layering in supplies over time to help with reducing price volatility. The price paid for coal delivered in 2025 decreased approximately 11.6% from 2024 mainly due to the completion of higher priced coal supply agreements that were agreed to in 2021 and 2022 when coal market pricing was stronger. The Vertically Integrated Utilities’ coal costs are typically recovered through various fuel reconciliation mechanisms.

The following table shows the amount of coal and lignite delivered to the Vertically Integrated Utilities’ plants during the past three years and the average delivered price of coal and lignite purchased by the Vertically Integrated Utilities:

	2025		2024		2023 (a)
Total coal and lignite delivered to the plants (in millions of tons)	19		17		21
Average cost per ton of coal and lignite delivered	$	54.86	$	62.05	$	64.31

(a) Deliveries of lignite ended after the first quarter of 2023.

The coal inventories at the Vertically Integrated Utilities’ plants fluctuate based on several factors, including consumption rates driven by electric power demand, unit outages, transportation constraints or delays, on-site space limitations, labor issues, supplier outages or performance issues and weather conditions, all of which can affect production, consumption or deliveries. As of December 31, 2025, the Vertically Integrated Utilities’ coal inventory was approximately 63 days of full load burn, down from the elevated levels experienced in recent years, but still above AEP’s targeted inventory level. While inventory targets vary by plant and are adjusted as necessary, the current inventory target is approximately 35 days of full load burn per plant for the Vertically Integrated Utilities. Inventory levels are expected to continue to decline in 2026 but will likely still not reach the inventory target levels by year-end.

Natural Gas

The Vertically Integrated Utilities consumed approximately 164 billion cubic feet of natural gas during 2025 for generating power, which represents an increase of 5.8% from 2024. While nominal year-over-year natural gas consumption increases were experienced across AEP’s operating companies, the main consumption increase driver was related to the Green Country Power Plant, which was acquired by PSO on June 30, 2025. From a delivered natural gas cost perspective, total costs increased 21.6% from 2024.

Several natural gas-fired units are connected to at least two pipelines, which allows greater access to competitive supplies and improves delivery reliability. From a natural gas supply perspective, the Vertically Integrated Utilities secure forward month, fixed price baseload supply, prompt month baseload supply, and pursue daily spot market purchases or sales (to balance daily positions). From a natural gas transportation perspective, the Vertically Integrated Utilities utilize firm and interruptible transportation capacity. Furthermore, SWEPCo and PSO utilize firm natural gas storage, which supports price stability and provides additional surety of natural gas supply. AEP’s natural gas supply, transportation and storage transactions are competitively bid and are based on applicable market prices.

The Vertically Integrated Utilities’ natural gas supply, transportation and storage costs are typically recovered through various fuel reconciliation mechanisms.

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The following table shows the amount of natural gas delivered to the Vertically Integrated Utilities’ plants during the past three years and the average delivered price of natural gas purchased by the Vertically Integrated Utilities:

	2025		2024		2023
Total natural gas delivered to the plants (in billions of cubic feet)	164		155		146
Average delivered price per MMBtu of purchased natural gas	$	3.71	$	3.05	$	2.69

Nuclear

I&M has made commitments to meet the current nuclear fuel requirements of the Cook Plant.  I&M has made and will make purchases of uranium in various forms in the spot, short-term, mid-term and long-term markets.  

For purposes of the storage of high-level radioactive waste in the form of SNF, I&M completed modifications to its SNF storage pool in the early 1990’s.  I&M entered into an agreement to provide for onsite dry cask storage of SNF to permit normal operations to continue.  I&M is scheduled to conduct further dry cask loading and storage projects on an ongoing periodic basis.  The year of expiration of each NRC Operating License is 2034 for Unit 1 and 2037 for Unit 2. Management has started the application process for license extensions for both units that would extend Unit 1 and Unit 2 to 2054 and 2057, respectively.

Nuclear Waste and Decommissioning

As the owner of the Cook Plant, I&M has a significant future financial obligation to dispose of SNF and decommission and decontaminate the plant safely.  NRC regulations and the SNF disposal program impact the cost to decommission the Cook Plant.  The most recent decommissioning cost study was completed in 2024.  According to that study, stated in 2024 undiscounted dollars, the estimated cost of decommissioning and disposal of low-level radioactive waste was $2.4 billion, with additional ongoing costs of $7 million per year for post-decommissioning storage of SNF and an eventual cost of $45 million for the subsequent decommissioning of the SNF storage facility. As of December 31, 2025 and 2024, the total decommissioning trust fund balance for the Cook Plant was approximately $4.5 billion and $4 billion, respectively. The balance of funds available to eventually decommission Cook Plant will differ based on contributions and investment returns.  The ultimate cost of retiring the Cook Plant may be materially different from estimates and funding targets as a result of the:

•Escalation of various cost elements (including, but not limited to, general inflation and the cost of energy).

•Further development of regulatory requirements governing decommissioning.

•Technology available at the time of decommissioning differing significantly from that assumed in studies.

•Availability of nuclear waste disposal facilities.

•Availability of a United States Department of Energy facility for permanent storage of SNF.

Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant will not be significantly different than current projections.  AEP will seek recovery from customers through regulated rates if actual decommissioning costs exceed projections.  See the “Nuclear Contingencies” section of Note 6 - Commitments, Guarantees and Contingencies for additional information with respect to nuclear waste and decommissioning.

Low-Level Radioactive Waste

The Low-Level Waste Policy Act of 1980 mandates that the responsibility for the disposal of low-level radioactive waste rests with the individual states.  Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials.  Michigan does not currently have a disposal site for such waste available.  I&M cannot predict when such a site may be available. However, the states of Utah and Texas have licensed low-level radioactive waste disposal sites which currently accept low-level radioactive waste from Michigan waste generators, which I&M currently utilizes.  There is currently no set date limiting I&M’s access to either of these facilities.  The Cook Plant has a facility onsite designed specifically for the storage of low-level radioactive waste.  In the event that low-level radioactive waste disposal facility access becomes unavailable, it can be stored onsite at this facility.

Counterparty Risk Management

The Vertically Integrated Utilities segment also sells power and enters into related energy transactions with wholesale customers and other market participants. As a result, counterparties and exchanges may require cash or cash related instruments to be deposited on transactions as margin against open positions.  As of December 31, 2025, counterparties posted

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approximately $112 million in cash, cash equivalents or letters of credit with AEPSC for the benefit of AEP’s public utility subsidiaries (while, as of that date, AEP’s public utility subsidiaries posted approximately $214 million with counterparties and exchanges).  Since open trading contracts are valued based on market prices of various commodities, exposures change daily.  See the “Quantitative and Qualitative Disclosures About Market Risk” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

Certain Power Agreements

I&M

A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the energy and capacity available to AEGCo at the Rockport Plant unless it is sold to another utility. I&M is obligated, whether or not power is available from AEGCo, to pay a demand charge for the right to receive such power (and an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all of its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The UPA will continue in effect until the debt obligations of AEGCo secured by the Rockport Plant have been satisfied and discharged (currently expected to be December 2028).

OVEC

AEP and several nonaffiliated utility companies jointly own OVEC.  The aggregate equity participation of AEP in OVEC is 43.47%.  Parent owns 39.17% and OPCo owns 4.3%.  Under the Inter-Company Power Agreement (ICPA), which defines the rights of the owners and sets the power participation ratio of each, the sponsoring companies are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MWs) in proportion to their respective power participation ratios.  The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%.  The ICPA terminates in June 2040.  The proceeds from charges by OVEC to sponsoring companies under the ICPA based on their power participation ratios are designed to be sufficient for OVEC to meet its operating expenses and fixed costs.  OVEC’s Board of Directors, as elected by AEP and nonaffiliated owners, has authorized environmental investments related to their ownership interests, with resulting expenses (including for related debt and interest thereon) included in charges under the ICPA. OVEC financed capital expenditures in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at its two generation plants through debt issuances, including tax-advantaged debt issuances.  Both OVEC generation plants are operating with environmental controls in-service.  See Note 18 - Variable Interest Entities and Equity Method Investments for additional information.

ELECTRIC DELIVERY

General

Other than AEGCo, the Vertically Integrated Utilities own and operate transmission and distribution lines and other facilities to deliver electric power.  See Item 2 – Properties for more information regarding the transmission and distribution lines.  Most of the transmission and distribution services are sold to retail customers of the Vertically Integrated Utilities in their service territories.  These sales are made at rates approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC.  The FERC regulates and approves the rates for both wholesale transmission transactions and wholesale generation contracts.  The use and the recovery of costs associated with the transmission assets of the Vertically Integrated Utilities are subject to the rules, principles, protocols and agreements in place with PJM and SPP, and as approved by the FERC. See Item 1. Business – Vertically Integrated Utilities – Regulation – FERC.  As discussed below, some transmission services also are separately sold to nonaffiliated companies.

Other than AEGCo, the Vertically Integrated Utilities hold franchises or other rights to provide electric service in various municipalities and regions in their service areas.  In some cases, these franchises provide the utility with the exclusive right to provide electric service within a specific territory.  These franchises have varying provisions and expiration dates.  In general, the operating companies consider their franchises to be adequate for the conduct of their business. 

Transmission Agreement

APCo, I&M, KGPCo, KPCo and WPCo own and operate transmission facilities that are used to provide transmission service under the PJM OATT and are parties to the TA.  OPCo, which is a subsidiary in AEP’s Transmission and Distribution Utilities segment that provides transmission service under the PJM OATT, is also a party to the TA.  The TA defines how the parties to

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the agreement share the revenues associated with their transmission facilities and the costs of transmission service provided by PJM.  The FERC has approved the TA.

Transmission Coordination Agreement and Open Access Transmission Tariff

PSO, SWEPCo and AEPSC are parties to the TCA.  Under the TCA, a coordinating committee is charged with the responsibility of: (a) overseeing the coordinated planning of the transmission facilities of the parties to the agreement, including the performance of transmission planning studies, (b) the interaction of such subsidiaries with independent system operators and other regional bodies interested in transmission planning and (c) compliance with the terms of the AEP and SPP OATTs filed with the FERC and the rules of the FERC relating to such tariffs.  Pursuant to the TCA, PSO, SWEPCo and AEPSC each have responsibility for monitoring and reporting situations or problems that materially affect the reliability of PSO’s and SWEPCo’s transmission systems.  The TCA also provides for the allocation among the parties of revenues collected for transmission and ancillary services as determined by the FERC-approved OATT for SPP.

Regional Transmission Organizations

AEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM, and PSO and SWEPCo are members of SPP (both FERC-approved RTOs).  RTOs operate, plan and control utility transmission assets in a manner designed to provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not.

REGULATION

General

The Vertically Integrated Utilities’ retail rates and certain other matters are subject to traditional cost-based regulation by the state utility commissions.  The Vertically Integrated Utilities are also subject to regulation by the FERC under the Federal Power Act with respect to wholesale power and transmission service transactions.  I&M is subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant.  AEP and its vertically integrated public utility subsidiaries are also subject to the regulatory provisions of much of the Energy Policy Act of 2005, which is administered by the FERC.

Rates

Historically, state utility commissions have established electric service rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service.  A utility’s cost of service generally reflects its operating expenses, including operation and maintenance expense, depreciation expense and taxes.  State utility commissions periodically adjust rates pursuant to a review of: (a) a utility’s adjusted revenues and expenses during a defined test period and (b) such utility’s level of investment.  Absent a legal limitation, such as a law limiting the frequency of rate changes or capping rates for a period of time, a state utility commission can review and change rates on its own initiative.  Some states may initiate reviews at the request of a utility, customer, governmental or other representative of a group of customers.  Such parties may, however, agree with one another not to request reviews of or changes to rates for a specified period of time.

Public utilities have traditionally financed capital investments until the new asset is placed in-service.  Provided the asset was found to be a prudent investment, it was then added to rate base and entitled to a return through rate recovery.  Given long lead times in construction, the high costs of plant and equipment and volatile capital markets, management actively pursues strategies to accelerate rate recognition of investments and cash flow.  AEP representatives continue to engage state commissioners and legislators on alternative ratemaking options to reduce regulatory lag and enhance certainty in the process.  These options include pre-approvals, a return on construction work in progress, rider/trackers, formula rates and the inclusion of future test-year projections into rates.

The rates of the Vertically Integrated Utilities are generally based on the cost of providing traditional bundled electric service (i.e., generation, transmission and distribution service).  Historically, the state regulatory frameworks in the service area of the Vertically Integrated Utilities reflected specified fuel costs as part of bundled (or, more recently, unbundled) rates or incorporated fuel adjustment clauses in a utility’s rates and tariffs.  Fuel adjustment clauses permit periodic adjustments to fuel cost recovery from customers and therefore provide protection against exposure to fuel cost changes.

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The following state-by-state analysis summarizes the regulatory environment of jurisdictions in which AEP’s vertically integrated public utility subsidiaries operate.  Several public utility subsidiaries operate in more than one jurisdiction.  See Note 4 - Rate Matters for more information regarding pending rate matters.

Arkansas

SWEPCo provides retail electric service in Arkansas at bundled rates approved by the APSC with rates set on a historical cost-of-service basis and formula rates. Arkansas provides for timely fuel and purchased power cost recovery through respective annual fuel and purchased power recovery mechanisms.

Indiana

I&M provides retail electric service in Indiana at fully bundled rates approved by the IURC with rates set on a forecasted cost-of-service basis.  Indiana allows for timely recovery of fuel expenses through a fuel recovery surcharge mechanism and has approved additional recovery mechanisms associated with purchase power capacity, transmission and certain generation and environmental-related costs. I&M is subject to a semi-annual Indiana jurisdictional earnings test.

Kentucky

KPCo provides retail electric service in Kentucky at bundled rates approved by the KPSC with rates currently set on a historical cost-of-service basis. Kentucky generally allows for timely recovery of fuel expenses through a fuel recovery surcharge mechanism.

Louisiana

SWEPCo provides retail electric service in Louisiana at bundled rates approved by the LPSC with rates set on a historical cost-of-service basis and formula rates. Louisiana provides for timely fuel and purchased power cost recovery through respective fuel and purchased power recovery mechanisms updated monthly.

Michigan

I&M provides retail electric service in Michigan at both unbundled standard service and open access distribution service rates approved by the MPSC, with rates set on a forecasted cost-of-service basis. Open access distribution service is limited to 10% of I&M’s retail load. Michigan generally allows for timely recovery of fuel expenses, transmission expenses and purchased power expenses through a single surcharge mechanism.

Oklahoma

PSO provides retail electric service in Oklahoma at bundled rates approved by the OCC with rates set on a historical cost-of-service basis.  Fuel and purchased energy costs are recovered through a fuel adjustment clause.

Tennessee

KGPCo currently provides retail electric service in Tennessee at bundled rates approved by the TPUC with rates set on a historical cost-of-service basis. Tennessee generally allows for timely recovery of fuel expenses and purchased power expenses through a surcharge mechanism.

Texas

SWEPCo provides retail electric service in Texas at bundled rates approved by the PUCT with rates set on a historical cost-of-service basis. Texas generally provides for timely fuel and purchased power cost recovery through respective fuel and purchased power recovery mechanisms.

Virginia

APCo currently provides retail electric service in Virginia at unbundled generation and distribution rates approved by the Virginia SCC with rates set on a historical cost-of-service basis.  Virginia generally allows for timely recovery of fuel expenses through a fuel cost recovery surcharge mechanism.  In addition to base rates and fuel cost recovery, APCo is permitted to

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recover transmission expenses provided at OATT rates based on rates established by the FERC. APCo is subject to a biennial Virginia retail generation and distribution earnings test.

West Virginia

APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC with rates set on a combined APCo and WPCo historical cost-of-service basis. West Virginia generally allows for timely recovery of fuel expenses, purchased power expenses and transmission expenses through a single surcharge mechanism.

FERC

The FERC regulates rates for interstate power sales at wholesale, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects.  The FERC regulations require the Vertically Integrated Utilities to provide open access transmission service at FERC-approved rates, and AEP has approved cost-based formula transmission rates on file at the FERC.  The FERC also regulates unbundled transmission service to retail customers.  In addition, the FERC regulates the sale of power for resale in interstate commerce by: (a) approving contracts for wholesale sales to municipal and cooperative utilities at cost-based rates and (b) granting authority to public utilities to sell power at wholesale at market-based rates upon a showing that the seller lacks the ability to improperly influence market prices.  AEP’s vertically integrated public utility subsidiaries have market-based rate authority from the FERC, under which much of their wholesale marketing activity takes place.  The FERC requires each public utility that owns or controls interstate transmission facilities, directly or through an RTO, to file an open access network and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system.  The FERC also requires all transmitting utilities, directly or through an RTO, to establish an Open Access Same-time Information System, which electronically posts transmission information such as available capacity and prices, and requires utilities to comply with Standards of Conduct that prohibit utilities’ transmission employees from providing non-public transmission information to the utility’s marketing employees. Additionally, the vertically integrated public utility subsidiaries are subject to mandatory reliability standards promulgated by the NERC, with the approval of the FERC, which standards protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches.

The FERC oversees RTOs, entities created to operate, plan and control utility transmission assets.  AEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM.  PSO and SWEPCo are members of SPP.

The FERC has jurisdiction over certain issuances of securities of most of AEP’s public utility subsidiaries, the acquisition of securities of utilities, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company.  In addition, both the FERC and state regulators are permitted to review the books and records of any company within a holding company system.

COMPETITION

The Vertically Integrated Utilities primarily generate, transmit and distribute electricity to their retail customers in their service territories.  These sales are made at rates approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC, and are not subject to competition from other vertically integrated public utilities. Other than AEGCo, the Vertically Integrated Utilities hold franchises or other rights that effectively grant the exclusive ability to provide electric service in various municipalities and regions in their service areas.  

The Vertically Integrated Utilities compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil, renewables and coal, within their service areas.  The primary factors in such competition are price, reliability of service and the capability of customers to utilize alternative sources of energy other than electric power. With respect to competing generators and self-generation, the public utility subsidiaries of AEP believe that they currently maintain a competitive position. 

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TRANSMISSION AND DISTRIBUTION UTILITIES

GENERAL

This segment consists of the transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.

The Transmission and Distribution Utilities own and operate transmission and distribution lines and other facilities to deliver electric power.  See Item 2 – Properties, for more information regarding the transmission and distribution lines.  Transmission and distribution services are sold to their retail customers in their service territories.  These sales are made at rates approved by the PUCT for AEP Texas and by the PUCO and the FERC for OPCo.  The FERC regulates and approves the rates for wholesale transmission transactions.  As discussed below, some transmission services also are separately sold to nonaffiliated companies.

The Transmission and Distribution Utilities hold franchises or other rights to provide electric service in various municipalities and regions in their service areas.  In some cases, these franchises provide the utility with the exclusive right to provide electric service.  These franchises have varying provisions and expiration dates.  In general, the operating companies consider their franchises to be adequate for the conduct of their business.

The use and the recovery of costs associated with the transmission assets of the Transmission and Distribution Utilities are subject to the rules, protocols and agreements in place with PJM and ERCOT, and as approved by the FERC.  In addition to providing transmission services in connection with power sales in their service areas, AEP’s transmission and distribution utility subsidiaries also provide transmission services for nonaffiliated companies through RTOs.

Transmission Agreement

OPCo owns and operates transmission facilities that are used to provide transmission service under the PJM OATT; OPCo is a party to the TA with other utility subsidiary affiliates. The TA defines how the parties to the agreement share the revenues associated with their transmission facilities and the costs of transmission service provided by PJM. The FERC has approved the TA.

Regional Transmission Organizations

OPCo is a member of PJM, a FERC-approved RTO.  RTOs operate, plan and control utility transmission assets to provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not.  AEP Texas is a member of ERCOT.

REGULATION

Transmission and distribution rates are established on a cost-of-service basis, which is designed to allow a utility company an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service. The cost-of-service generally reflects operating expenses, including operation and maintenance expense, depreciation expense and taxes. Utility commissions periodically adjust rates pursuant to a review of: (a) a utility’s adjusted revenues and expenses during a defined test period and (b) such utility’s level of investment.

OPCo provides transmission and distribution services to retail customers within its service territory at cost-based rates approved by the PUCO or by the FERC. AEP Texas provides transmission and distribution services to REPs within its service territory. Prior to the passage of Texas House Bill 5247 (HB 5247) in June 2025, AEP Texas set rates through a combination of base rate cases and interim Transmission Cost of Services (TCOS) and Distribution Cost Recovery Factor (DCRF) semi-annual filings which update rates to reflect changes in net invested capital. In October 2025, AEP Texas submitted its first annual interim rate adjustment filing with the PUCT seeking recovery of eligible costs through the UTM established by HB 5247. This filing combined three recovery mechanisms (TCOS, DCRF and Transmission Cost Recovery Factor (TCRF)) into a single filing. AEP Texas and OPCo also have PUCT and PUCO, respectively, approved rider/tracker mechanisms which are periodically reset and designed to recover certain operating expenses.

FERC

The FERC regulates rates for transmission of electric power, accounting and other matters.  The FERC regulations require AEP to provide open access transmission service at FERC-approved rates, and it has approved cost-based formula transmission rates on file at the FERC.  The FERC also regulates unbundled transmission service to retail customers.  The FERC requires each public utility that owns or controls interstate transmission facilities to, directly or through an RTO, file an open access network

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and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system.  The FERC also requires all transmitting utilities, directly or through an RTO, to establish an Open Access Same-time Information System, which electronically posts transmission information such as available capacity and prices, and requires utilities to comply with Standards of Conduct that prohibit utilities’ transmission employees from providing non-public transmission information to the utility’s marketing employees. In addition, both the FERC and state regulators are permitted to review the books and records of any company within a holding company system. Additionally, the transmission and distribution utility subsidiaries are subject to mandatory reliability standards as set forth by the NERC, with the approval of the FERC, which standards protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches.

AEP TRANSMISSION HOLDCO

GENERAL

AEPTHCo is a holding company for AEPTCo. AEPTHCo also has interests in several AEP Transmission Joint Ventures. AEPTCo is the direct holding company of APTCo, KTCo, OKTCo, SWTCo and WVTCo. AEPTCo also has a controlling interest in Midwest Transmission Holdings. Midwest Transmission Holdings owns all of the issued and outstanding stock of IMTCo and OHTCo.

AEPTCo

The State Transcos are independent of, but respectively overlay, the following AEP electric utility operating companies: APCo, I&M, KPCo, OPCo, PSO, SWEPCo and WPCo. The State Transcos develop, own, operate and maintain their respective transmission assets. Individual State Transcos (a) have obtained the approvals necessary to operate in Indiana, Kentucky, Michigan, Ohio, Oklahoma and West Virginia, subject to any applicable siting requirements, (b) are authorized to submit projects for commission approval in Virginia and (c) have been granted consent to enter into a joint license agreement that will support investment in Tennessee. Assets of the State Transcos interconnect to transmission facilities owned by the aforementioned operating companies and nonaffiliated transmission owners within the footprints of PJM, MISO and SPP. APTCo, IMTCo, KTCo, OHTCo and WVTCo are located within PJM. IMTCo also owns portions of the Greentown station assets located in MISO. OKTCo and SWTCo are located within SPP. SWTCo does not currently own or operate transmission assets.

The State Transcos own, operate, maintain and invest in transmission infrastructure in order to maintain and enhance system integrity and grid reliability, grid security, safety, reduce transmission constraints and facilitate interconnections of new generating resources and new wholesale customers, as well as enhance competitive wholesale electricity markets. A key part of AEP’s business is replacing and upgrading transmission facilities, assets and components of the existing AEP System as needed to maintain reliability. As of December 31, 2025, the State Transcos had $17.1 billion of transmission and other assets in-service, excluding CWIP, with plans to construct approximately $11.6 billion of additional transmission assets through 2030.

In January 2025, AEP announced a partnership whereby a nonaffiliated entity would acquire a 19.9% noncontrolling interest in Midwest Transmission Holdings, a subsidiary of AEPTCo Parent that owns all of the issued and outstanding stock of OHTCo and IMTCo. The partnership was structured pursuant to a contribution agreement between AEPTCo, along with Midwest Transmission Holdings, and Olympus BidCo L.P. (“the Investor”), a special purpose entity controlled by (a) investment funds managed by or affiliated with Kohlberg Kravis Roberts & Co. L.P. and (b) Public Sector Pension Investment Board, whereby the Investor agreed to acquire a 19.9% noncontrolling equity interest in Midwest Transmission Holdings for $2.82 billion. The transaction closed in June 2025. AEP received cash proceeds of approximately $2.78 billion, net of transaction costs. Net proceeds were used to help finance AEP’s capital plan.

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AEPTHCO JOINT VENTURE INITIATIVES

AEPTHCo has established joint ventures with nonaffiliated electric utility companies for the purpose of developing, building and owning transmission assets that seek to improve reliability and market efficiency and provide transmission access to remote generation sources in North America (Transmission Joint Ventures). The Transmission Joint Ventures currently include:

Joint Venture Name	Location(s)	Projected or Actual Completion Date	AEPTHCo Ownership %	In-Service Net PP&E as of 12/31/2025		Approved Return on Equity
				(in millions)
ETT	Texas (ERCOT)	(a)	50%	$	3,744	9.6	%
Midcontinent Grid Solutions, LLC	Wisconsin	2034	50%	(b)		10.5	%
Prairie Wind Transmission, LLC	Kansas	2014	25%	121		12.8	%
Pioneer Transmission, LLC	Indiana	2018	50%	177		10.5	%
Transource Energy, LLC	Missouri, West Virginia, Maryland, Oklahoma and Pennsylvania	(c)	86.5%	496		10.3% - 11.3%
Valley Link Transmission Company, LLC	Maryland, Virginia and West Virginia	2029	31.1%	(d)		11.4	%	(e)

(a)ETT is undertaking multiple projects and the completion dates will vary for those projects. ETT’s investment in completed and active projects in ERCOT is expected to be $5.6 billion by 2030.  Future projects will be evaluated on a case-by-case basis.

(b)The projects awarded by MISO are estimated to cost approximately $1.2 billion.

(c)Transource Energy, LLC is undertaking multiple projects and the completion dates will vary for those projects. Transource Energy, LLC's investment in current and active projects is expected to be $1.1 billion upon completion.  Future projects will be evaluated on a case-by-case basis.

(d)The projects awarded by PJM are estimated to cost approximately $3.0 billion.  Future projects will be evaluated on a case-by-case basis.

(e)Valley Link’s base ROE is subject to ongoing settlement and hearing procedures.

Transource Energy LLC, and its subsidiaries Transource Missouri, Transource West Virginia, Transource Maryland, Transource Pennsylvania and Transource Oklahoma are consolidated joint ventures by AEP.  All other joint ventures in the table above are not consolidated by AEP. AEP’s joint ventures do not have employees.  Business services for the joint ventures are provided by AEPSC and other AEP subsidiaries and the joint venture partners.

REGULATION

The State Transcos and the Transmission Joint Ventures located outside of ERCOT establish transmission rates annually through forward-looking formula rate filings with the FERC pursuant to FERC-approved implementation protocols.  The protocols include a transparent, formal review process to verify the updated transmission rates are prudently-incurred and reasonably calculated.

The State Transcos’ and the Transmission Joint Ventures’ (where applicable) rates are included in the respective OATT for PJM and SPP.  An OATT is the FERC rate schedule that provides the terms and conditions for transmission and related services on a transmission provider’s transmission system.  The FERC requires transmission providers such as PJM and SPP to offer transmission service to all eligible customers (for example, load-serving entities, power marketers, generators and customers) on a non-discriminatory basis.

The FERC-approved formula rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners in annual rate base filings with the FERC.  The formula rates establish rates for a one-year period based on the current projects in-service and proposed projects for a defined timeframe.  The formula rates also include a true-up calculation for the previous year’s billings, allowing for over/under-recovery of the transmission owner’s ATRR.  PJM and SPP pay the transmission owners their ATRR for use of their facilities and bill transmission customers taking service under the PJM and SPP OATTs, based on the terms and conditions in the respective OATT for the service taken. Additionally, the State Transcos are subject to mandatory reliability standards promulgated by the NERC, with the approval of the FERC, which standards protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches. Management monitors pending matters before the FERC, including inquiries and challenges related to ROEs and transmission formula rates, that have the potential to reduce AEP’s future transmission formula rates and/or the transmission ROE methodology.

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In the annual formula rate filings described above, the State Transcos in aggregate filed formula rate base totals of $13.3 billion, $11.4 billion and $10.7 billion for 2025, 2024 and 2023, respectively.  The total filed transmission revenue requirements, including prior year over/under-recovery of revenue and associated carrying charges were $2.1 billion, $1.9 billion and $1.8 billion for 2025, 2024 and 2023, respectively.

The rates of ETT, which is located in ERCOT, are determined by the PUCT through a combination of base rate cases and interim Transmission Cost of Services (TCOS) filings.  ETT may file interim TCOS filings semi-annually to update its rates to reflect changes in its net invested capital.

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GENERATION & MARKETING

GENERAL

Generation & Marketing focuses primarily on a retail supply business and a wholesale energy trading and marketing business which includes executing transactions and negotiating contracts to maximize value and mitigate pricing and delivery risk in response to evolving customer needs and market conditions. The segment also includes rights to Cardinal Plant Unit 1’s power and capacity through 2028 pursuant to a PPA with a nonaffiliated electric cooperative. Generation & Marketing previously included AEP OnSite Partners prior to its sale in September 2024 and AEP Renewables prior to its sale in August 2023.

The retail energy supply business, AEP Energy, provides electricity and/or natural gas to residential, commercial and industrial customers in Illinois, Pennsylvania, Delaware, Maryland, New Jersey, Ohio and Washington, D.C.  AEP Energy had approximately 922,342 customer accounts as of December 31, 2025.

The wholesale trading and marketing business transacts within RTOs to provide supply to customers, manage pricing risk or otherwise provide service to fulfill contractual obligations. Additionally in certain instances this business procures physical electricity from identified sources, including renewable generation, when providing service to customers.

COMPETITION

Generation & Marketing subsidiaries face competition for the sale of available power, capacity and ancillary services.  The principal factors of impact are electricity and fuel prices, new market entrants, construction or retirement of generating assets by others and technological advances in power generation. Other factors impacting competitiveness include environmental regulation, transmission congestion or transportation constraints at or near generation facilities, inoperability or inefficiencies, outages and deactivations and retirements at generation facilities. Technology advancements, increased demand for clean energy, changing consumer behaviors, low-priced and abundant natural gas, and regulatory and public policy reforms are among the catalysts for transformation within the industry that impact competition for Generation & Marketing.

Generation & Marketing’s retail energy supply business operates in jurisdictions that each establish laws and regulations governing its competitive market, and public utility commission communications and utility default service pricing can affect customer participation in retail competition. Severe load and market volatility, sustained low market volatility and maturing competitive environments can adversely affect this business.

Counterparty Risk Management

Counterparties and exchanges may require cash or cash related instruments to be deposited on these transactions as margin against open positions.  As of December 31, 2025, counterparties posted approximately $146 million in cash, cash equivalents or letters of credit with AEP for the benefit of Generation & Marketing subsidiaries (while, as of that date, Generation & Marketing subsidiaries posted approximately $133 million with counterparties and exchanges).  Since open trading contracts are valued based on market prices of various commodities, exposures change daily.  See the “Quantitative and Qualitative Disclosures About Market Risk” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS

The following persons are executive officers of AEP.  Their ages are given as of February 12, 2026.  The officers are appointed annually for a one-year term by the board of directors of AEP.

William J. Fehrman

Chair of the Board of Directors, President and Chief Executive Officer

Age 65

Chair of the Board of Directors since August 2025. President and Chief Executive Officer since August 2024. Director of the Board from August 2024 to August 2025. President and Chief Executive Officer of Centuri Holdings, Inc. from January 2024 to July 2024. President, Chief Executive Officer and Director of Berkshire Hathaway Energy Company from 2018 to 2023.

Rob Berntsen

Executive Vice President, General Counsel and Secretary

Age 56

Executive Vice President and General Counsel since July 2025. Executive Vice President and Chief Legal and Compliance Officer at Xcel Energy from May 2024 to June 2025. Senior Vice President, Chief of Staff and General Counsel of BHE Renewables from May 2022 to May 2024. Senior Vice President and General Counsel of BHE Infrastructure Group from December 2020 to May 2022.

Doug Cannon

President - AEP Transmission

Age 49

President - AEP Transmission since June 2025. Chief Executive Officer of NV Energy from January 2019 to May 2025. President of NV Energy from February 2018 to May 2025.

Johannes Eckert

Executive Vice President and Chief Information & Technology Officer

Age 58

Executive Vice President and Chief Information & Technology Officer since July 2025. Senior Vice President and Chief Information & Technology Officer of Cox Communications from 2016 to 2025.

Kelly J. Ferneau

Executive Vice President and Chief Nuclear Officer

Age 57

Executive Vice President and Chief Nuclear Officer since November 2024. I&M Site Vice President - Donald C. Cook Plant from July 2022 to October 2024. I&M Plant Manager from 2018 to June 2022.

Alicia R. Knapp

President - Nuclear Development

Age 47

President - Nuclear Development since September 2025. President and CEO of BHE Renewables from December 2020 to September 2025.

Trevor I. Mihalik

Executive Vice President and Chief Financial Officer

Age 59

Executive Vice President and Chief Financial Officer since January 2025. Executive Vice President and Group President of Sempra from January 2024 to January 2025. Executive Vice President and Chief Financial Officer of Sempra from 2018 to 2023.

Phillip R. Ulrich

Executive Vice President and Chief Human Resources Officer

Age 54

Executive Vice President since January 2023. Chief Human Resources Officer since August 2021. Senior Vice President from August 2021 to December 2022. Chief Human Resources Officer of Flex, LTD from May 2019 to July 2021.

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ITEM 1A.   RISK FACTORS

GENERAL RISKS OF REGULATED OPERATIONS

AEP may not be able to recover the costs of substantial planned investment in capital improvements and additions. (Applies to all Registrants)

AEP’s business and capital investment plans call for extensive investment in capital improvements and additions, including the construction or acquisition of additional transmission and generation facilities, installation and interconnection with data centers, modernizing existing infrastructure, installation of environmental upgrades and retrofits as well as other initiatives.  AEP’s public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions.  If these regulatory commissions do not approve adjustments to the rates charged, affected AEP subsidiaries would not be able to recover the costs associated with their investments.  This would cause financial results to be diminished.

The business and capital investment plans of AEP depend, in part, on the continued growth and viability of data centers and large load customers interconnecting with the AEP System. (Applies to all Registrants)

AEP is experiencing current and projected load demands that exceed historical experience, creating a business need for new power generating resources and transmission facilities. Much of this demand is driven by interconnecting with and providing power to data centers and other large load customers to serve an increasingly digital economy and to support AI. The business and capital investment plans of AEP are focused on meeting these current and projected needs. If these increased demands for electricity do not occur as projected or are not sustained as projected, for any reason, it could affect AEP’s financial condition.

The business and capital investment plans of AEP are subject to execution risks. (Applies to all Registrants)

AEP’s business and capital investment plans for the construction of new projects, including providing service to new data centers and other large load customers, involve execution risks that could adversely affect AEP’s financial performance and/or impair AEP’s ability to execute on these plans. These risks include delays, supply chain disruption and the unavailability of materials, cost overruns, inflation, the cost and availability of capital, labor disputes or shortages and other factors that could cause the total cost and timing of any project to exceed estimates. While AEP utilizes measures to limit the impact of these events, if any of these projects are canceled for any reason, including shifts in large customer needs, preferences or financial stability, shifts in demand for large customer products or services, changes in technology, failure to receive necessary regulatory approvals, cost recovery and/or siting or environmental permits, mitigation efforts might not be sufficient and it could result in significant unrecoverable costs and the execution of AEP’s business and capital investment plans would be negatively impacted. In addition, if any construction work or investments have been recorded as an asset, an impairment may need to be recorded in the event a project is canceled. This would cause financial results to be diminished.

Meeting the significant increase in electricity demand from new data centers and other large‑load customers will require substantial investment in new generation and transmission facilities. These projects may require levels of capital that exceed historical utility financing needs, and the ability of the capital markets to supply sufficient funding for large‑scale infrastructure expansion is uncertain. AEP’s ability to undertake these capital‑intensive projects depends in part on continued access to debt and equity markets. If capital markets experience reduced liquidity, constrained capacity for utility issuances, or diminished investor appetite for long‑duration infrastructure investments, AEP may be unable to obtain the financing required to support these projects. Even if capital is available, it may only be obtainable at significantly higher cost due to market conditions or competition for capital among utilities and other sectors. Any inability to secure adequate financing could delay or prevent the construction of required facilities, impair AEP’s ability to serve its customers, and adversely affect future net income, cash flows and financial condition.

Regulated electric revenues and earnings are dependent on federal and state regulations that may limit AEP’s ability to recover costs and other amounts. (Applies to all Registrants)

The rates customers pay to AEP regulated utility businesses are subject to approval by the FERC and the respective state utility commissions of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. AEP cannot predict the ultimate outcomes of any actions by the FERC or the respective state commissions in establishing rates. The occurrence of any of the following could reduce future net income and cash flows and negatively impact financial condition:

•If regulated utility earnings exceed the return established by a relevant commission, that commission could reduce future rates;

•The overturning or reversal on appeal of previously authorized recovery; and

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•Any legislation, regulatory action or litigation outcome that triggers a reversal of a regulatory asset or deferred cost or establishment of a regulatory liability.

The regulated utility businesses, and the energy industry as a whole have experienced a period of rising costs and investments and an upward trend in spending, especially with respect to infrastructure investments, which are likely to continue in the foreseeable future. The increase in spending could trigger increased regulatory scrutiny to authorizing cost recovery, especially in a rising cost environment, whether due to inflation, tariffs, high fuel prices or otherwise, and/or in periods of economic decline or hardship. The inability to obtain cost recovery would adversely affect AEP’s business, financial position, results of operations and cash flows. See Note 4 - Rate Matters for additional information.

Regulated electric revenues and earnings are subject to prudency review. (Applies to all Registrants)

Regulators have initiated and may initiate additional proceedings to investigate the prudence of costs in the AEP regulated utility businesses. In these proceedings and in base rate proceedings regulators examine the reasonableness or prudence of operation and maintenance practices, the level of expenditures (including storm costs and costs associated with capital projects), the allowed rates of return and rate base, the proposed resource acquisitions and the previously incurred capital expenditures that the regulated utility businesses seek to keep or place in rates. Regulators may disallow costs found not to have been prudently incurred or found not to have been incurred in compliance with applicable tariffs, creating risk in the ultimate recovery of those costs. Disallowance of these costs would adversely affect AEP’s business, financial position, results of operations and cash flows.

Regulatory bodies may not allow recovery of costs incurred on a timely basis. (Applies to all Registrants)

Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or reduce rates. Traditional base rate proceedings generally have long timelines, are primarily based on historical costs and may or may not be limited in scope or duration by statute. The length of these base rate proceedings can cause the regulated utility businesses to experience regulatory lag in recovering costs and result in earning less than the allowed returns. Decisions are typically subject to appeal, further exacerbating the regulatory lag and leading to additional uncertainty associated with rate case proceedings.

AEP is subject to negative publicity. (Applies to all Registrants)

The AEP regulated utility businesses have large customer and stakeholder bases and, as a result, could be subject to public criticism or adverse publicity focused on issues including the operation and maintenance of their assets and infrastructure, their preparedness for major storms or other extreme weather events and/or the time it takes to restore service after such events, or the quality of their service or the reasonableness of the cost of their service. In addition, the public holds diverse and often conflicting views on the use of fossil fuels which can subject AEP to adverse publicity in connection with its use of fossil fuels. Criticism or adverse publicity of any nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view AEP or the applicable regulated utility in a favorable light and could potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight, more stringent legislative or regulatory requirements, or other legislation or regulatory actions that adversely affect the regulated utility businesses.

AEP’s transmission investment strategy and execution are dependent on federal and state regulatory policy and implementation by RTOs. (Applies to all Registrants)

A significant portion of AEP’s earnings is derived from transmission investments and activities.  FERC policy currently supports the expansion and updating of the transmission infrastructure within its jurisdiction.  If the FERC were to adopt a different policy, if states were to limit or restrict such policies, or if transmission needs do not continue or develop as projected, AEP’s strategy of investing in transmission could be impacted.  Further, AEP’s transmission strategy seeks to obtain authorization or to win bids to install, construct and operate new transmission lines and facilities.  However, there can be no assurance that PJM, SPP, ERCOT or other RTOs will authorize new transmission projects or will award such projects to AEP.  

Certain elements of AEP’s transmission formula rates have been challenged, which could result in lowered rates and/or refunds of amounts previously collected. (Applies to all Registrants other than AEP Texas)

AEP provides transmission service under rates regulated by the FERC. The FERC approved the cost-based formula rate templates used by AEP to calculate its respective annual revenue requirements, but it has not expressly approved the amount of actual capital and operating expenditures to be used in the formula rates. All aspects of AEP’s rates accepted or approved by the FERC, including the formula rate templates, the rates of return on the actual equity portion of its respective capital structures and the approved targeted capital structures, are subject to challenge by interested parties at the FERC, or by the

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FERC on its own initiative. In addition, interested parties may challenge the annual implementation and calculation by AEP of its projected rates and formula rate true-up pursuant to its approved formula rate templates under AEP’s formula rate implementation protocols. If a challenger can establish that any of these aspects are unjust, unreasonable, unduly discriminatory or preferential, then the FERC can make appropriate prospective adjustments to them and/or disallow any of AEP’s inclusion of those aspects in the rate setting formula.

Inquiries related to rates of return, as well as challenges to the formula rates of other utilities, are ongoing in other proceedings at the FERC.  The results of these proceedings could potentially negatively impact AEP in any future challenges to AEP’s formula rates.  If the FERC orders revenue reductions, including refunds, in any future cases related to its formula rates, it could reduce future net income and cash flows and impact financial condition.

End-use consumers and entities supplying electricity to end-use consumers may also attempt to influence government and/or regulators to change the rate setting methodologies that apply to AEP, particularly if rates for delivered electricity increase substantially.

AEP faces risks related to project siting, financing, construction, permitting, governmental approvals and the negotiation of project development agreements that may impede their development and operating activities. (Applies to all Registrants)

AEP owns, develops, constructs, manages and operates electric generation, transmission and distribution facilities. A key component of AEP's growth is its ability to construct and operate these facilities. As part of these operations AEP must periodically apply for licenses and permits from various local, state, federal and other regulatory authorities and abide by their respective conditions. Should AEP be unsuccessful in obtaining necessary licenses or permits on acceptable terms or resolving third-party challenges to such licenses or permits, should there be a delay in obtaining or renewing necessary licenses or permits or should regulatory authorities initiate any associated investigations or enforcement actions or impose related penalties or disallowances, it could reduce future net income and cash flows and impact financial condition. Any failure to timely construct contracted generation, transmission and distribution facilities or to negotiate successful project development agreements for new facilities with third-parties, including new data centers and large load customers, could impact future net income and cash flows and impact financial condition. Any failure to timely construct contracted generation, transmission and distribution facilities or to negotiate successful project development agreements for new facilities with third-parties, including new data centers and other large load customers, could impact future net income and cash flows and impact financial condition.

Changes in technology and regulatory policies may lower the value of electric utility facilities and franchises. (Applies to all Registrants)

AEP primarily generates electricity at large central facilities and delivers that electricity over its transmission and distribution facilities to customers usually situated within an exclusive franchise. This method results in economies of scale and generally lower costs than newer technologies, such as fuel cells and microturbines, and distributed generation using either new or existing technology.  Other technologies, such as light emitting diodes (LEDs), increase the efficiency of electricity and, as a result, lower the demand for it.  Changes in regulatory policies and advances in batteries or energy storage, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production and delivery.  These developments can challenge AEP’s competitive ability to maintain relatively low cost, efficient and reliable operations, to establish fair regulatory mechanisms and to provide cost-effective programs and services to customers.  In the event that lower cost alternatives for generation, as a result of changing regulatory policies, subsidies or advances in technology, are added to the available generation supply, they could displace current resources or reduce the price at which market participants sell their electricity.

AEP is exposed to nuclear generation risk. (Applies to AEP and I&M)

I&M owns the Cook Plant, which consists of two nuclear generating units for a rated capacity of 2,296 MWs, or about a tenth of the regulated generating capacity in the AEP System as of December 31, 2025.  AEP and I&M are, therefore, subject to the risks of nuclear generation, which include the following:

•The potential harmful effects on the environment and human health due to an adverse incident/event resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials such as SNF.

•Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations.

•Uncertainties with respect to contingencies and assessment amounts triggered by a loss event (federal law requires owners of nuclear units to purchase the maximum available amount of nuclear liability insurance unless the NRC specifies a lesser amount and potentially contribute to the coverage for losses of others).

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•Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

There can be no assurance that I&M’s preparations or risk mitigation measures will be adequate if these risks are triggered.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities.  In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved.  Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants.  In addition, if an incident did occur, it could harm results of operations or financial condition.  A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.  Moreover, a major incident at any nuclear facility in the U.S. could require AEP or I&M to make material contributory payments.

Costs associated with the operation (including fuel), maintenance and retirement of nuclear plants continue to be more significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements and safety standards, availability of nuclear waste disposal facilities and experience gained in the operation of nuclear facilities.  Costs also may include replacement power, any unamortized investment at the end of the useful life of the Cook Plant (whether scheduled or premature), the carrying costs of that investment and retirement costs.  The ability to obtain adequate and timely recovery of costs associated with the Cook Plant is not assured.

AEP subsidiaries are exposed to risks through participation in the market and transmission structures in various regional power markets that are beyond their control. (Applies to all Registrants)

Differences in the market and transmission structures in various regional power markets are likely to affect results.  The rules governing the various RTOs, including SPP and PJM, may also change from time to time which could affect costs or revenues.  Existing, new or changed rules of these RTOs could result in significant additional fees and increased costs to participate in those structures, including the cost of transmission and generation facilities built by others due to changes in rules and allocations, including transmission rate design. In addition, these RTOs may assess costs resulting from improved transmission reliability, reduced transmission congestion and firm transmission rights. As members of these RTOs, AEP’s subsidiaries are subject to certain additional risks, including the allocation among existing members, of losses caused by unreimbursed defaults of other participants in these markets and resolution of complaint cases that may seek refunds of revenues previously earned by members of these markets.

AEP could be subject to higher costs and/or penalties related to mandatory reliability standards. (Applies to all Registrants)

Owners and operators of the bulk power transmission system are subject to mandatory reliability standards promulgated by the NERC and enforced by the FERC.  The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles.  Compliance with new reliability standards may subject AEP to higher operating costs and/or increased capital expenditures.  If AEP were found not to be in compliance with the mandatory reliability standards, AEP could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates.

A substantial portion of the receivables of AEP Texas is concentrated in a small number of REPs, and any delay or default in payment could adversely affect its cash flows, financial condition and results of operations. (Applies to AEP and AEP Texas)

AEP Texas collects receivables from the distribution of electricity from REPs that supply the electricity it distributes to its customers. As of December 31, 2025, AEP Texas did business with approximately 146 REPs. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for these services or could cause them to delay such payments. AEP Texas depends on these REPs to remit payments on a timely basis. In 2025, AEP Texas’ two largest REPs accounted for 38% of its operating revenue. Any delay or default in payment by REPs could adversely affect cash flows, financial condition and results of operations. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations, and claims might be made by creditors involving payments AEP Texas had received from such REP.

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RISKS RELATED TO MARKET, ECONOMIC OR FINANCIAL VOLATILITY AND OTHER RISKS

AEP’s financial performance may be adversely affected if AEP is unable to successfully operate facilities or perform certain corporate functions. (Applies to all Registrants)

Performance is highly dependent on the successful operation of generation, transmission and/or distribution facilities.  Operating these facilities involves many risks, including:

•Operator error and breakdown or failure of equipment or processes.

•Operating limitations that may be imposed by environmental or other regulatory requirements.

•Labor disputes.

•Compliance with mandatory reliability standards, including mandatory cybersecurity standards.

•Information technology failure, including failure of AI technology, that impairs AEP’s information technology infrastructure or disrupts normal business operations.

•Information technology failure that affects AEP’s ability to access customer information or causes loss of confidential or proprietary data that materially and adversely affects AEP’s reputation or exposes AEP to legal claims.

•Supply chain disruptions and inflation.

•Fuel or water supply interruptions caused by transportation constraints, adverse weather such as drought, non-performance by suppliers and other factors.

•Catastrophic events such as extreme weather, fires, earthquakes, explosions, hurricanes, tornadoes, winter storms, terrorism (including cyber-terrorism), floods or other similar occurrences.

•Fuel costs and related requirements triggered by financial stress in the coal industry.

Physical attacks or hostile cyber intrusions could severely impair operations, lead to the disclosure of confidential information and damage AEP’s reputation. (Applies to all Registrants)

Risks from cybersecurity and physical threats to energy infrastructure are increasing. Threat actors, including sophisticated nation-state actors and criminal groups, exploit potential vulnerabilities in the electric utility industry, grid infrastructure and other energy infrastructures. Attacks and disruptions, which could involve physical, cyber and hybrid targeting of physical and cyber assets, are increasingly sophisticated and dynamic. The increased implementation of, and reliance on, information technologies and networks to manage business operations, including the operation of technical systems, as well as AEP’s use of numerous vendors and suppliers, create additional points of vulnerability that could be, and in certain instances have been, exploited by malicious threat actors. Several U.S. government agencies have warned that the energy sector and its supply chains are subject to increasing risks of physical attacks, ransomware attacks and cybersecurity threats, and that the risks may escalate during periods of heightened geopolitical tensions. In addition, the rapid evolution and increased adoption of AI technologies may intensify AEP’s cybersecurity risks.

A security breach of AEP’s physical assets or information systems, or those of AEP’s competitors, vendors, business partners and interconnected entities (including RTOs) could materially impact AEP by, among other things, impairing the availability of electricity transmitted and distributed by AEP and/or the reliability of generation, transmission and distribution systems, damaging grid infrastructure, interrupting critical business functions, impairing the availability of vendor services and materials that AEP relies on to maintain its operations, or by leading to the theft or inappropriate release of certain types of information, including critical infrastructure information, system data and architecture, sensitive customer, vendor, or employee data, or other confidential data.

AEP has not identified any cybersecurity incidents that have materially affected or are reasonably likely to materially affect its business strategy, results of operation or financial condition.

If a material physical or cybersecurity breach or disruption were to occur, AEP’s reputation could be negatively affected, customer confidence in AEP could be diminished and AEP could be subject to legal claims, regulatory exposure, loss of revenues, and increased costs, including infrastructure repairs or operations shutdown, all of which could materially affect AEP’s financial condition and materially damage its business reputation. Moreover, the amount and scope of insurance maintained against losses resulting from any such security breaches or disruptions may not be sufficient to cover losses or otherwise adequately compensate for any resulting business disruptions. The continued increase in federal and state regulatory requirements related to cybersecurity and evolving threat actor-capabilities could require changes to measures currently undertaken by AEP or to its business operations and could adversely affect its financial condition.

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The failure of AEP or third-party vendor information technology systems, or the failure to enhance existing information technology systems and implement new technology, could adversely affect AEP. (Applies to all Registrants)

AEP’s operations are dependent upon the proper functioning of its internal systems, including the information technology systems that support underlying business processes. Any significant failure or malfunction of such information technology systems may result in disruptions of operations. AEP’s information technology systems are dependent upon global communications and cloud service providers, as well as their respective vendors, many of whom have at some point experienced significant system failures and outages in the past and may experience such failures and outages in the future. These providers’ systems are susceptible to cybersecurity and data breaches, outages from fire, floods, power loss, telecommunications failures, break-ins and similar events. Failure to prevent or mitigate data loss from system failures or outages could materially affect AEP’s results of operations, financial position and cash flows.

The amount of taxes imposed on AEP could change. (Applies to all Registrants)

AEP is subject to income taxation at the federal level and by certain states and municipalities. In determining AEP’s income tax liability for these jurisdictions, management monitors changes to the applicable tax laws and related regulations, administrative interpretations and judicial determinations, including tax incentives and credits designed to support the sale of energy from utility scale renewable energy facilities. While management believes AEP complies with current prevailing laws, one or more taxing jurisdictions could seek to impose incremental or new taxes on the company. At the federal level, management is monitoring the potential for changes in current tax policy, including tax rates, tax credits and incentives. Any adverse developments in tax laws, incentives, credits or regulations, including legislative changes, judicial holdings or administrative interpretations, could have a material and adverse effect on financial condition and results of operations.

Changes in U.S. or foreign trade policies, including the imposition of tariffs and other protectionist trade measures, and other factors beyond AEP’s control may adversely impact future net income and cash flows and financial condition.

Executive actions have been taken and additional measures proposed that are intended to alter the U.S. approach to international trade policy, the terms of certain existing bilateral or multi‐lateral trade agreements and trading arrangements with foreign countries. Such changes to U.S. international trade policy, and any retaliatory trade measures that foreign governments may take in response, including the imposition of tariffs, sanctions, export or import controls, or other measures that restrict international trade, or the threat of such actions, could result in additional increases in the cost of certain goods, services and cost of capital and exacerbate supply chain issues. In addition, related geopolitical and domestic political developments, such as existing and potential trade wars, uncertainty regarding changes in trade policy, and other events beyond AEP’s control, have increased and may continue to increase levels of political and economic unpredictability globally and the volatility of global financial markets. As a result, prevailing economic conditions may reduce future net income and cash flows and negatively impact financial condition.

If AEP is unable to access capital markets or insurance markets on reasonable terms, for any reason, including negative publicity, it could reduce future net income and cash flows and negatively impact financial condition. (Applies to all Registrants)

AEP relies on access to capital markets as a significant source of liquidity for capital requirements not satisfied by operating cash flows. AEP also relies on access to insurance markets to assist in managing its risk and liability profile. Volatility, increased interest rates and reduced liquidity in the financial markets could affect AEP’s ability to raise capital on reasonable terms to fund capital needs, including construction costs and refinancing maturing indebtedness. In addition, AEP has exposure to international banks, including those in Europe, Canada and Asia. Disruptions in these markets could reduce or restrict AEP’s ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2025, approximately 8%, 23% and 15% of the Registrants’ available credit facilities were with European, Canadian, and Asian banks, respectively.

In the past, certain sources of insurance and debt and equity capital have expressed unwillingness to provide insurance for or to invest in companies, such as AEP, that rely on fossil fuels. The public holds diverse and often conflicting views on the use of fossil fuels. AEP has multiple stakeholders, including shareholders, customers, associates, federal and state regulatory authorities and the communities in which AEP operates, and these stakeholders will often have differing priorities and expectations regarding issues related to the use of fossil fuels. Any adverse publicity in connection with AEP’s use of fossil fuels could curtail availability from certain sources of capital. Additionally, certain terms that AEP may be required to include in its financing agreements and arrangements may not be acceptable to certain investors, which could limit the availability of, or increase the cost of, capital.

If sources of capital for AEP are reduced, capital costs could increase materially. Restricted access to capital or insurance markets and/or increased borrowing costs or insurance premiums could reduce future net income and cash flows and negatively

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impact financial condition. If AEP is not able to access debt or equity at competitive rates or at all, the ability to finance its operations and implement its strategy and business plan as scheduled could be adversely affected. An inability to access debt and equity may limit AEP’s ability to pursue improvements or acquisitions that it may otherwise rely on for future growth.

Shareholder activism could cause AEP to incur significant expense, hinder execution of AEP’s business strategy and impact AEP’s stock price. (Applies to all Registrants)

Shareholder activism, which can take many forms and arise in a variety of situations, could result in substantial costs and divert management’s and the AEP Board’s attention and resources from AEP’s business. Additionally, such shareholder activism could give rise to perceived uncertainties as to AEP’s future, adversely affect AEP’s relationships with its employees, customers or service providers and make it more difficult to attract and retain qualified personnel. Also, AEP may be required to incur significant fees and other expenses related to activist shareholder matters, including for third-party advisors. AEP’s stock price could be subject to significant fluctuation or otherwise be adversely affected by the events, risks and uncertainties of any shareholder activism.

Downgrades in AEP’s credit ratings could negatively affect its ability to access capital. (Applies to all Registrants)

The credit ratings agencies periodically review AEP’s capital structure and the quality and stability of earnings and cash flows. From time to time, AEP’s financial metrics have approached, and may in the future approach, thresholds designated by the credit rating agencies for potential ratings downgrades.  Any negative ratings actions could constrain the capital available to AEP and could limit access to funding for operations.  AEP’s business is capital intensive, and AEP is dependent upon the ability to access capital at rates and on terms management determines to be attractive.  If AEP’s ability to access capital becomes significantly constrained, AEP’s interest costs will likely increase and that could reduce future net income and cash flows and negatively impact financial condition.

AEP and AEPTCo have no income or cash flow apart from dividends paid or other payments due from their subsidiaries. (Applies to AEP and AEPTCo)

AEP and AEPTCo are holding companies and have no operations of their own.  Their ability to meet their financial obligations associated with their indebtedness and to pay dividends is primarily dependent on the earnings and cash flows of their operating subsidiaries, primarily their regulated utilities, and the ability of their subsidiaries to pay dividends to them or repay loans from them.  Their subsidiaries are separate and distinct legal entities that have no obligation (apart from loans from AEP or AEPTCo) to provide them with funds for their payment obligations, whether by dividends, distributions or other payments.  Payments to AEP or AEPTCo by their subsidiaries are also contingent upon their earnings and business considerations.  AEP and AEPTCo indebtedness and dividends are structurally subordinated to all subsidiary indebtedness. Accordingly, restrictions on the ability of AEP’s subsidiaries to pay dividends to AEP and AEPTCo could materially impact the amount of cash flow available to, and received by, AEP and AEPTCo.

Volatility in the securities markets, interest rates, and other factors could substantially increase defined benefit pension and other postretirement plan costs and the costs of nuclear decommissioning. (Applies to all Registrants and to AEP and I&M with respect to the costs of nuclear decommissioning)

The costs of providing pension and other postretirement benefit plans are dependent on a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plan, changes in actuarial assumptions, future government regulation, changes in life expectancy and the frequency and amount of AEP’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 AEP could be required from time to time to fund the pension plan with significant amounts of cash. Such cash funding obligations could have a material impact on liquidity by reducing cash flows and could negatively affect results of operations.

Additionally, I&M holds a significant amount of assets in its nuclear decommissioning trusts to satisfy obligations to decommission its nuclear plant. The rate of return on assets held in those trusts can significantly impact both the costs of decommissioning and the funding requirements for the trusts.

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Supply chain disruptions, tariffs and inflation could negatively impact operations and corporate strategy. (Applies to all Registrants)

AEP’s operations and business plans depend on the global supply chain to procure the equipment, materials and other resources necessary to build and provide services in a safe and reliable manner. The delivery of components, materials, equipment and other resources that are critical to AEP’s business operations and corporate strategy are affected by domestic and global supply chain upheaval. This can result in the shortage of critical items. International tensions from any source, including the ramifications of regional conflict or increased tariffs, could further exacerbate global supply chain upheaval. Any disruptions and shortages could adversely impact business operations and corporate strategy. The current administration has implemented tariffs on certain imported goods and may impose additional tariffs. The constraints in the supply chain could restrict the availability and delay the construction, maintenance or repair of items that are needed to support normal operations or are required to execute on AEP’s corporate strategy for continued capital investment in utility equipment and impact AEP’s strategy to transition its generation fleet. These disruptions and constraints could reduce future net income and cash flows and impact financial condition.

The United States economy has experienced an inflationary environment and supply chain disruptions have contributed to higher prices of components, materials, equipment and other needed commodities. A prolonged continuation or a further increase in the severity of supply chain and inflationary disruptions, including increased tariffs, could result in additional increases in the cost of certain goods, services and cost of capital and further extend lead times. AEP typically recovers increases in capital expenses from customers through rates in regulated jurisdictions. Failure to recover increased capital costs could reduce future net income and cash flows and possibly harm AEP’s financial condition. Increases in inflation raises costs for labor, materials and services, and failure to secure these on reasonable terms may adversely impact financial condition.

AEP’s results of operations and cash flows may be negatively affected by a lack of growth or slower growth in the number of customers, a decline in customer demand or a recession. (Applies to all Registrants)

Growth in customer accounts and growth of customer usage each directly influence demand for electricity and the need for additional power generation and delivery facilities.  Customer growth and customer usage are affected by a number of factors outside the control of AEP, such as economic and demographic conditions, population changes, job and income growth, housing starts, new business formation and the overall level of economic activity.  Some or all of these factors could impact the demand for electricity.

Failure to attract and retain an appropriately qualified workforce and management could harm results of operations. (Applies to all Registrants)

Certain events, such as an aging workforce without appropriate replacements, mismatch of skillset or complement to future needs, or unavailability of contract resources may lead to operating challenges and increased costs. The challenges include potential higher rates of existing employee departures, lack of resources, loss of knowledge and a lengthy time period associated with skill development. Advancements in artificial intelligence and other emerging technologies may require significant changes to the size, skills, and composition of AEP’s workforce, and the inability to adapt to these evolving talent needs could exacerbate existing workforce challenges and adversely affect AEP’s operations and financial performance. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate the business. If AEP is unable to successfully attract and retain an appropriately qualified workforce, operations may be negatively impacted and future net income and cash flows may be reduced.

Difficulties in sustaining leadership continuity could negatively impact AEP’s business and financial condition. The ability to maintain strong leadership relies on effective succession planning, and gaps in preparing or transitioning individuals into critical roles may impact performance.

Changes in the price of purchased power and commodities, the cost of procuring fuel, emission allowances for criteria pollutants and the costs of transport may increase AEP’s cost of purchasing and producing power, impacting financial performance. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

AEP is exposed to changes in the price and availability of purchased power and fuel (including the cost to procure coal and gas) and the price and availability to transport fuel.  

•AEP is exposed to changes in the price and availability of fuel, including coal, natural gas and uranium, as existing contracts for the supply of such fuel end or are not honored.

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•The inability to procure fuel at costs that are economical could cause AEP to retire generating capacity prior to the end of its useful life.

•AEP is exposed to changes in the price and availability of emission allowances.

•AEP is exposed to changes in the price and availability of diesel, the primary fuel used in transporting coal by barge.

While AEP typically recovers such fuel-related expenses pursuant to rate recovery mechanisms in regulated jurisdictions, the failure to recover these costs could reduce future net income and cash flows and possibly harm AEP’s financial condition.

Prices for coal, natural gas and emission allowances have shown material swings in the past.  Changes in the cost of purchased power, fuel or emission allowances and changes in the relationship between such costs and the market prices of power could reduce future net income and cash flows and negatively impact financial condition. In addition, actual power prices and fuel costs will differ from those assumed in financial projections used to value trading and marketing transactions, and those differences may be material.  As a result, as those transactions are marked-to-market, they may impact future results of operations and cash flows and impact financial condition.

AEP is subject to physical and financial risks associated with climate change. (Applies to all Registrants)

Climate change creates physical and financial risk.  Physical risks from climate change may include an increase in sea level and changes in weather conditions, such as changes in precipitation and extreme weather events, such as fires.  Customers’ energy needs vary with weather conditions, primarily temperature and humidity.  For residential customers, heating and cooling represent their largest energy use.  To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes.

Increased energy use due to weather changes may require AEP to invest in additional generating assets, transmission and other infrastructure to serve increased load.  Decreased energy use due to weather changes may affect financial condition through decreased revenues.  Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions.  Weather conditions outside of the AEP service territory could also have an impact on revenues.  AEP buys and sells electricity depending upon system needs and market opportunities.  Extreme weather conditions creating high energy demand on AEP’s own and/or other systems may raise electricity prices as AEP buys short-term energy to serve AEP’s own system, which would increase the cost of energy AEP provides to customers.

Severe weather and weather-related events impact AEP’s service territories, primarily when thunderstorms, tornadoes, hurricanes, fires, floods and snow or ice storms occur.  To the extent the frequency and intensity of extreme weather events and storms increase, AEP’s cost of providing service will increase, including the costs and the availability of procuring insurance related to such impacts, and these costs may not be recoverable.  Changes in wind patterns or in precipitation resulting in droughts, water shortages or floods could adversely affect operations, principally wind generation facilities for changes in wind patterns and the fossil fuel generating units for changes in precipitation. A change in wind patterns or a negative impact to water supplies due to long-term drought conditions or severe flooding could adversely impact AEP’s ability to provide electricity to customers, as well as increase the price they pay for energy.  AEP may not recover all costs related to mitigating these physical and financial risks.

To the extent climate change impacts a region’s economic health, it may also impact revenues.  AEP’s financial performance is tied to the health of the regional economies AEP serves.  The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods and services, impacts the economic health of the communities within AEP’s service territories. Climate change may impact the economy, which could impact sales and revenues. The cost of additional regulatory requirements, such as regulation of carbon dioxide emissions, could impact the availability of goods and prices charged by AEP’s suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and carbon dioxide emissions as a financial risk, this could negatively affect AEP’s ability to access capital markets or cause AEP to receive less than ideal terms and conditions in capital markets.

The occurrence of one or more wildfires could cause tremendous loss, impact the market value and credit ratings of Registrants’ securities and have a material adverse effect on Registrants’ financial condition. (Applies to all Registrants)

More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. AEP’s infrastructure could pose risks to safety and system reliability and wildfire mitigation initiatives may not be successful or effective in preventing or reducing wildfire-related events. Wildfires can occur even when effective mitigation procedures are followed. Despite AEP’s early-stage wildfire mitigation initiatives, a wildfire could be ignited, spread and cause damages, which could subject AEP to significant liability. Other potential risks associated with wildfires include the inability to secure sufficient insurance coverage, increased costs for insurance and

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mitigation efforts, regulatory recovery risk, litigation risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets.

The generation, transmission and distribution of electricity are dangerous and involve inherent risks of damage to private property and injury to AEP’s workforce and the general public. (Applies to all Registrants)

Electricity poses hazards for AEP’s workforce and the general public in the event that either comes in contact with electrical current or equipment, including through energized downed power lines or through equipment malfunctions. In addition, the risks associated with the operation of transmission and distribution assets and power generation and storage facilities include public and workforce safety issues and the risk of utility assets causing or contributing to wildfires, explosions, mechanical failure, unscheduled downtime, equipment interruptions, remediation, chemical and oil spills, discharges or releases of toxic or hazardous substances or gases and other environment risks. Deaths, injuries and property damage caused by such events can subject AEP to liability that, despite the existence of insurance coverage, can be significant. In addition, AEP may be held responsible for the actions of its contractors. No assurance can be given that future losses will not exceed the limits of AEP’s or its contractors’ insurance coverage. An occurrence of any of these hazards may also result in suspension of operations and the imposition of civil or criminal penalties.

Adverse outcomes in AEP’s material legal proceedings could materially and adversely affect AEP’s results of operations and financial condition. (Applies to all Registrants)

AEP is involved in legal proceedings, claims and litigation arising out of its business operations, the most significant of which are summarized in Note 6 - Commitments, Guarantees and Contingencies.  Management cannot predict the outcome of such legal proceedings. Adverse outcomes in these proceedings could require significant expenditures that could reduce future net income and cash flows and negatively impact financial condition.

Disruptions at power generation facilities owned by third-parties could interrupt the sales of transmission and distribution services. (Applies to AEP, AEP Texas and OPCo)

AEP Texas and OPCo transmit and distribute electric power obtained from power generation facilities owned by third-parties or affiliates. If power generation is disrupted or if power generation capacity is inadequate, sales of transmission and distribution services may be diminished or interrupted, and results of operations, financial condition and cash flows could be adversely affected.

Most of the real property rights on which the assets of AEPTCo are situated result from affiliate license agreements and are dependent on the terms of the underlying easements and other rights of its affiliates. (Applies to AEPTCo)

AEPTCo does not hold title to the majority of real property on which its electric transmission assets are located. Instead, under the provisions of certain affiliate contracts, it is permitted to occupy and maintain its facilities upon real property held by the respective AEP subsidiary utility affiliate that overlay its operations. The ability of AEPTCo to continue to occupy such real property is dependent upon the terms of such affiliate contracts and upon the underlying real property rights of these utility affiliates, which may be encumbered by easements, mineral rights and other similar encumbrances that may affect the use of such real property. AEP can give no assurance that (a) the relevant AEP subsidiary utility affiliates will continue to be affiliates of AEPTCo, (b) suitable replacement arrangements can be obtained in the event that the relevant AEP subsidiary utility affiliates are not its affiliates and (c) the underlying easements and other rights are sufficient to permit AEPTCo to operate its assets in a manner free from interruption.

Compliance with legislative and regulatory requirements may lead to increased costs and result in penalties. (Applies to all Registrants)

Business activities of electric utilities and related companies are heavily regulated, primarily through national and state laws and regulations of general applicability, including laws and regulations related to working conditions, health and safety, equal employment opportunity, employee benefit and other labor and employment matters, laws and regulations related to competition and antitrust matters. Many agencies employ mandatory civil penalty structures for regulatory violations. Registrants are subject to the jurisdiction of many federal and state agencies, including the FERC, NERC, Commodity Futures Trading Commission, Federal EPA, NRC, Occupational Safety and Health Administration, the SEC and the United States Department of Justice which may impose significant civil and criminal penalties to enforce compliance requirements relative to AEP’s business, which could have a material adverse impact on results of operations and cash flows and impact financial condition.

The impact of new laws, regulations and policies and the related interpretations, as well as changes in enforcement practices or

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regulatory scrutiny generally cannot be predicted, and changes in applicable laws, regulations and policies and the related interpretations and enforcement practices may require extensive system and operational changes, be difficult to implement, increase AEP’s operating costs, require significant capital expenditures, or adversely impact the cost or attractiveness of the products or services AEP offers, or result in adverse publicity and harm AEP’s reputation.

RISKS RELATED TO OWNING AND OPERATING GENERATION ASSETS AND SELLING POWER

Costs of compliance with existing and evolving environmental laws are significant. (Applies to all Registrants except AEPTCo)

AEP’s operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety.  A majority of the electricity generated by AEP is produced by the combustion of fossil fuels.  Emissions of nitrogen and sulfur oxides, mercury and particulates and the discharge and disposal of solid waste (including coal-combustion residuals or CCR) resulting from fossil fueled generation plants are subject to increased regulations, controls and mitigation expenses.  Compliance with the sometimes evolving criteria of these legal requirements (including any newly adopted requirements and/or more stringent application of existing regulations, including CCR requirements that could result from either agency action or litigation) can be difficult. While management believes AEP complies with current prevailing laws and regulations, there can be no assurance that AEP’s efforts will be deemed to have been sufficient in a litigation or regulatory review context. Compliance requires AEP to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees, disposal, remediation and permits at AEP facilities and could require AEP to retire generating capacity prior to the end of its estimated useful life.  Costs of compliance with environmental statutes and regulations, and penalties or damages assessed for noncompliance, could reduce future net income and negatively impact financial condition, especially if emission limits, CCR waste discharge and/or discharge disposal obligations are tightened, more extensive operating and/or permitting requirements are imposed or additional substances or facilities become regulated.

Regulation of GHG emissions could materially increase costs to AEP and its customers or cause some electric generating units to be uneconomical to operate or maintain. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

Federal or state laws or regulations may be adopted that could impose new or additional limits on the emissions of greenhouse gases, including, but not limited to, carbon dioxide and methane, from electric generation units using fossil fuels like coal. The potential effects of greenhouse gas emission limits on AEP's electric generation units are subject to significant uncertainties based on, among other things, the timing of the implementation of any new requirements, the required levels of emission reductions, the nature of any market-based or tax-based mechanisms adopted to facilitate reductions, the relative availability of greenhouse gas emission reduction offsets, the development of cost-effective, commercial-scale carbon capture and storage technology and supporting regulations and liability mitigation measures, and the range of available compliance alternatives.

AEP’s results of operations could be materially adversely affected to the extent that new federal or state laws or regulations impose any new greenhouse gas emission limits. Any future limits on greenhouse gas emissions could create substantial additional costs in the form of taxes or emissions allowances, require significant capital investment in carbon capture and storage technology, fuel switching, or the replacement of high-emitting generation facilities with lower-emitting generation facilities and/or could cause AEP to retire generating capacity prior to the end of its estimated useful life. Although AEP typically recovers environmental expenditures, there can be no assurance in the future that AEP can recover such costs which could reduce future net income and cash flows and possibly harm financial condition. Further, real or alleged violations of environmental regulations, including those related to climate change, could reduce future net income and cash flows and possibly harm financial condition.

AEP may be unable to procure or construct generation capacity when needed or to recover the costs of such generation capacity. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

AEP’s capacity obligations are subject to a number of factors including load growth, requirements that can be imposed by the states, RTOs and other jurisdictions in which it operates or participates as a member and the retirement of existing generating facilities. AEP must obtain new and replacement generation to comply with prevailing capacity needs and reserve obligations. AEP’s ability to acquire, retrofit and/or construct power generation facilities in a timely manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise, escalating costs for capital, materials, labor, and environmental compliance, changes in RTO cost allocation and cost recovery, reliance on suppliers for timely and satisfactory performance, delays and cost increases, and supply chains and material constraints, including those that may result from major storm events. Delays in obtaining permits, challenges in securing suitable land for the siting, shortages in materials and qualified labor, levels of public support or opposition, suppliers and contractors not performing as expected or required under their contracts and/or experiencing financial problems that inhibit

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their ability to fulfill their obligations under contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, further direct and indirect trade and tariff issues, supply chain delays or disruptions, and other events beyond AEP’s control may occur that may materially affect the schedule, cost, and performance of needed acquisitions or construction projects. If these projects or other capital improvements are significantly delayed or become subject to cost overruns or cancellation, AEP could incur additional costs and termination payments or face increased risk of potential write-off of the investment in the project. In addition, AEP could be exposed to higher costs, penalties and market volatility, which could affect cash flow and cost recovery, should one or more applicable regulator decline to approve the acquisition or construction of the project or new generation needed to meet the reliability needs of customers at the lowest reasonable cost.

Courts adjudicating nuisance and other similar claims in the future may order AEP to pay damages or to limit or reduce emissions. (Applies to all Registrants except AEP Texas and AEPTCo)

In the past, there have been several cases seeking damages based on allegations of federal and state common law nuisance in which AEP, among others, were defendants.  In general, the actions allege that emissions from the defendants’ power plants constitute a public nuisance.  The plaintiffs in these actions generally seek recovery of damages and other relief.  If future actions are resolved against AEP, substantial modifications or retirement of AEP’s existing coal-fired power plants could be required, and AEP might be required to purchase power from third-parties to fulfill AEP’s commitments to supply power to AEP customers.  This could have a material impact on revenues.  In addition, AEP could be required to invest significantly in additional emission control equipment, accelerate the timing of capital expenditures, pay damages or penalties and/or halt operations.  Unless recovered, those costs could reduce future net income and cash flows and harm financial condition.  Moreover, results of operations and financial position could be reduced due to the timing of recovery of these investments and the expense of ongoing litigation.

Commodity trading and marketing activities are subject to inherent risks which can be reduced and controlled but not eliminated. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

AEP routinely has open trading positions in the market, within guidelines set by AEP, resulting from the management of AEP’s trading portfolio.  To the extent open trading positions exist, fluctuating commodity prices can improve or diminish financial results and financial position. AEP’s power trading activities also expose AEP to risks of commodity price movements.  To the extent that AEP’s power trading does not hedge the price risk associated with the generation it owns, or controls, AEP would be exposed to the risk of rising and falling spot market prices. In connection with these trading activities, AEP routinely enters into financial contracts, including futures and options, OTC options, financially-settled swaps and other derivative contracts.  These activities expose AEP to risks from price movements.  If the values of the financial contracts change in a manner AEP does not anticipate, it could harm financial position or reduce the financial contribution of trading operations.

Parties with whom AEP has contracts may fail to perform their obligations, which could harm AEP’s results of operations. (Applies to all Registrants)

AEP sells power from its generation facilities into the spot market and other competitive power markets on a contractual basis. AEP also enters into contracts to purchase and sell electricity, natural gas, emission allowances, renewable energy credits and coal as part of its power marketing and energy trading operations. AEP is exposed to the risk that counterparties that owe AEP money or the delivery of a commodity, including power, could breach their obligations.  Should the counterparties to these arrangements fail to perform, AEP may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices that may exceed AEP’s contractual prices, which would cause financial results to be diminished and AEP might incur losses.  Although estimates take into account the expected probability of default by a counterparty, actual exposure to a default by a counterparty may be greater than the estimates predict.

AEP relies on electric transmission facilities that AEP does not own or control.  If these facilities do not provide AEP with adequate transmission capacity, AEP may not be able to deliver wholesale electric power to the purchasers of AEP’s power. (Applies to all Registrants)

AEP depends on transmission facilities owned and operated by other nonaffiliated power companies to deliver the power AEP sells at wholesale.  This dependence exposes AEP to a variety of risks.  If transmission is disrupted, or transmission capacity is inadequate, AEP may not be able to sell and deliver AEP wholesale power.  If a region’s power transmission infrastructure is inadequate, AEP’s recovery of wholesale costs and profits may be limited.  If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure.

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OVEC may require additional liquidity and other capital support.  (Applies to AEP, APCo, I&M and OPCo)

AEP and several nonaffiliated utility companies own OVEC. The Inter-Company Power Agreement (ICPA) defines the rights and obligations and sets the power participation ratio of the parties to it. Under the ICPA, parties are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MWs) in proportion to their respective power participation ratios. The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%. If a party fails to make payments owed by it under the ICPA, OVEC may not have sufficient funds to honor its payment obligations, including its ongoing operating expenses as well as its indebtedness. As of December 31, 2025, OVEC has outstanding indebtedness of approximately $873 million, of which APCo, I&M and OPCo are collectively responsible for $379 million through the ICPA. Although they are not an obligor or guarantor, APCo, I&M and OPCo are responsible for their respective ratio of OVEC’s outstanding debt through the ICPA and if OVEC’s indebtedness is accelerated for any reason, there is risk that APCo, I&M and/or OPCo may be required to pay some or all of such accelerated indebtedness in amounts equal to their aggregate power participation ratio of 43.47%.

ITEM 1B.   UNRESOLVED STAFF COMMENTS

None.

ITEM 1C.   CYBERSECURITY

Cybersecurity is a critical component of AEP’s risk management framework. As an electric utility operating critical infrastructure, AEP is subject to mandatory requirements under applicable federal, state, and industry standards. AEP maintains a risk-based cybersecurity program designed to protect the confidentiality, integrity, and availability of its information technology, operational technology, and critical infrastructure assets.

Cybersecurity Risk Management and Strategy

AEP’s cybersecurity risk management program is designed to identify, assess, and manage risks from cybersecurity threats, including those posed by third parties. The program incorporates a defense-in-depth approach, leverages partnerships with government and peers to assess the evolving threats and aligns with recognized industry standards and regulatory requirements applicable to electric utilities.

Key elements of AEP’s cybersecurity program include, among others:

•Continuous monitoring and detection of cyber threats;

•Vulnerability assessments and penetration testing;

•Incident response planning and exercises;

•Business continuity and disaster recovery planning;

•Security awareness training, including advanced phishing simulations;

•Third-party risk management, including vendor due diligence and contractual controls;

•Cybersecurity insurance coverage.

AEP regularly evaluates and updates its cybersecurity controls, processes, and technologies in response to the evolving threat landscape and regulatory developments. We leverage both internal expertise and external partners to assist with assessments, testing, and program maturity evaluations.

Governance and Oversight

AEP’s Board of Directors, through the Technology Committee, oversees the cybersecurity program and our approach to cyber risk management. The Technology Committee receives periodic updates from management regarding cybersecurity risks, the threat environment, and the status of AEP’s security programs, including significant incidents, if any.

Management’s Role and Expertise

Management is responsible for implementing and maintaining AEP’s cybersecurity programs. Day-to-day oversight is led by AEP’s Senior Vice President (SVP) of Enterprise Security, Resilience, and National Security Policy who reports to AEP’s Chief Executive Officer. The SVP for Enterprise Security, Resilience, and National Security Policy has expertise in electricity sector risk management, critical infrastructure protection, cybersecurity, and incident response. This individual also oversees and leads AEP’s engagements with Federal agencies on cybersecurity and physical security threat information sharing and

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partnerships with the Department of Homeland Security, Federal Bureau of Investigation, Department of Energy, and the intelligence community. The SVP for Enterprise Security, Resilience, and National Security Policy also works closely with AEP’s Chief Information Officer, Generation, Transmission, and Distribution operations leadership, along with legal, compliance, internal audit, and business resilience to help ensure cybersecurity risks are identified, assessed, and managed across the enterprise. Management also provides relevant cybersecurity updates to the Audit Committee.

AEP has not identified any cybersecurity incidents that have materially affected or are reasonably likely to materially affect its business strategy, results of operations, or financial condition.

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ITEM 2.   PROPERTIES

GENERATION FACILITIES

The tables below summarize the net maximum capacity of AEP's owned generation plants as of December 31, 2025. AEP subsidiaries serve customer electricity needs from these facilities and from purchased power in the PJM and SPP markets based on demand and other economic conditions. AEP's regulated subsidiaries have approved recovery mechanisms in retail jurisdictions that recover the cost of prudently incurred fuel, purchased power and other expenses.

Vertically Integrated Utilities Segment

AEGCo
Plant Name	Units	State	Fuel Type	Net Maximum  Capacity (MWs)	Year Plant  or First Unit Commissioned
Rockport (a)	2	IN	Steam - Coal	1,310	1984

(a)AEGCo owns a 50% interest in the Rockport Plant units. I&M owns the remaining 50%. Figures presented reflect only the portion owned by AEGCo.

APCo
Plant Name	Units	State	Fuel Type	Net Maximum  Capacity (MWs)	Year Plant  or First Unit Commissioned
Ceredo	6	WV	Natural Gas	516	2001
Dresden	3	OH	Natural Gas	665	2012
Smith Mountain	5	VA	Pumped Storage	585	1965
Amos	3	WV	Steam - Coal	2,950	1971
Mountaineer	1	WV	Steam - Coal	1,320	1980
Clinch River	2	VA	Steam - Natural Gas	465	1958
Hydro (Various Plants)	Various	VA	Hydro	158	1906-1964
Hydro (Various Plants)	Various	WV	Hydro	53	1935-1938
Amherst	NA	VA	Solar	5	2023
Top Hat	NA	IL	Wind	204	2025
Total MWs				6,921

NA    Not applicable.

I&M
Plant Name	Units	State	Fuel Type	Net Maximum Capacity (MWs)	Year Plant  or First Unit Commissioned
Rockport (a)	2	IN	Steam - Coal	1,310	1984
Cook	2	MI	Steam - Nuclear	2,296	1975
Hydro (Various Plants)	Various	IN	Hydro	7	1904-1913
Hydro (Various Plants)	Various	MI	Hydro	13	1908-1923
Solar (Various Plants)	NA	IN	Solar	31	2016-2021
Solar (Various Plants)	NA	MI	Solar	5	2016
Total MWs				3,662

(a)I&M owns a 50% interest in the Rockport Plant units. AEGCo owns the remaining 50%. Figures presented reflect only the portion owned by I&M.

NA    Not applicable.

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KPCo
Plant Name	Units	State	Fuel Type	Net Maximum Capacity (MWs)	Year Plant  or First Unit Commissioned
Mitchell (a)	2	WV	Steam - Coal	780	1971
Big Sandy	1	KY	Steam - Natural Gas	295	1963
Total MWs				1,075

(a)KPCo owns a 50% interest in the Mitchell Plant units.  WPCo owns the remaining 50%. Figures presented reflect only the portion owned by KPCo.

PSO
Plant Name	Units	State	Fuel Type	Net Maximum Capacity (MWs)	Year Plant  or First Unit Commissioned
Comanche	3	OK	Natural Gas	228	1973
Green Country	3	OK	Natural Gas	904	2002
Northeastern, Unit 1	3	OK	Natural Gas	470	1961
Riverside, Units 3 and 4	2	OK	Natural Gas	160	2008
Southwestern, Units 4 and 5	2	OK	Natural Gas	166	2008
Weleetka	2	OK	Natural Gas	90	1975
Northeastern, Unit 3 (a)	1	OK	Steam - Coal	472	1979
Northeastern, Unit 2	1	OK	Steam - Natural Gas	435	1961
Riverside, Units 1 and 2	2	OK	Steam - Natural Gas	879	1974
Southwestern, Units 1, 2 and 3	3	OK	Steam - Natural Gas	446	1952
Tulsa	2	OK	Steam - Natural Gas	319	1956
North Central Wind Energy Facilities (b)	NA	OK	Wind	675	2021-2022
Rock Falls	NA	OK	Wind	155	2017
Flat Ridge IV	NA	KS	Wind	135	2025
Flat Ridge V	NA	KS	Wind	153	2025
Pixley	NA	KS	Solar	189	2025
Total MWs				5,876

(a)Northeastern, Unit 3 operated on coal up through December 2025 and began to operate on natural gas beginning in January 2026.

(b)PSO owns a 45.5% interest and SWEPCo owns the remaining 54.5% interest in Sundance, Maverick and Traverse.  Figures presented reflect only the portion owned by PSO.

NA    Not applicable.

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SWEPCo
Plant Name	Units	State	Fuel Type	Net Maximum Capacity (MWs)	Year Plant  or First Unit Commissioned
Mattison	4	AR	Natural Gas	314	2007
Stall	3	LA	Natural Gas	535	2010
Flint Creek (a)	1	AR	Steam - Coal	259	1978
Turk (a)	1	AR	Steam - Coal	477	2012
Welsh (b)	2	TX	Steam - Coal	1,056	1977
Arsenal Hill	1	LA	Steam - Natural Gas	111	1960
Knox Lee	1	TX	Steam - Natural Gas	344	1950
Lieberman	2	LA	Steam - Natural Gas	219	1947
Wilkes	3	TX	Steam - Natural Gas	889	1964
Diversion Wind Farm	NA	TX	Wind	201	2024
North Central Wind Energy Facilities (c)	NA	OK	Wind	809	2021-2022
Wagon Wheel	NA	OK	Wind	598	2025
Total MWs				5,812

(a)Jointly-owned with nonaffiliated entities.  Figures presented reflect only the portion owned by SWEPCo. The Arkansas jurisdictional portion of SWEPCo’s interest in Turk Plant is not in rate base.

(b)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028. In December 2024, SWEPCo filed an application for a CCN with the APSC, LPSC and PUCT to convert Welsh Plant, Units 1 and 3 to natural gas in 2028 and 2027, respectively.

(c)SWEPCo owns a 54.5% interest and PSO owns the remaining 45.5% interest in Sundance, Maverick and Traverse. Figures presented reflect only the portion owned by SWEPCo.

NA    Not applicable.

WPCo
Plant Name	Units	State	Fuel Type	Net Maximum Capacity (MWs)	Year Plant  or First Unit Commissioned
Mitchell (a)	2	WV	Steam - Coal	780	1971

(a)WPCo owns a 50% in the Mitchell Plant units. KPCo owns the remaining 50%. Figures presented reflect only the portion owned by WPCo.

TRANSMISSION AND DISTRIBUTION FACILITIES

The AEP System has significant investments in transmission and distribution lines across its Vertically Integrated Utilities, Transmission and Distribution Utilities and AEP Transmission Holdco Segments.

TITLE TO PROPERTY

The AEP System’s generating facilities are generally located on AEP owned property.  The greater portion of the transmission and distribution lines of the AEP System has been constructed over property owned by third parties pursuant to easements or along public highways and streets pursuant to appropriate statutory authority.  The rights of AEP’s public utility subsidiaries in the realty on which their facilities are located are considered adequate for use in the conduct of their business.  Minor defects and irregularities customarily found in title to properties of like size and character may exist, but such defects and irregularities do not materially impair the use of the properties.  AEP’s public utility subsidiaries generally have the right of eminent domain which permits them, if necessary, to acquire, perfect or secure titles to or easements on privately held lands used or to be used in their utility operations.  

SYSTEM TRANSMISSION LINES AND FACILITY SITING

Laws in the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Tennessee, Texas, Virginia and West Virginia require prior approval of sites of generating facilities and/or routes of high-voltage transmission lines.  AEP has experienced delays and additional costs in constructing facilities as a result of proceedings conducted pursuant to such statutes and in proceedings in which AEP’s operating companies have sought to acquire rights-of-way through condemnation.  These proceedings may result in additional delays and costs in future years.

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CONSTRUCTION PROGRAM

With input from its state utility commissions, AEP subsidiaries regularly assess the adequacy of their transmission, distribution, generation and other facilities to plan and provide for the reliable supply of electric power and energy to its customers.  In this assessment process, assumptions are being reviewed as new information becomes available and assessments and plans are modified, as appropriate.  AEP forecasts approximately $12.2 billion of construction expenditures for 2026. Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, supply chain issues, weather, legal reviews, technology advancements, inflation and the ability to access capital.  See the “Budgeted Capital Expenditures” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

POTENTIAL UNINSURED LOSSES

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to AEP’s generation plants and costs of replacement power.  Unless allowed to be recovered through rates, future losses or liabilities which are not completely insured could reduce net income and impact the financial conditions of AEP and subsidiaries.  For risks related to owning a nuclear generating unit, see the “Nuclear Contingencies” section of Note 6 - Commitments, Guarantees and Contingencies for additional information.

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ITEM 3.   LEGAL PROCEEDINGS

For a discussion of material legal proceedings, see Note 6 - Commitments, Guarantees and Contingencies for additional information.

ITEM 4.   MINE SAFETY DISCLOSURE

Not applicable.

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PART II

ITEM 5.   MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

AEP

In addition to the AEP Common Stock Information section below, the remaining information required by this item is incorporated herein by reference to (a) the material under the “Dividend Policy and Restrictions” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations and (b) Note 16 - Stock-Based Compensation.

During the quarter ended December 31, 2025, neither AEP nor its publicly-traded subsidiaries purchased equity securities that are registered by AEP or its publicly-traded subsidiaries pursuant to Section 12 of the Exchange Act other than in amounts that were not material as described in Note 16 referenced above.

AEP Texas, APCo, I&M, OPCo, PSO and SWEPCo

The common stock of these companies is held solely by AEP.  For more information see the “Dividend Restrictions” section of Note 15 - Financing Activities.

AEPTCo

AEP owns the entire interest in AEPTCo through its wholly-owned subsidiary AEP Transmission Holdco.

AEP COMMON STOCK INFORMATION

AEP common stock is principally traded using the trading symbol “AEP” on the NASDAQ Stock Market.  As of December 31, 2025, AEP had 42,604 registered shareholders. The performance graph below compares the cumulative total return among AEP, the S&P 500 Index and the S&P 500 Utilities (Sector) Index over a five year period. The performance graph assumes an initial investment of $100 on December 31, 2020 and that all dividends were reinvested.

Past performance is no guarantee of future results. Chart provided for illustrative purposes.

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ITEM 6.   RESERVED

ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

AEP

The information required by this item is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations. Year-to-year comparisons between 2024 and 2023 have been omitted from this Form 10-K but may be found in "Management's Discussion and Analysis of Financial Condition" in Part II, Item 7 of AEP’s Form 10-K for the fiscal year ended December 31, 2024.

AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(a).  Management’s narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations.

ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

The information required by this item is incorporated herein by reference to the material under the “Quantitative and Qualitative Disclosures About Market Risk” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations.

ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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2025 Annual Reports

American Electric Power Company, Inc. and Subsidiary Companies

AEP Texas Inc. and Subsidiaries

AEP Transmission Company, LLC and Subsidiaries

Appalachian Power Company and Subsidiaries

Indiana Michigan Power Company and Subsidiaries

Ohio Power Company and Subsidiaries

Public Service Company of Oklahoma

Southwestern Electric Power Company Consolidated

Audited Financial Statements and

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

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX OF ANNUAL REPORTS

		Page Number
American Electric Power Company, Inc. and Subsidiary Companies:
	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
	Report of Independent Registered Public Accounting Firm (PCAOB ID 238)	92
	Management’s Report on Internal Control Over Financial Reporting	95
	Consolidated Financial Statements	96
AEP Texas Inc. and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	102
	Report of Independent Registered Public Accounting Firm (PCAOB ID 238)	104
	Management’s Report on Internal Control Over Financial Reporting	106
	Consolidated Financial Statements	107
AEP Transmission Company, LLC and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	113
	Report of Independent Registered Public Accounting Firm (PCAOB ID 238)	115
	Management’s Report on Internal Control Over Financial Reporting	117
	Consolidated Financial Statements	118
Appalachian Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	123
	Report of Independent Registered Public Accounting Firm (PCAOB ID 238)	126
	Management’s Report on Internal Control Over Financial Reporting	128
	Consolidated Financial Statements	129
Indiana Michigan Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	135
	Report of Independent Registered Public Accounting Firm (PCAOB ID 238)	138
	Management’s Report on Internal Control Over Financial Reporting	140
	Consolidated Financial Statements	141
Ohio Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	147
	Report of Independent Registered Public Accounting Firm (PCAOB ID 238)	150
	Management’s Report on Internal Control Over Financial Reporting	152
	Consolidated Financial Statements	153
Public Service Company of Oklahoma:
	Management’s Narrative Discussion and Analysis of Results of Operations	158
	Report of Independent Registered Public Accounting Firm (PCAOB ID 238)	161
	Management’s Report on Internal Control Over Financial Reporting	163
	Financial Statements	164
Southwestern Electric Power Company Consolidated:
	Management’s Narrative Discussion and Analysis of Results of Operations	170
	Report of Independent Registered Public Accounting Firm (PCAOB ID 238)	173
	Management’s Report on Internal Control Over Financial Reporting	175
	Consolidated Financial Statements	176
Index of Notes to Financial Statements of Registrants		182

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Company Overview

AEP is one of the largest investor-owned electric public utility holding companies in the United States.  AEP’s electric utility operating companies provide generation, transmission and distribution services to more than five million retail customers in Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia.

AEP’s subsidiaries operate an extensive portfolio of assets including:

•Approximately 252,000 circuit miles of distribution lines.

•Approximately 38,000 circuit miles of transmission lines, including approximately 2,000 circuit miles of 765 kV lines.

•Approximately 25,000 MWs of regulated owned generating capacity as of December 31, 2025.

AEP is committed to executing its strategy to improve customers’ lives with reliable, affordable power. AEP’s mission is to put the customer first and is focused on six core principles:

•Customer Service - Industry-best customer experience.

•Employee Commitment - Safe and secure workplace; engaged, trained and developed employees.

•Environmental Respect - Creative sustainable energy solutions.

•Regulatory & Legislative Integrity - Balanced regulatory outcomes; Trusted industry leadership.

•Operational Excellence - World-class asset performance.

•Financial Strength - Strong financial discipline.

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AEP CONSOLIDATED RESULTS OF OPERATIONS

2025 Compared to 2024

Earnings Attributable to AEP Common Shareholders increased from $3.0 billion in 2024 to $3.6 billion in 2025 primarily due to:

•Investment in transmission assets, which resulted in higher revenues and income.

•The favorable impact from the receipt of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A revenue refund provision recorded in 2024 associated with the Turk Plant and SWEPCo’s 2012 Texas Base Rate Case.

•A decrease in operating expense due to the Federal EPA’s revised CCR rule which resulted in higher operating expenses in 2024.

•A decrease in operating expenses due to the voluntary severance program that occurred in the second quarter of 2024.

•An increase in sales volumes driven by favorable weather.

•Favorable rate proceedings in AEP’s various jurisdictions.

These increases were partially offset by:

•The favorable impact from the receipt of PLRs in 2024 related to the treatment of NOLCs in retail ratemaking. See “NOLCs in Retail Jurisdictions - IRS PLRs” section below for additional information.

•An increase in operating expenses recorded in 2025 due to an impairment of in-process internal use software development costs.

See “Results of Operations” section for additional information by operating segment.

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Non-GAAP Financial Measures

AEP reports its financial results in accordance with GAAP by using earnings (loss) attributable to AEP common shareholders as stated above. AEP supplements the reporting of financial information determined in accordance with GAAP with certain non-GAAP financial measures including operating earnings. Operating earnings, which could differ from GAAP earnings, exclude certain gains and losses and other specified items, including mark-to-market adjustments from commodity hedging activities and other items as set forth in the reconciliation below. Management believes these items are not indicative of AEP's ongoing performance.

This information is intended to enhance an investor’s overall understanding of period over period financial results and provide an indication of AEP’s baseline operating performance by excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. These non-GAAP financial measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations.

Reconciliation of Reported GAAP Earnings to Operating Earnings

The following table presents a reconciliation of operating earnings to the most directly comparable GAAP measure.

	Year Ended December 31, 2025
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Reported GAAP Earnings	$	3,580	$	488	$	1,075	$	457	$	414	$	328	$	252	$	388
Adjustments to Reported GAAP Earnings (a):
Mark-to-Market Impact of Commodity Hedging Activities (b)	9		—		—		—		7		—		—		—
Sale of AEP OnSite Partners (c)	10		—		—		—		—		—		—		—
Impact of Ohio Legislation (d)	19		—		—		—		—		19		—		—
FERC NOLC Order (e)	(480)		—		(354)		(29)		(36)		—		(4)		(54)
Impairment of Software Development Costs (f)	52		11		—		9		7		14		5		4
Total Specified Items	(390)		11		(354)		(20)		(22)		33		1		(50)
Operating Earnings	$	3,190	$	499	$	721	$	437	$	392	$	361	$	253	$	338

(a)    Excluding tax related adjustments, all items presented in the table are tax adjusted at the statutory rate unless otherwise noted.

(b)    Represents the impact of mark-to-market economic hedging activities.

(c)    Represents an adjustment to the estimated loss on the sale of AEP OnSite Partners as a result of the contractual working capital true-up.

(d)    Represents the reduction in regulatory assets for OVEC-related purchased power costs as a result of approved legislation in Ohio in April 2025.

(e)    Represents the impact of the FERC NOLC Order for years 2021-2024.

(f) Represents an impairment of in-process internal use software development costs.

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	Year Ended December 31, 2024
	AEP		AEP Texas			AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Reported GAAP Earnings	$	2,967	$	420		$	688	$	422	$	391	$	306	$	249	$	321
Adjustments to Reported GAAP Earnings (a):
Mark-to-Market Impact of Commodity Hedging Activities (b)	(85)		—			—		—		19		—		—		—
Remeasurement of Excess ADIT Regulatory Liability (c)	(45)		—			—		—		(12)		—		—		(33)
Impact of NOLC on Retail Ratemaking (d)	(260)		—			—		—		(69)		—		(57)		(134)
Disallowance - Dolet Hills Power Station (e)	11		—			—		—		—		—		—		11
Provision for Refund - Turk Plant (f)	117		—			—		—		—		—		—		117
Sale of AEP OnSite Partners (g)	11		—		—	—		—		—		—		—		—
Severance and Pension Settlement Charges (h)	121		16			9		20		17		19		8		23
Federal EPA CCR Rule (i)	111		—			—		—		11		41		—		—
SEC Matter Loss Contingency (j)	19		—			—		—		—		—		—		—
State Tax Law Changes (k)	11		—			—		—		—		—		—		11
Total Specified Items	11		16			9		20		(34)		60		(49)		(5)
Operating Earnings	$	2,978	$	436		$	697	$	442	$	357	$	366	$	200	$	316

(a)Excluding tax related adjustments, all items presented in the table are tax adjusted at the statutory rate unless otherwise noted.

(b)Represents the impact of mark-to-market economic hedging activities.

(c)Represents the impact of the remeasurement of Excess ADIT in Arkansas and Michigan as a result of the denial of SWEPCo's request regarding the Turk Plant by the APSC and the approved treatment of stand-alone NOLCs by the MPSC.

(d)Represents the impact of receiving IRS PLRs related to NOLCs in retail ratemaking on I&M, PSO and SWEPCo. Amount includes a reduction in Excess ADIT and activity related to prior periods.

(e)Represents the impact of a disallowance recorded at SWEPCo on the remaining net book value of the Dolet Hills Power Station as a result of an LPSC approved settlement agreement in April 2024.

(f)Represents a provision for revenue refunds on certain capitalized costs associated with the Turk Plant.

(g)Represents the loss on the sale of AEP OnSite Partners.

(h)Represents employee severance charges and pension settlement expenses.

(i)Represents the impact of the Federal EPA Revised CCR Rule.

(j)Represents an estimated loss contingency related to a previously disclosed SEC investigation.

(k)Represents the impact of the remeasurement of ADIT as a result of enacted state tax legislation in Arkansas and Louisiana.

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	Year Ended December 31, 2023
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Reported GAAP Earnings	$	2,208	$	370	$	614	$	294	$	336	$	328	$	209	$	220
Adjustments to Reported GAAP Earnings (a):
Mark-to-Market Impact of Commodity Hedging Activities (b)	228		—		—		—		(20)		—		—		—
Remeasurement of Excess ADIT Regulatory Liability (c)	(46)		—		—		(46)		—		—		—		—
ENEC Fuel Disallowance (d)	181		—		—		101		—		—		—		—
Turk Impairment (e)	80		—		—		—		—		—		—		80
Sale of Unregulated Renewables (f)	73		—		—		—		—		—		—		—
Kentucky Operations (g)	(34)		—		—		—		—		—		—		—
Change in Texas Legislation (h)	(24)		(20)		—		—		—		—		—		(4)
FERC NOLC Disallowance (i)	24		—		36		(4)		(2)		(9)		(3)		1
Severance Charges (j)	19		3		1		4		3		5		1		2
Impairment of Investment in NMRD (k)	15		—		—		—		—		—		—		—
Total Specified Items	516		(17)		37		55		(19)		(4)		(2)		79
Operating Earnings	$	2,724	$	353	$	651	$	349	$	317	$	324	$	207	$	299

(a)Excluding tax related adjustments, all items presented in the table are tax adjusted at the statutory rate unless otherwise noted.

(b)Represents the impact of mark-to-market economic hedging activities.

(c)Represents the impact of the remeasurement of ADIT - NOLC in Virginia and West Virginia.

(d)Represents the impact of the disallowance of the recovery of certain deferred fuel costs in West Virginia.

(e)Represents the impact of the disallowance of certain capitalized costs associated with the Turk Plant.

(f)Represents the loss on the sale of the Competitive Contracted Renewable Portfolio and other related third-party transaction costs.

(g)Represents an adjustment to the loss on the expected sale of the Kentucky Operations which was terminated in April 2023 and other related third-party transaction costs.

(h)Represents the impact of recent legislation in Texas regarding recovery of certain employee incentives.

(i)Represents the impact of the FERC decision denying stand-alone treatment of NOLCs for transmission formula rates.

(j)Represents the impact of AEP's workforce reduction in 2023.

(k)Represents the impairment of AEP's investment in the NMRD joint venture.

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ELECTRIC INDUSTRY TRANSFORMATION

The electric utility industry is undergoing a historic transformation, fueled by rapid commercial customer class load growth, especially from data processing and other energy-intensive operations, as well as shifting regulator and customer expectations, evolving public policies, rising stakeholder demands, demographic changes, new competitive pressures, emerging technologies, necessary reliability investments and volatile commodity markets. AEP projects growth in the system peak demand by 2030 across its diversified service territory, with especially strong projected growth in Indiana, Ohio, Oklahoma and Texas. To meet this accelerating demand, AEP outlined a $72 billion, five year capital plan focused on strengthening transmission infrastructure, adding new generation resources to serve both existing customers and large forecasted load additions and continuing to enhance distribution system reliability. Throughout this investment cycle, AEP remains committed to focusing on customer affordability. AEP expects to utilize various levers to address affordability including incremental load growth, rate design, continued operation and maintenance expense efficiency and financing mechanisms such as securitizations.

AEP has advanced large-load tariff proposals and tariff modifications aimed at enabling the rapid interconnection of committed large load customers while protecting existing customers from increased costs. These proposals have been filed in eight of AEP’s jurisdictions, with four already approved by state commissions. AEP is actively engaging with regulators, policymakers, RTOs, customers and suppliers to advance system reliability, resiliency and affordability across its service territories during this period of rapid transformation.

Additionally, AEP continues to secure resources to support forecasted load requirements in its regulated jurisdictions including:

•The addition of 2.2 GWs of owned generating capacity in 2025.

•Securing additional turbines for gas-fired turbine capacity.

•RFPs seeking approximately 12,700 MWs of generating capacity.

•Capacity purchase agreements to satisfy capacity reserve margins to serve customers.

•Long-term transmission construction partnership with a major U.S.-based infrastructure services company.

Customer Demand

AEP uses sales volumes by customer class as a way to measure drivers of customer demand. In 2025, AEP experienced an increase in customer demand for power driven primarily by new data processing loads coming online in 2025 in the commercial customer class and favorable weather and marginal growth in the residential class. The table below shows the percentage change in sales volume by customer class.

(a)Percentage change for the year ended December 31, 2025 as compared to the year ended December 31, 2024. Load figures are billed retail sales excluding firm wholesale load.

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Large Load/Data Center Tariffs

Several AEP utility subsidiaries have made rate filings with state commissions to establish new tariffs for data centers and other large load customers. The new tariffs are designed to protect existing customers by strengthening and lengthening contract terms with large customers. These new protections include contract lengths of up to 20 years and take-or-pay contractual minimums which can require a customer to pay for as much as 90% of their contracted demand. In practice, these provisions reduce risks around the build out of large load infrastructure on existing customers, promoting stability and affordability. The table below provides a summary of the status of these new data center and large load tariffs.

Company	Jurisdiction	Large Load Tariff	Status (a)	Customer Eligibility
APCo	Virginia	Large Power Service	Pending	New load of 150 MWs or more/100 MWs for individual site
APCo	West Virginia	Large Capacity/Industrial Power	Approved	New load of 150 MWs or more/100 MWs for individual site
I&M	Indiana	Industrial Power	Approved	New load of 150 MWs or more/70 MWs for individual site
I&M	Michigan	Large Load	Pending	New load of 50 MWs or more
KPCo	Kentucky	Industrial General Service	Approved	New commercial or industrial load of 150 MWs or more
OPCo	Ohio	Data Center	Approved	New data center load of 25 MWs or more
PSO	Oklahoma	Large Power and Light	Pending	New load of 75 MWs or more
SWEPCo	Texas	Electric Service Large Load	Pending	New load of 75 MWs or more

(a)Both the pending and the approved tariffs include certain requirements for cash, or cash related instruments, as deposits.

In June 2025, Texas Senate Bill 6 (SB 6) became effective and was signed into law by the Governor of Texas. SB 6 establishes a standardized process for connecting large load customers within ERCOT in a way that supports business development in Texas while minimizing the potential for stranded infrastructure costs. The new legislation establishes criteria for new large load interconnections and directs the PUCT to ensure that these large load customers pay a reasonable share of allocated transmission costs.

The PUCT is currently drafting rules through multiple active dockets related to large load interconnection standards, net-metering arrangements for co-location, large load forecasting criteria, large load reliability/demand reduction and transmission cost allocation review to implement SB 6. The rulemaking projects are on various timelines, with final adoptions planned throughout 2026. AEP Texas has signed Letters of Agreement for an incremental 36 gigawatts of load by 2030. As the PUCT finalizes its SB 6 rulemaking efforts, AEP Texas expects improved clarity and certainty around the timing and the amount of additional load connection in ERCOT.

PJM Capacity Market Reform

The AEP East Companies are members of PJM. Utilities in PJM can meet their capacity obligations by either: (a) participating in capacity auctions administered by PJM, or (b) via the Fixed Resource Requirement alternative (FRR) in which load-serving entities self-supply their generation through owned or contracted resources. All AEP East Companies other than AEP Ohio utilize the FRR alternative.

In January 2026, the White House, all thirteen state governors from across the PJM footprint, and senior federal energy officials jointly released a Statement of Principles. This Statement of Principles is designed to increase capacity available in the PJM market for large load customers and to ensure the costs of those resources are paid for by the large load customers to protect existing customer affordability. The Statement of Principles directs PJM to hold a one-time Reliability Backstop Auction, accelerate capacity market reforms in response to unprecedented data center load growth, and align costs associated with new capacity coming into the market with the large load customers necessitating the resources. Subsequently, in a proceeding pending since 2025, the Board of Directors of PJM issued a decision letter initiating changes to PJM’s capacity market and interconnection processes.

As direct participants in the PJM capacity market, these reforms have the potential to materially impact AEP’s competitive retail operations and could materially alter OPCo’s cost allocations to retail customers.

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AEP will continue to engage constructively with governors, regulators, PJM, and state and federal policymakers to support reforms that strengthen grid reliability, enable economic growth, and provide transparent, durable investment signals for utilities and investors. Management will continue to monitor activity within PJM and cannot predict the ultimate impact of these early-stage capacity market reform efforts or whether the FRR alternative will be impacted. If changes to PJM auction rules affect AEP’s existing or prospective customer contracts or generation development strategy, it could affect future results of operations.

New Generation Resources

The growth of AEP’s regulated generation portfolio reflects the company’s focus on meeting increasing customer demand for power while balancing cost and reliability.

Acquired Generation Facilities

During 2025, PSO acquired four power generation facilities to strengthen its portfolio and enhance reliability. Additionally, in the fourth quarter of 2025, APCo acquired the Top Hat Wind Facility and SWEPCo acquired the Wagon Wheel Wind Facility. These transactions reflect the company’s focus on securing necessary generation to meet future customer demand. See “Acquisitions” section of Note 7 for additional information. The table below summarizes these acquisitions:

Company	Plant Name	Fuel Type	Location	Acquisition Date	Net Maximum Capacity
					(in MWs)
PSO	Pixley	Solar	Barber County, KS	May 2025	189
PSO	Green Country	Natural Gas	Jenks, OK	June 2025	904
PSO	Flat Ridge IV	Wind	Kingman and Harper Counties, KS	June 2025	135
PSO	Flat Ridge V	Wind	Kingman and Harper Counties, KS	August 2025	153
APCo	Top Hat	Wind	Logan County, Illinois	November 2025	204
SWEPCo	Wagon Wheel	Wind	Multiple Counties, Oklahoma	December 2025	598
Total					2,183

Pending Natural Gas Generation

In December 2024, SWEPCo filed an application for a CCN with the APSC, LPSC and PUCT for construction of the Hallsville Natural Gas Plant (450 MWs) and the fuel conversion of Welsh Plant, Units 1 and 3 to natural gas. In the application for the CCN, SWEPCo seeks to site the Hallsville Natural Gas Plant at the location of the now-retired Pirkey Plant. Regulatory proceedings in all three jurisdictions are underway. If approved, the projects will help SWEPCo address increasing SPP capacity requirements. SWEPCo estimates the combined capital cost of these projects is approximately $723 million and the projects would be placed in service between December 2027 and May 2028.

In February 2025, I&M filed an application with the IURC to acquire the Oregon Generation Plant (Oregon), an 870 MW combined-cycle power generation facility located near Toledo, Ohio. In April 2025, I&M submitted a FERC 203 application for the acquisition and received approval in October 2025. In August 2025, I&M reached a unanimous settlement in the filing submitted to the IURC with intervening parties approving the acquisition of the Oregon facility and cost recovery. In November 2025, the IURC issued an order granting a CPCN to I&M for its acquisition of the Oregon facility. I&M expects to close on the transaction in the first quarter of 2026.

In January 2026, the IURC issued a separate order approving the settlement agreement in I&M’s Indiana Expedited Generation Resource (EGR) Plan filing. This order approving the settlement agreement allows I&M to seek expedited IURC approval of future proposed PPAs, capacity purchase agreements (CPAs) and owned generation resources to serve I&M’s increasing

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customer load and to implement deferral accounting for the generation resources that are approved by the IURC through the EGR Plan process.

In September 2025, PSO filed an application with the OCC seeking regulatory approval of a new 450 MW combustion turbine configuration at its existing Northeastern facility in Oklahoma as part of a project portfolio. If approved, the combustion turbines would be projected to be online by the end of 2028.

Significant Approved Renewable Generation Filings

AEP received regulatory approvals from various state regulatory commissions to acquire approximately 1,285 MWs of owned renewable generation facilities, totaling approximately $3.6 billion. The Financial Condition section below includes the estimated cost of these facilities in the Budgeted Capital Expenditures. In addition, AEP received regulatory approvals for 1,067 MWs of renewable PPAs. The recently enacted OBBBA legislation is not expected to affect the eligibility of these generation facilities for federal tax incentives. The following table summarizes regulatory approvals received for active renewable projects that are not yet in service as of December 31, 2025:

Company	Generation Type	Expected Commercial Operation	Owned/PPA	Generating Capacity
				(in MWs)
APCo	Solar	2026-2027	PPA	113
APCo (a)	Wind	2026-2029	Owned	401
I&M	Solar	2026-2027	PPA	280
I&M	Wind	2026-2030	PPA	674
I&M	Solar	2028	Owned	469
PSO (b)	Wind	2026	Owned	265
PSO (b)	Solar	2027	Owned	150
Total Approved Renewable Projects				2,352

(a)APCo has one wind project under construction.

(b)PSO has one wind project and one solar project under construction.

Significant Generation Requests for Proposal (RFP)

The table below includes active RFPs issued for both owned and purchased power generation. Projects selected will be subject to regulatory approval.

Company	Issuance Date	Resource Type	Projected In-Service Dates	Generating Capacity
				(in MWs)
PSO (a)	November 2023	All-source	2027/2028	1,500
PSO	January 2026	All-source	2029	4,000
I&M (b)	September 2024	Wind, solar, dispatchable resources, BESS and emerging technology resources	2029	4,000
SWEPCo (c)	January 2024	Wind, solar, BESS and natural gas resources	2027/2028	2,100
APCo	May 2025	Owned wind, solar, co-located or stand-alone BESS	2029	800
APCo	May 2025	Purchased power from wind, solar, hydro or geothermal	2029	300
Total Significant RFPs				12,700

(a)RFP was negotiated and filed for regulatory approval in September 2025.

(b)Five wind resources selected totaling 574 MWs from the 2024 RFP have already been submitted and approved by the IURC. I&M expects to file applications with the IURC for regulatory approval of additional resources from the 2024 RFP in 2026.

(c)Two self-build natural gas resources totaling 1,503 MWs were selected and filed for regulatory approval in December 2024.

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Capacity Purchase Agreements

In addition to the generation projects discussed above, AEP enters into Capacity Purchase Agreements (CPA) to satisfy operating companies’ capacity reserve margins to serve customers. The following table includes CPA amounts under contract as of December 31, 2025, by year, for the five-year period 2026-2030:

	I&M			PSO		SWEPCo
		Natural Gas	Wind	Natural Gas	Wind	Natural Gas	Wind
Delivery Start Year	(in MWs)
2026		614	73	460	86	150	75
2027		769	—	410	86	300	100
2028		995	—	410	—	450	—
2029		995	—	410	—	450	—
2030		995	—	410	—	150	—

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RECENT REGULATORY DEVELOPMENTS AND OTHER TRANSACTIONS

Regulatory Matters - Utility Rates and Rate Proceedings

The Registrants are involved in rate cases and other proceedings with their regulatory commissions in order to establish fair and appropriate electric service rates to recover their costs and earn a fair return on their investments.  Depending on the outcomes, these rate cases and proceedings can have a material impact on results of operations, cash flows and possibly financial condition. AEP is currently involved in the following key proceedings.

The following tables show the Registrants’ completed and pending base rate case proceedings in 2025. See Note 4 - Rate Matters for additional information.

Completed Base Rate Case Proceedings

		Annual
		Base Revenue		Approved	New Rates
Company	Jurisdiction	Increase		ROE	Effective
		(in millions)
APCo/WPCo	West Virginia	$	76	9.25%	August 2025	(a)
SWEPCo	Arkansas	85		9.65%	February 2026

(a)The WVPSC approved recovery of the base rate increase through current ENEC rates. The WVPSC issued an interim order approving securitization of APCo and WPCo under-recovery balances, with activity subsequent to 2024 subject to a final prudence review prior to securitization. See the “2024 West Virginia Base Rate Case” and “2025 West Virginia Securitization Filing” sections of Note 4 for additional information.

Pending Base Rate Case Proceedings

			Annual
		Filing	Base Revenue		Requested
Company	Jurisdiction	Date	Increase Request		ROE
			(in millions)
OPCo	Ohio	May 2025	$	97	10.9%
KPCo	Kentucky	August 2025	96		10.0%
SWEPCo	Texas	October 2025	95		10.75%
PSO	Oklahoma	January 2026	299		10.5%

Other Significant Regulatory Matters

2025 West Virginia Securitization Filing

In March 2025, APCo and WPCo (the Companies) requested to finance, through the issuance of securitization bonds, approximately $2.4 billion of West Virginia jurisdictional undepreciated property balances and regulatory assets. In the third quarter of 2025, the Companies submitted post-hearing exhibits with a revised securitization request of approximately $2.5 billion, including: (a) $413 million of the Companies’ combined unrecovered ENEC balances, (b) $1.7 billion of undepreciated West Virginia jurisdictional plant balances as of December 31, 2022 for the Amos, Mitchell and Mountaineer Plants, (c) $237 million of environmental costs previously approved for recovery through a separate West Virginia surcharge and (d) $158 million of West Virginia jurisdictional deferred major storm operation and maintenance costs. See “2025 West Virginia Securitization Filing” section of Note 4 for additional information.

In August 2025, the WVPSC issued an interim order stating that it will approve the Companies’ future securitization of the generation plant assets, ENEC under-recovery balances, environmental costs and deferred storm operation and maintenance costs. All amounts above are subject to further review in a future final securitization financing order that the Companies expect will be issued by the WVPSC in 2026. Upon receipt of the final financing order, the Companies expect to proceed with the securitization bonds issuance process and to complete the securitization in the first half of 2026, subject to market conditions.

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2025 Virginia Securitization Legislation and Securitization Filing

In March 2025, the Governor of Virginia signed into law amendments to the Virginia utility retail base rate and rider rate case processes applicable to APCo as well as definitions of assets that APCo may request for securitization in future filings, effective July 1, 2025. This legislation will move future APCo Virginia biennial base rate filing due dates from March 31st to May 31st, with a final Virginia SCC order to be issued on these future filings no later than January 15th of the subsequent year and resulting updated base rates implemented no earlier than March 1st. This legislation prohibits APCo from increasing Virginia retail rates during the winter heating months of November through February. Finally, this legislation also allows APCo to file with the Virginia SCC, no earlier than July 1, 2025, a request seeking permission to securitize major storm costs incurred starting January 1, 2024 as well as the remaining December 31, 2023 Virginia retail net book values of APCo’s Amos and Mountaineer Plants.

In July 2025, APCo filed a request with the Virginia SCC to finance, through the issuance of proposed 20-year securitization bonds, approximately $1.4 billion of Virginia jurisdictional undepreciated property balances and a major storm operation and maintenance regulatory asset deferral balance. This proposed securitization included: (a) $1.2 billion of undepreciated Virginia jurisdictional plant balances as of December 31, 2023 for the Amos and Mountaineer Plants and (b) $141 million of Virginia jurisdictional major storm other operation and maintenance expenses deferred during the 2024-2025 biennial period. In September 2025, Virginia SCC staff submitted testimony concluding that all costs proposed by APCo for securitization are eligible for securitization in accordance with Virginia law. While also concluding that APCo’s proposed securitization of the Amos and Mountaineer Plants over 20 years offers benefits to customers through rate relief, Virginia SCC staff took no position on APCo’s proposed securitization of major storm other operation and maintenance expenses due to the apparent lack of significant benefit or cost savings for customers. In October 2025, the Hearing Examiner recommended the Virginia SCC approve the requested $1.4 billion for securitization. In November 2025, the Virginia SCC issued a financing order approving securitization of the requested $1.4 billion of Virginia jurisdictional costs. In accordance with Virginia statutory requirements and the financing order, the issuance of the securitization bonds is subject to final review by the Virginia SCC after bond pricing. APCo expects to proceed with the securitization bond issuance process and to complete the securitization process in the first half of 2026, subject to market conditions. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

NOLCs in Transmission Formula Rates - June 2025 FERC Order

In June 2025, the FERC issued two orders, partially reversing its January 2024 decisions on the basis of IRS PLRs accepted into the record, and concluding that the accelerated depreciation-related NOLC adjustments should be included in rate base and should also be included in the computation of Excess ADIT regulatory liabilities to be refunded to customers. As a result of the June 2025 FERC orders, the Registrants recognized revenues, with interest, attributable to accelerated depreciation-related NOLCs included in transmission formula rates for years 2021 through 2025 and reduced Excess ADIT regulatory liabilities. The impact of the orders resulted in a $499 million increase in Earnings Attributable to AEP Common Shareholders in the second quarter of 2025. See the table below and the “FERC 2021 PJM and SPP Transmission Formula Rate Challenge” section of Note 4 for additional information.

Company	Increase (Decrease) in Pretax Income (a)		Decrease in Income Tax Expense (b)		Increase in Noncontrolling Interest (c)		Increase in Net Income
	(in millions)
APCo	$	8	$	21	$	—	$	29
I&M	17		28		—		45
PSO	(13)		16		—		3
SWEPCo	17		39		—		56
AEPTCo	214		203		(55)		362
Other (d)	(2)		6		—		4
AEP Total	$	241	$	313	$	(55)	$	499

(a)Primarily represents the reversal of revenue refund provisions for years 2021-2025, partially offset by an increase in affiliated transmission expenses.

(b)Primarily relates to a $384 million remeasurement of Excess ADIT regulatory liabilities, partially offset by $71 million of tax expense on favorable pretax income.

(c)The noncontrolling interest relates to IMTCo and OHTCo. See “Noncontrolling Interest in Midwest Transmission Holdings” section of Note 7 for additional information.

(d)Includes KGPCo, KPCo, OPCo and WPCo.

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NOLCs in Retail Jurisdictions - IRS PLRs

AEP’s utility subsidiaries have made rate filings with state commissions to transition to stand-alone treatment of NOLCs in retail ratemaking. In April 2024, supportive PLRs for certain retail jurisdictions were received from the IRS, effective March 2024. The PLRs concluded NOLCs on a stand-alone ratemaking basis should be included in rate base and in the computation of Excess ADIT regulatory liabilities to be refunded to customers. Based on this conclusion, I&M, PSO and SWEPCo recognized regulatory assets related to revenue requirement amounts to be collected from customers, reduced Excess ADIT regulatory liabilities and recorded favorable impacts to net income in the first quarter of 2024 as shown in the table below:

Company	Increase in Pretax Income from the Recognition of Regulatory Assets		Reduction in Income Tax Expense (a)		Increase in Net Income
	(in millions)
I&M	$	20	$	50	$	70
PSO	12		45		57
SWEPCo	35		101		136
AEP Total	$	67	$	196	$	263

(a)Primarily relates to a $224 million remeasurement of Excess ADIT regulatory liabilities, partially offset by $29 million of tax expense on favorable pretax income from the recognition of regulatory assets.

The table below provides a summary of the status of the transition to stand-alone treatment of NOLCs in retail ratemaking for each AEP utility subsidiary.

Company (a)	Jurisdiction		Status
APCo	Virginia		Approved
APCo/WPCo	West Virginia	(b)	Pending
I&M	Indiana		Approved
I&M	Michigan		Approved
KGPCo	Tennessee		Approved
KPCo	Kentucky	(b)	Pending
PSO	Oklahoma	(b)	Approved, subject to refund
SWEPCo	Arkansas	(b)	Pending
SWEPCo	Louisiana	(b)	Pending
SWEPCo	Texas		Approved, subject to refund

(a)AEP Texas and OPCo do not have NOLCs on a stand-alone basis.

(b)Pending receipt of jurisdiction specific IRS PLR.

Beginning in the second quarter of 2024 and continuing until the NOLC revenue requirement is in rates, AEP is recognizing additional regulatory assets related to revenue requirement amounts to be collected from customers. As of December 31, 2025, AEP has NOLC regulatory assets of $108 million on its balance sheet.

Noncontrolling Interest in Midwest Transmission Holdings (Applies to AEP and AEPTCo)

In June 2025, a nonaffiliated entity acquired a 19.9% noncontrolling interest in Midwest Transmission Holdings, a subsidiary of AEPTCo Parent that owns all of the issued and outstanding stock of OHTCo and IMTCo. AEP received cash proceeds of approximately $2.78 billion, net of transaction costs, which were used to help finance AEP’s capital plan. See “Noncontrolling Interest in Midwest Transmission Holdings” section of Note 7 for additional information.

Kentucky Securitization Case

In June 2025, KPCo issued $478 million of securitization bonds to recover $500 million of regulatory assets, including $311 million of plant retirement costs, $79 million of deferred storm costs related to 2020, 2021, 2022 and 2023 major storms, $56 million of under-recovered purchased power rider costs, $51 million of deferred purchased power expenses and $3 million of issuance-related expenses, including KPSC advisor expenses. The net bond proceeds of $478 million also included $6 million for non-utility issuance costs and a $29 million offset for net present value of return on accumulated deferred income taxes related to KPCo’s securitized plant retirement costs as ordered by the KPSC.

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New Legislation

Ohio Legislation

Ohio House Bill 15 (HB 15) was approved by the Ohio legislature in April 2025 and signed into law by the Governor of Ohio in May 2025. HB 15 became effective beginning August 14, 2025 and (a) alters rate-setting mechanisms by replacing ESPs with triennial base rate cases based on a three-year forecasted test period, effective with the end of OPCo’s previously approved ESP which ends in May 2028, (b) eliminates OPCo’s ability to recover from, or refund to, customers the difference between purchased power expenses from OVEC and the market revenues OPCo receives from that purchased power as of the effective date of the law and (c) repeals the statute that permits electric distribution utilities, including OPCo, to execute contracts to provide customer-sited renewable generation service such as fuel cell technology or other renewable resources prospectively.

In 2025, as a result of this legislation, OPCo recorded a $24 million reduction to its OVEC-related purchased power regulatory asset for deferred net costs that are no longer probable of future recovery. Management is unable to predict the future impact to net income, cash flows and financial condition arising from the future changes in OPCo’s rate setting mechanisms and the elimination of OPCo’s ability to recover from, or refund to, customers the difference between purchased power expenses from OVEC and the market revenues OPCo receives from that purchased power. See “OVEC” section of Note 18 for additional information.

Texas Legislation

On June 20, 2025, Texas House Bill 5247 (HB 5247) was signed into law by the Governor of Texas and became effective. The bill establishes a UTM for qualifying electric utilities to file annual interim rate adjustments for cost recovery of certain transmission and distribution capital expenditures. On June 27, 2025, AEP Texas filed with the PUCT notice of qualification and election to follow the new methodology as permitted by HB 5247. Qualifying electric utilities under HB 5247 consist of utilities that: (a) operate solely in ERCOT, (b) have been identified by the PUCT as having responsibility for constructing transmission infrastructure as part of ERCOT’s Permian Basin Reliability Plan and (c) make annual capital expenditures in transmission and distribution that exceed 300% of annual depreciation. Based on those requirements, AEP Texas is a qualifying electric utility and SWEPCo is not a qualifying electric utility.

The UTM permits a qualifying electric utility to defer all or a portion of costs associated with its eligible transmission and distribution capital investments, including depreciation expense and carrying costs, as a regulatory asset. The tracking mechanism is available through 2035 and is an alternative to the existing capital tracking mechanisms in Texas. As a result of the new legislation, AEP Texas deferred approximately $56 million of eligible costs through December 2025 as a regulatory asset.

2025 UTM Filing

In October 2025, AEP Texas submitted its first filing with the PUCT seeking recovery of eligible costs through the UTM established by HB 5247. This filing combined three recovery mechanisms (Interim Transmission Cost of Service and Distribution Cost Recovery Factor capital trackers and the Transmission Cost Recovery Factor) into a single filing. The capital tracker incremental revenue requirement, inclusive of the items outlined in the January 2026 brief, sought in this filing is $100 million, including a request to recover, over a 12-month period, $38 million of eligible costs related to UTM deferrals and $2 million of eligible costs related to the System Resiliency Plan deferrals, both inclusive of equity carrying charges through the July 2025 test year period end. In November 2025, an intervenor proposed a $31 million reduction to the UTM deferral balance. The filing is currently undergoing a paper hearing and in January 2026 the parties filed briefs reiterating their position. A resolution is expected in the first half of 2026. Investments included in the UTM and the existing capital tracker filings remain subject to prudency review in the utility’s next base rate review before the PUCT. If any of these deferred costs are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

Oklahoma Legislation

Effective August 28, 2025, in accordance with Oklahoma Senate Bill 998 (SB 998), a public utility may defer up to 90% of all depreciation expense and return associated with qualifying electric plant to a regulatory asset, provided the utility has notified the OCC of its election to do so. SB 998 excludes deferral of costs related to transmission plant and new electric generating units. Deferred costs will be recovered through base rates over a 20-year period and earn a return until recovered. SB 998 also allows for expedited recovery of new gas plant investments. Through December 31, 2025, PSO deferred $9 million of qualifying costs to a regulatory asset to be recovered through future base rates.

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Federal Tax Legislation

On July 4, 2025, President Trump signed H.R. 1 into law, commonly known as the One Big Beautiful Bill Act (OBBBA). This budget reconciliation legislation modifies and accelerates the phase out of technology neutral PTCs and ITCs available for wind and solar projects, adds new restrictions to guard against certain foreign ownership or influence with respect to otherwise credit-eligible projects and makes 100% bonus depreciation permanent for certain non-regulated entities. With the exception of bonus depreciation, this legislation is prospective and has no material impact on the current period financial statements.

On August 15, 2025, the Department of Treasury and the IRS issued new and revised wind and solar tax credit guidance, Notice 2025-42, which modified the definition of “begin construction” for tax purposes by eliminating the previously available 5% cost safe harbor standard for projects that begin construction after September 1, 2025. This guidance is not expected to have a material impact on the Registrants.

On September 30, 2025, the Department of Treasury and the IRS issued interim guidance regarding the application of CAMT, Notice 2025-49. This guidance is not expected to have a material impact on the Registrants.

Additional significant guidance from the Department of Treasury and the IRS is expected on the tax provisions in recently enacted legislation. AEP will continue to monitor any issued guidance and evaluate the impact on AEP’s future net income, cash flows and financial condition.

Midcontinent Grid Solutions Investment (Applies to AEP and Transource Energy)

In 2025, Transource Energy and an affiliate of Berkshire Hathaway Energy formed Midcontinent Grid Solutions, LLC to participate in MISO’s 2024 Regional Transmission Expansion Plan competitive process. In January 2026, MISO selected the upgrades proposed by Midcontinent Grid Solutions to address forecasted reliability and load growth requirements. The projects awarded by MISO are estimated to cost approximately $1.2 billion and Transource Energy’s share of this investment is estimated to be $600 million. The projects awarded by MISO will be developed, owned and operated by Midcontinent Grid Solutions Wisconsin, LLC (MGS Wisconsin), a subsidiary of Midcontinent Grid Solutions, LLC.

In May 2025, Midcontinent Grid Solutions, LLC’s subsidiary, Midcontinent Grid Solutions Iowa, LLC (MGS Iowa) submitted to FERC a request for acceptance of formula rates, consisting of a formula rate template and implementation protocols, effective July 2025.

In September 2025, the FERC issued an order accepting the formula rate, granting MGS Iowa’s requested effective date of July 2025 and the following: (a) regulatory asset treatment for pre-commercial and formation costs with carrying charges, (b) a hypothetical capital structure of 60% equity and 40% debt through the date of the company’s first transmission project being placed in service, (c) conditional approval of a 50-basis point ROE adder due to participation in an RTO, effective upon the date on which operational control transitions to MISO, and (d) authorization of the company’s request to replicate its formula rate and related treatments for future subsidiaries in MISO. FERC also accepted MGS Iowa’s proposed use of a 9.98% base ROE, the MISO regional base ROE effective at the time of the FERC order, and the depreciation rates proposed by the company.

As an affiliate of Midcontinent Grid Solutions Iowa, LLC (MGS Iowa), MGS Wisconsin is authorized to replicate MGS Iowa’s FERC-approved formula rate without further FERC approval.

Valley Link Investment (Applies to AEP and Transource Energy)

In 2024, Transource Energy and affiliates of Dominion Energy and FirstEnergy formed Valley Link Transmission, LLC to participate in PJM’s 2024 Regional Transmission Expansion Plan competitive process. Valley Link proposed regional electric transmission upgrades for PJM's consideration during PJM’s 2024 Reliability Window 1. In February 2025, PJM selected the upgrades proposed by Valley Link to address forecasted reliability requirements. The projects awarded by PJM are estimated to cost approximately $3 billion and Transource Energy’s share of this investment is estimated to be $1.1 billion.

In March 2025, Valley Link’s subsidiaries, including Valley Link Transmission Maryland, LLC, Valley Link Transmission Virginia, LLC and Valley Link Transmission West Virginia, LLC, submitted to FERC a request for acceptance of formula rates for each company, consisting of a formula rate template and implementation protocols, effective May 2025. The filing also requested approval of Federal Power Act Section 219 transmission incentive rate treatments for the projects awarded by PJM to the Valley Link subsidiaries. In May 2025, the FERC issued an order accepting the formula rate, granting the incentives for: (a) recovery of abandonment costs if the project is cancelled for reasons beyond Valley Link’s control, (b) inclusion of CWIP in rates while the project is in development, (c) regulatory asset treatment for pre-commercial costs and (d) a 50-basis point ROE adder due to participation in an RTO. The order also initiated settlement proceedings to determine the companies’ base ROE, hypothetical capital structure, formula rate template language and depreciation rates.

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Fuel Cell Agreement

In November 2024, AEP executed a purchase agreement to acquire 100 MWs of solid oxide fuel cells with an option to acquire up to one gigawatt in total by the end of 2025. AEP, through its subsidiaries, offers data centers and other large customers this custom solution to support their growing energy needs while it completes grid infrastructure enhancements to accommodate demand. By the end of the first quarter of 2025, OPCo had signed two contracts totaling approximately 98 MWs for electricity service from fuel cells. In February 2025, OPCo requested PUCO approval of those two contracts. The PUCO approved the contracts in May 2025.

In September 2025, an intervenor filed a request for rehearing with the Supreme Court of Ohio, opposing the PUCO's approval and claiming that the order was unlawful, anti-competitive, and discriminatory.

Ohio House Bill 15 repeals the statute that permits electric distribution utilities, including OPCo, to execute contracts to provide customer-sited renewable generation service such as fuel cell technology or other renewable resources after August 14, 2025, but grandfathered the two existing PUCO approved contracts. See “Ohio Legislation” section above for additional information.

In January 2026, under the existing option to acquire additional fuel cells, an unregulated AEP subsidiary entered into an agreement to acquire solid oxide fuel cells for approximately $2.65 billion to develop a fuel cell generation facility near Cheyenne, Wyoming. The subsidiary also entered into a 20-year offtake agreement with an investment-grade customer for 100% of the facility’s output. The offtake arrangement is subject to certain conditions that AEP expects to be satisfied by the second quarter of 2026. If these conditions are not met, AEP will receive financial compensation for all capital and costs incurred.

Forward Sale of Equity

In March 2025, AEP entered into separate forward sale agreements with non-affiliate forward purchasers relating to 22,549,020 shares of AEP’s common stock at an initial price of $102.00 per share, exclusive of an underwriting discount equal to $2.244 per share. Except in certain specified circumstances that would require physical share settlement, AEP may elect to settle the forward sale transaction by means of physical, cash or net share settlement. The timing of the settlement of the forward sale agreements is also at AEP’s discretion, and management currently expects settlement to occur on or prior to December 31, 2026. To the extent the forward sale agreements are physically settled, AEP will issue common stock to the forward purchasers and receive cash proceeds based on the applicable forward sale price on the settlement date as defined in the forward sale agreements. For the year ended 2025, AEP issued 5,022,229 shares of common stock and received net cash proceeds of $500 million. As of December 31, 2025, AEP expects approximately $1.7 billion of net cash proceeds from the remaining physical settlement of the forward sale agreements and management anticipates using any future proceeds for general corporate purposes, capital investments, acquisitions or repayment of debt. The forward sale transactions will be classified as equity transactions because they are indexed to AEP’s common stock and physical settlement is within AEP’s control.

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LITIGATION

In the ordinary course of business, AEP is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases that have a probable likelihood of loss if the loss can be estimated.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition. See Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies for additional information.

Claims for Indemnification Made by Owners of the Gavin Power Station

AEP sold the Gavin Power Station to Gavin Power LLC and Lighthouse Generation LLC in 2017. Pursuant to the PSA for that transaction, AEP maintained responsibility to complete closure of the 300 acre unlined fly ash reservoir (FAR) pond in accordance with the closure plan approved by the Ohio EPA and to indemnify the purchasers for that work. In November 2022, the Federal EPA made several assertions related to the CCR Rule (see “CCR Rule” section below for additional information), including an assertion that the closure of the FAR is noncompliant with the CCR Rule in multiple respects. The owners of the Gavin Power Station have notified AEP that they believe they are entitled to indemnification for any damages that may result from these claims. Management does not believe that the owners of the Gavin Power Station have any valid claim for indemnity or otherwise against AEP under the PSA. See “Claims for Indemnifications Made by Owners of the Gavin Power Station” section of Note 6 for additional information.

ENVIRONMENTAL ISSUES

AEP has a substantial capital investment program and incurs additional operational costs to comply with environmental control requirements.  Additional investments and operational changes will be made in response to existing and potential future requirements to reduce emissions from fossil generation and in response to rules governing the beneficial use and disposal of coal combustion by-products, clean water and renewal permits for certain water discharges. AEP is unable to predict changes in regulations, regulatory guidance, legal interpretations, policy positions and implementation actions that may evolve.

AEP is engaged in litigation about environmental issues, was notified of potential responsibility for the clean-up of contaminated sites and incurred costs for disposal of SNF and future decommissioning of the nuclear units.  Management is engaged in the development of possible future requirements including the items discussed below.  

AEP will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances.  If AEP cannot recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.

Impact of Environmental Compliance on the Generating Fleet

The rules and environmental control requirements discussed below will have a material impact on AEP’s operations.  As of December 31, 2025, AEP owned generating capacity of approximately 25,400 MWs, of which approximately 10,700 MWs were coal-fired.  In April 2024, the Federal EPA announced four major new rules directed at fossil-fuel electric generation facilities. Management continues to evaluate the impacts of these rules on the plans for the future of AEP’s generating fleet, in particular, the economic feasibility of making the requisite environmental investments in AEP’s fossil generation fleet. AEP continues to refine the cost estimates of complying with these rules to identify the best alternative for promoting compliance with all of the rules while meeting AEP’s obligations to provide reliable and affordable electricity.

The costs of complying with new rules may also change based on: (a) potential state rules that impose additional more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) actual performance of the pollution control technologies installed, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity, (g) policy changes implemented by the Presidential administration and (h) other factors.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states and localities implement and administer many of these programs and could impose additional or more stringent requirements. Primary CAA regulatory programs that continue to drive investments in AEP’s existing generating units include the following: (a) periodic revisions to NAAQS and the development of SIPs to achieve more stringent standards, (b) implementation of the regional haze program by the states and the Federal EPA, (c) regulation of hazardous air pollutant emissions under MATS, (d) implementation and review of CSAPR and (e) the Federal EPA’s regulation of GHG emissions

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from fossil generation under Section 111 of the CAA. Certain notable developments in significant CAA regulatory requirements affecting AEP’s operations are discussed in the following sections.

National Ambient Air Quality Standards

The Federal EPA periodically reviews and revises the NAAQS for criteria pollutants under the CAA. Revisions tend to increase the stringency of the standards, which in turn may require AEP to make investments in pollution control equipment at existing generating units, or, since most units are already well controlled, to make changes in how units are dispatched and operated. In February 2024, the Federal EPA finalized a new more stringent annual primary PM2.5 standard.

Areas with air quality that does not meet the new standard will be designated by the Federal EPA as “nonattainment,” which will trigger an obligation for states to revise their SIPs to include additional requirements, resulting in further emission reductions to meet the new standard. In November 2025, in connection with pending litigation challenging the new standards, the Federal EPA filed a motion asking the court to vacate the stricter PM2.5 standard.

If the rule is not vacated, areas around some of AEP’s generating facilities may be deemed nonattainment, which may require those facilities to install additional pollution controls or to implement operational constraints. Any nonattainment designations by the Federal EPA and the subsequent SIP revisions by affected states will take time to finalize and complete. Management cannot reasonably estimate any impacts on AEP’s operations, cash flows, net income or financial condition.

Regional Haze

The Federal EPA issued a Clean Air Visibility Rule (CAVR) in 2005, which would require certain power plants and other facilities to install best available retrofit technology to address regional haze in federal parks and other protected areas. CAVR is implemented by the states, through SIPs, or by the Federal EPA, through FIPs. The rules implementing the Regional Haze requirements of the CAA have been revisited over time. In January 2026, the Federal EPA published a final rule extending the due date for the next round of Regional Haze SIP submittals by states to July 31, 2031.

The Federal EPA disapproved portions of the Texas regional haze SIP and finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NOX regional haze obligations for electric generating units in Texas. Additionally, the Federal EPA finalized an intrastate SO2 emissions trading program based on CSAPR allowance allocations. Environmental groups filed challenges to these various rulemakings in district courts in the Fifth Circuit and the District of Columbia Circuit. Management cannot predict the outcome of that litigation, although management supports the intrastate trading program as a compliance alternative to source-specific controls and intervened in the Fifth Circuit litigation in support of the Federal EPA. In July 2024, the U.S. District Court for the District of Columbia Circuit entered a consent decree setting deadlines for the Federal EPA to rule on Regional Haze SIPs for 32 states, including Texas. In September 2024, the Federal EPA signed a proposed rule to partially approve and partially disapprove the Texas SIP revision. In May 2025, the Federal EPA proposed to withdraw the prior proposed rule, including the proposed partial disapproval of the Texas SIP revision, and instead proposed to approve the Texas Regional Haze SIP. In December 2025, the Federal EPA finalized its approval of the Texas and Oklahoma SIPs. The Federal EPA has recently approved Regional Haze SIP submissions for Ohio and West Virginia, both of which have been appealed by environmental groups. Management will continue to monitor the litigation and cannot predict the outcome.

New Source Performance Standards

In January 2026, the Federal EPA finalized revisions to the New Source Performance Standards for stationary combustion turbine units that commenced construction, modification, or reconstruction after December 13, 2024. The new standards for NOX require a level of performance equivalent to the application of selective catalytic reduction for large, high-utilization natural gas-fired turbines, but establish various levels of combustion controls as the best system of emission reductions for smaller and lower-utilization turbines. The rule does not change the SO2 limits applicable to combustion turbines. Management is evaluating the implications of the rule on new combustion turbine projects.

Cross-State Air Pollution Rule

CSAPR is a regional trading program that the Federal EPA began implementing in 2015 to address interstate transport of emissions that contribute significantly to nonattainment and interfere with maintenance of the 1997 ozone NAAQS and the 1997 and 2006 PM2.5 NAAQS in downwind states.  CSAPR relies on SO2 and NOX allowances and individual state budgets to compel further emission reductions from electric utility generating units.  Interstate trading of allowances is allowed on a restricted basis. The Federal EPA has revised, or updated, the CSAPR trading programs several times since they were established.

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In January 2021, the Federal EPA finalized a revised CSAPR, which substantially reduced the ozone season NOX budgets for several states, including states where AEP operates, beginning in ozone season 2021. AEP met the requirements of the revised rule over the first few years of implementation, and is evaluating its compliance options for future years, when the budgets are further reduced.

In February 2023, the Federal EPA Administrator finalized the disapproval of interstate transport SIPs submitted by 19 states, including Texas, addressing the 2015 Ozone NAAQS. The Federal EPA disapproved interstate transport SIPs submitted by additional states soon thereafter. Disapproval of the SIPs provided the Federal EPA with authority to impose a FIP for those states, replacing the SIPs that were disapproved. In August 2023, a FIP (the Good Neighbor Plan) went into effect that further revised the ozone season NOX budgets under the existing CSAPR program in states to which the FIP applies. The FIP has since been administratively stayed pending the Supreme Court lifting its order staying enforcement of the Good Neighbor Plan, other courts lifting any judicial orders staying the SIP disapproval action as to the state, and the Federal EPA taking subsequent rulemaking action consistent with any judicial rulings on the merits. Additionally, in April 2025, the court placed the challenges to the Good Neighbor Plan in abeyance pending further order of the court. The Federal EPA has indicated it intends to propose rulemaking to revise the rule. Management will continue to monitor the litigation and any further actions by the Federal EPA for any potential impact to operations.

Climate Change, CO2 Regulation and Energy Policy

In April 2024, the Administrator of the Federal EPA signed new GHG standards and guidelines for new and existing fossil-fuel fired sources. The rule relies on carbon capture and sequestration and natural gas co-firing as means to reduce CO2 emissions from coal fired plants and carbon capture and sequestration or limited utilization to reduce CO2 emissions from new gas turbines. The rule also offers early retirement of coal plants in lieu of carbon capture and storage as an alternative means of compliance.

Twenty-seven states, numerous companies, trade associations and others challenged the rule. AEP has joined with several other utilities to challenge the rule and has asked the court to stay the rule during the litigation, and the appeals have been consolidated. The court has stayed the litigation pending rulemaking by the Federal EPA. In June 2025, the Federal EPA proposed to determine that GHG emissions from fossil-fueled power plants do not significantly contribute to air pollution that may endanger public health or the environment. This determination would eliminate all GHG standards for existing and new fossil-fuel plants. As an alternative, the Federal EPA proposed to eliminate GHG standards for existing coal and gas units and to keep only certain emission limits applicable to new sources. These proposals have not been finalized. In July 2025, the Federal EPA proposed to repeal the 2009 Endangerment Finding, which determined that greenhouse gas emissions endanger public health and welfare. The 2009 Endangerment Finding is the basis of the Federal EPA’s authority to regulate greenhouse gas emissions under the Clean Air Act and was used to first regulate motor vehicle emissions. Management is evaluating the Federal EPA’s proposed repeal of the 2009 Endangerment Finding and its impact on the Federal EPA’s authority to regulate greenhouse gas emissions from electric generators. Management cannot predict the outcome of the current litigation or the Federal EPA’s proposed actions related to the rule or the Endangerment Finding and any subsequent litigation that may result. Excessive costs to comply with environmental regulations have led to the announcement of early plant closures across the country. More stringent rules directed at the fossil-fuel fired electric utility industry could force AEP to close additional coal-fired generation facilities earlier than their estimated useful life, if those rules remain in place. If AEP is unable to recover the costs of its investments, it would reduce future net income and cash flows and impact financial condition.

AEP is committed to delivering reliable, affordable power and routinely submits IRPs in various regulatory jurisdictions to address future generation needs. A recent evaluation demonstrated that changing external conditions and business growth, including unprecedented load growth, evolving market and policy dynamics, and jurisdictional preferences will impact AEP’s corporate-wide pathway to reduce Scope 1 GHG emissions by 80% by 2030 through collective state IRPs. Accordingly, AEP continues to focus on supporting state-based clean energy mandates and decarbonization targets, including meeting the Virginia Clean Economy Act and Michigan Public Act 235 mandates that are on track for achievement. AEP remains committed to seeking advanced low-carbon generation solutions where supported. As an example, APCo and I&M are seeking early site permits to bring small modular reactors to Virginia and Indiana. In light of this shift, AEP will continue to assess aspirations to achieve net-zero Scope 1 and 2 emissions by 2045. AEP’s performance will ultimately be driven by the needs and desires of the states AEP serves and the company will continue to engage with regulators and policymakers to meet the energy needs while facilitating the delivery of reliable, affordable energy.

MATS Rule

In April 2024, the Federal EPA issued a revised MATS rule for power plants, which includes a more stringent standard for emissions of filterable PM for coal-fired electric generating units, as well as a new mercury standard for lignite-fired electric

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generating units. The rule also requires the installation and operation of continuous emissions monitors for PM. Several states and other parties have challenged the rule in the United States Court of Appeals for the District of Columbia Circuit, but management cannot predict the outcome of the litigation. The litigation is being held in abeyance. In June 2025, the Federal EPA proposed to repeal the 2024 MATS rule and revert to the 2012 MATS rule emission standards. Management does not anticipate any significant challenges complying with the 2024 MATS rule, should the proposed repeal not be finalized.

CCR Rule

The Federal EPA’s CCR Rule regulates the disposal and beneficial re-use of CCR, including fly ash and bottom ash created from coal-fired generating units and FGD gypsum generated at some coal-fired plants.  As originally promulgated in 2015, the rule applied to active and inactive CCR landfills and surface impoundments at facilities of active electric utility or independent power producers.

In August 2018, the District of Columbia Circuit Court vacated and remanded certain aspects of the 2015 CCR rule, including an exemption for legacy impoundments. Following this, the Federal EPA issued a final rule in August 2020, setting an April 11, 2021 deadline for unlined CCR impoundments to cease waste acceptance and commence closure. This rule permits a facility to request a deadline extension from the Federal EPA if alternative disposal capacity is unavailable or a compliant conversion or a plant retirement is in progress.

In January 2022, the Federal EPA made public statements in the context of a deadline extension request submitted by the Gavin Power Station suggesting more stringent closure requirements for CCR units. See “Claims for Indemnification Made by Owners of the Gavin Power Station” above for additional information. In April 2022, a petition was filed with the District of Columbia Circuit Court of Appeals, arguing that the Federal EPA could not enforce these new purported requirements without proper rulemaking. In June 2024, the District of Columbia Circuit dismissed these petitions, finding the statements were not amendments to existing regulations and thus the court lacked jurisdiction.

In April 2024, the Federal EPA finalized revisions to the CCR Rule to expand the scope of the rule to include inactive impoundments at inactive facilities (“legacy CCR surface impoundments”) as well as to establish requirements for currently exempt solid waste management units that involve the direct placement of CCR on the land (“CCR management units”). That rule has been challenged in the District of Columbia Circuit Court. In March 2025, the Federal EPA announced plans to make changes to the CCR Rule and to work with states to implement future CCR requirements. As a result, the litigation challenging the 2024 Legacy Rule is being held in abeyance. In November 2025, the Federal EPA proposed to extend by three years the compliance deadline applicable to certain facilities operating pursuant to alternative closure deadlines for unlined surface impoundments greater than 40 acres. In February 2026, the Federal EPA finalized a rule that provides additional time to meet facility evaluation requirements for identifying CCR management units and to comply with groundwater monitoring provisions. Additionally, this rule makes conforming changes to the remaining CCR management units compliance deadlines. Additional revisions to the CCR Rule are expected in 2026.

Should additional corrective measures like groundwater treatment or ash removal be mandated at any of AEP’s coal-fired facilities, AEP could face substantial costs that could materially and adversely affect financial condition, results of operations, and cash flows. See “Federal EPA’s Revised CCR Rule” section in Note 6 for additional information.

Clean Water Act Regulations

The Federal EPA’s ELG rule for generating facilities establishes limits for FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater, which are to be implemented through each facility’s wastewater discharge permit. A revision to the ELG rule, published in October 2020, established additional options for reusing and discharging small volumes of bottom ash transport water, provided an exception for retiring units and extended the compliance deadline to a date as soon as possible beginning one year after the rule was published but no later than December 2025. Management has assessed technology additions and retrofits to comply with the rule and the impacts of the Federal EPA’s actions on facilities’ wastewater discharge permitting for FGD wastewater and bottom ash transport water. For affected facilities required to install additional technologies to meet the ELG rule limits, permit modifications were filed in January 2021 that reflect the outcome of that assessment. AEP continues to work with state agencies to finalize permit terms and conditions. Other facilities opted to file Notices of Planned Participation (NOPP), pursuant to which the facilities are not required to install additional controls to meet ELG limits provided they make commitments to cease coal combustion by a date certain.

In April 2024, the Federal EPA finalized further revisions to the ELG rule that establish a zero liquid discharge standard for FGD wastewater, bottom ash transport water, and managed combustion residual leachate, as well as more stringent discharge limits for unmanaged combustion residual leachate. The revised rule provides a new compliance alternative that would

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eliminate the need to install zero liquid discharge systems for facilities that comply with the 2020 rule’s control technology requirements and have committed by December 31, 2025 to retire by 2034. Management is evaluating the compliance alternatives in the rule, taking into consideration the requirements of the other new rules and their combined impacts to operations. Several appeals have been filed with various federal courts challenging the 2024 ELG rule. SWEPCo also challenged the rule by filing a joint appeal with a utility trade association in which AEP participates. The litigation challenging the ELG Rule is being held in abeyance while the new administration evaluates the rule and the Federal EPA has subsequently announced plans to reconsider the standards and deadlines established by the 2024 ELG rule. Management cannot predict the outcome of the litigation.

In December 2025, the Federal EPA issued the Deadline Extension ELG Rule to extend the compliance deadlines in the 2024 ELG Rule by five years as well as to establish a site-specific mechanism for extending compliance deadlines for both the 2020 and 2024 ELG Rules. Management cannot predict the outcome of any further rulemaking actions by the Federal EPA related to the ELG rule.

In January 2026, the Federal EPA proposed a rule titled Updating the Water Quality Certification Regulations. Through the proposed rule, the Federal EPA is attempting to clarify the Clean Water Act section 401 certification process for states and tribes. Under section 401, a federal agency cannot conduct any activity that may result in a discharge into waters of the United States without obtaining a permit from a State or authorized tribe in the location of the discharge certifying compliance with applicable water quality requirements. The proposed rule aims to reduce regulatory delays associated with the certification process. Management will monitor the rulemaking for any potential impacts to operations.

The definition of “waters of the United States” has been subject to rulemaking and litigation which has led to inconsistent scope among the states. In November 2025, the Federal EPA and the United States Army Corps of Engineers proposed a revised definition of “waters of the United States” to conform to a decision by the United States Supreme Court. Management will continue to monitor developments in rulemaking and litigation for any potential impact to operations.

Impact of Environmental Regulation on Coal-Fired Generation

Compliance with extensive environmental regulations requires significant capital investment in environmental monitoring, installation of pollution control equipment, emission fees, disposal, remediation and permits. Management regularly evaluates cost estimates of complying with these regulations which may result in a decision to retire coal-fired generating facilities earlier than their currently estimated useful lives.

For generating facilities retired or planned for retirement in advance of the retirement date currently authorized for ratemaking purposes, with related accelerated depreciation regulatory assets pending regulatory approval, the table below summarizes the net book value and related regulatory asset balances recorded as of December 31, 2025:

Company	Plant	Net Investment (a)		Accelerated Depreciation Regulatory Asset			Actual/Projected Retirement Date		Current Authorized Recovery Period	Annual Depreciation (b)
		(in millions)								(in millions)
PSO	Northeastern Plant, Unit 3	$	73	$	221		2026		(c)	$	15
SWEPCo	Pirkey Plant	—		94		(d)	2023		(e)	—
SWEPCo	Welsh Plant, Units 1 and 3	269		220			2028	(f)	(g)	47

(a)Net book value including CWIP excluding cost of removal and materials and supplies.

(b)These amounts represent the amount of annual depreciation that has been collected from customers over the prior 12-month period.

(c)Northeastern Plant, Unit 3 is currently being recovered through 2040. In April 2025, PSO and ODEQ finalized a second amended regional haze agreement that would allow continued operation of the Northeastern Plant, Unit 3, on natural gas, through May 31, 2041. This agreement is contingent upon approval by the Federal EPA in the form of a revised SIP. ODEQ is in the process of preparing a SIP submission for the Federal EPA’s review and approval.

(d)Represents Texas and FERC jurisdictional share.

(e)SWEPCo requested recovery of the Texas jurisdictional share of the remaining net book value of the Pirkey Plant in its 2025 Texas Base Rate Case. See the “Regulated Generating Units” section of Note 5 for additional information. In January 2026, the FERC issued an order providing recovery of the Pirkey Plant based on blended recovery periods determined by all SWEPCo jurisdictions including Texas.

(f)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028. In December 2024, SWEPCo filed an application for a CCN with the APSC, LPSC and PUCT to convert Welsh Plant, Units 1 and 3 to natural gas in 2028 and 2027, respectively.

(g)Welsh Plant, Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Welsh Plant, Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

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Management is seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the plants are retired. To the extent the net book value of these generation assets is not deemed recoverable, it could materially reduce future net income, cash flows and impact financial condition.

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RESULTS OF OPERATIONS

AEP’s Reportable Segments

AEP’s primary business is the generation, transmission and distribution of electricity.  Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight applicable to each public utility subsidiary.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments are as follows:

•Vertically Integrated Utilities

•Transmission and Distribution Utilities

•AEP Transmission Holdco

•Generation & Marketing

The remainder of AEP’s activities are presented as Corporate and Other, which is not considered a reportable segment. See Note 9 - Business Segments for additional information on AEP’s segments.

The following discussion of AEP’s results of operations by operating segment provides a comparison of earnings (loss) attributable to AEP common shareholders for the year ended December 31, 2025 as compared to the year ended December 31, 2024. For AEP’s Vertically Integrated Utilities and Transmission and Distribution Utilities segments and Registrant Subsidiaries within these segments, the results include revenues from rate rider mechanisms designed to recover fuel, purchased power and other recoverable expenses such that the revenues and expenses associated with these items generally offset and do not affect Earnings Attributable to AEP Common Shareholders. For additional information regarding the financial results for the years ended December 31, 2025 and 2024, see the discussions of Results of Operations by Registrant Subsidiary.

A detailed discussion of AEP’s 2024 results of operations by operating segment can be found in Management’s Discussion and Analysis of Financial Condition and Results of Operation section included in the 2024 Annual Report on Form 10-K filed with the SEC on February 13, 2025.

The following table presents Earnings Attributable to AEP Common Shareholders by segment:

	Years Ended December 31,
	2025		2024		2023
	(in millions)
Vertically Integrated Utilities	$	1,605	$	1,453	$	1,090
Transmission and Distribution Utilities	816		726		699
AEP Transmission Holdco	1,161		790		703
Generation & Marketing	287		289		(26)
Corporate and Other	(289)		(291)		(258)
Earnings Attributable to AEP Common Shareholders	$	3,580	$	2,967	$	2,208

See Note 9 - Business Segments for additional information on Earnings (Loss) Attributable to AEP Common Shareholders by segment.

Heating Degree Days and Cooling Degree Days

Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues.  In general, degree day changes in the Eastern Region have a larger effect on revenues than changes in the Western Region due to the relative size of the two regions and the number of customers within each region.

The actual heating degree days are calculated on a 55-degree temperature base and the actual cooling degree days are calculated on a 65-degree temperature base for Registrant Subsidiaries except AEP Texas. AEP Texas’ actual heating degree days are calculated on a 55-degree temperature base and actual cooling degree days are calculated on a 70-degree temperature base. Due to the recent more volatile weather, effective in January 2025, the calculation methodology for heating degree days and cooling degree days was changed from a daily minimum/maximum average temperature over a thirty-year period to a daily hourly average temperature over a twenty-year period. This change did not have a material impact on the Registrants’ discussion of weather-related usage.

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VERTICALLY INTEGRATED UTILITIES

Summary of KWh Energy Sales for Vertically Integrated Utilities
	Years Ended December 31,
	2025	2024	2023
	(in millions of KWhs)
Retail:
Residential	31,844	31,025	30,290
Commercial	26,295	24,647	23,481
Industrial	33,571	34,013	34,148
Miscellaneous	2,257	2,271	2,229
Total Retail	93,967	91,956	90,148
Wholesale (a)	16,039	14,523	13,401
Total KWhs	110,006	106,479	103,549

(a)Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.

Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities
	Years Ended December 31,
	2025	2024	2023
	(in degree days)
Eastern Region
Actual – Heating	2,741	2,092	1,992
Normal – Heating	2,646	2,704	2,719
Actual – Cooling	1,120	1,366	1,003
Normal – Cooling	1,110	1,114	1,119
Western Region
Actual – Heating	1,354	1,052	1,068
Normal – Heating	1,436	1,450	1,464
Actual – Cooling	2,506	2,738	2,590
Normal – Cooling	2,307	2,289	2,277

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Reconciliation of Year Ended December 31, 2024 to Year Ended December 31, 2025

Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities

(in millions)

Year Ended December 31, 2024	$	1,453
Changes in Revenues:
Retail Revenues	956
Off-system Sales	145
Transmission Revenues	113
Other Revenues	8
Total Change in Revenues	1,222
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(260)
Other Operation and Maintenance	(356)
Asset Impairments and Other Related Charges	(21)
Depreciation and Amortization	(105)
Taxes Other Than Income Taxes	3
Other Income	(1)
Allowance for Equity Funds Used During Construction	22
Non-Service Cost Components of Net Periodic Pension Cost	1
Interest Expense	(132)
Total Change in Expenses and Other	(849)
Income Tax Benefit	(222)
Net Income Attributable to Noncontrolling Interests	1
Year Ended December 31, 2025	$	1,605

The major components of the increase in Revenues were as follows:

•Retail Revenues increased $956 million primarily due to the following:

•A $601 million increase in base rate and rider revenues.

•A $148 million increase at SWEPCo due to a revenue refund provision recorded in 2024 associated with the Turk Plant and SWEPCo’s 2012 Texas Base Rate Case.

•A $133 million increase in weather-normalized revenues primarily in the residential and commercial classes, partially offset by a decrease in the industrial class.

•A $109 million increase in fuel revenues.

•A $50 million increase in weather-related usage primarily in the residential class driven by a 30% increase in heating degree days.

These increases were partially offset by:

•An $86 million decrease due to regulatory provisions for refund at I&M.

•Off-system Sales increased $145 million primarily due to economic hedging activity, Rockport Plant, Unit 2 merchant sales at I&M and capacity revenues recognized from the RPM auction for the 2025-2026 planning year at APCo.

•Transmission Revenues increased $113 million primarily due to the following:

•A $65 million increase due to continued transmission investment.

•A $56 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•Other Revenues increased $8 million primarily due to gains from the sale of renewable energy credits.

Expenses and Other and Income Tax Benefit changed between years as follows:

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $260 million primarily due to increases at I&M and PSO, partially offset by decreases at APCo and SWEPCo.

•Other Operation and Maintenance expenses increased $356 million primarily due to the following:

•A $114 million increase in distribution expenses primarily due to vegetation management costs.

•An $88 million increase in PJM and SPP transmission expenses.

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•A $60 million increase in generation expenses.

•A $60 million increase in employee-related expenses.

•A $53 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $29 million increase in customer operations and services primarily due to recoverable energy assistance program expenses for qualified Virginia customers at APCo.

These increases were partially offset by:

•A $76 million decrease due to the voluntary severance program that occurred in the second quarter of 2024.

•A $14 million decrease due to a disallowance recorded on the remaining net book value of the Dolet Hills Power Station as a result of an LPSC approved settlement agreement in April 2024.

•Asset Impairments and Other Related Charges increased $21 million primarily due to the following:

•A $34 million increase due to an impairment of in-process internal use software development costs.

This increase was partially offset by:

•A $13 million decrease due to the Federal EPA’s revised CCR rules finalized in 2024.

•Depreciation and Amortization expenses increased $105 million primarily due to the following:

•A $117 million increase primarily due to a higher depreciable base at APCo, I&M, PSO and SWEPCo.

•A $20 million increase at I&M due to a prior year deferral combined with current year amortization of Excess ADIT as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking.

•A $20 million increase at SWEPCo due to the amortization of the Storm Recovery Funding securitized assets.

These increases were partially offset by:

•A $61 million decrease due to the under-recovery of regulatory assets related to renewables at PSO and SWEPCo.

•Allowance for Equity Funds Used During Construction increased $22 million primarily due to increased AFUDC base and rates.

•Interest Expense increased $132 million primarily due to higher long-term debt balances at APCo, PSO and SWEPCo and a prior year deferral of expenses as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking at I&M, PSO and SWEPCo.

•Income Tax Benefit decreased $222 million primarily due to the following:

•A $212 million decrease due to a reduction in Excess ADIT regulatory liabilities at I&M, PSO and SWEPCo as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking recorded in 2024.

•A $78 million decrease due to an increase in pretax book income.

•A $32 million decrease due to the reversal of a regulatory liability related to the merchant portion of Turk Plant Excess ADIT as a result of the APSC’s denial of SWEPCo’s request to allow the merchant portion of the Turk Plant to serve Arkansas customers recorded in 2024.

These decreases were partially offset by:

•A $114 million increase due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

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TRANSMISSION AND DISTRIBUTION UTILITIES

Summary of KWh Energy Sales for Transmission and Distribution Utilities
	Years Ended December 31,
	2025	2024	2023
	(in millions of KWhs)
Retail:
Residential	27,437	26,782	26,099
Commercial	46,187	36,147	30,419
Industrial	28,020	27,368	26,571
Miscellaneous	728	742	745
Total Retail (a)	102,372	91,039	83,834
Wholesale (b)	2,250	2,014	1,922
Total KWhs	104,622	93,053	85,756

(a)Represents energy delivered to distribution customers.

(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.

Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities
	Years Ended December 31,
	2025	2024	2023
	(in degree days)
Eastern Region
Actual – Heating	3,273	2,446	2,380
Normal – Heating	3,057	3,140	3,185
Actual – Cooling	1,098	1,300	842
Normal – Cooling	1,056	1,031	1,026
Western Region
Actual – Heating	348	196	197
Normal – Heating	323	316	318
Actual – Cooling	2,956	3,249	3,208
Normal – Cooling	2,641	2,770	2,737

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 Reconciliation of Year Ended December 31, 2024 to Year Ended December 31, 2025

Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities

(in millions)

Year Ended December 31, 2024	$	726
Changes in Revenues:
Retail Revenues	195
Off-system Sales	56
Transmission Revenues	72
Other Revenues	(84)
Total Change in Revenues	239
Changes in Expenses and Other:
Purchased Electricity for Resale	(67)
Purchased Electricity from AEP Affiliates	33
Other Operation and Maintenance	(152)
Asset Impairments and Other Related Charges	22
Depreciation and Amortization	59
Taxes Other Than Income Taxes	(20)
Other Income	(8)
Allowance for Equity Funds Used During Construction	8
Non-Service Cost Components of Net Periodic Benefit Cost	9
Interest Expense	(18)
Total Change in Expenses and Other	(134)
Income Tax Expense	(18)
Equity Earnings of Unconsolidated Subsidiaries	3
Year Ended December 31, 2025	$	816

The major components of the increase in Revenues were as follows:

•Retail Revenues increased $195 million primarily due to the following:

•A $171 million increase in base case and rider revenues.

•A $26 million increase in weather-related usage driven by a 34% increase in heating degree days in Ohio.

These increases were partially offset by:

•A $14 million decrease in weather-normalized revenues primarily in the residential class in Ohio.

•Off-system Sales increased $56 million primarily due to increased sales of OVEC purchased power driven by higher market prices and volume.

•Transmission Revenues increased $72 million primarily due to the following:

•A $120 million increase primarily due to continued transmission investments.

This increase was partially offset by:

•A $48 million decrease due to lower peak loads included in 2025 billing rates in Texas.

•Other Revenues decreased $84 million primarily due to the following:

•A $74 million decrease in securitization revenues resulting from the maturity of Transition Funding III LLC securitization bonds in December 2024.

•An $18 million decrease due to lower third-party Legacy Generation Resource Rider revenue as a result of approved legislation in Ohio in May 2025 which ended the retail recovery of OVEC purchased power costs.

Expenses and Other and Income Tax Expense changed between years as follows:

•Purchased Electricity for Resale expenses increased $67 million primarily due to the following:

•A $35 million increase in recoverable auction purchases from nonaffiliates to serve SSO customers in Ohio.

•A $24 million increase due to a reduction in regulatory assets for OVEC-related purchased power costs that are no longer probable of future recovery due to approved legislation in Ohio in May 2025.

•A $13 million increase in OVEC-related purchased power expenses.

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•Purchased Electricity from AEP Affiliates expenses decreased $33 million primarily due to decreased recoverable auction purchases from AEP Energy Partners to serve SSO customers in Ohio.

•Other Operation and Maintenance expenses increased $152 million primarily due to the following:

•A $105 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses in Ohio.

•A $54 million increase in recoverable Transmission Cost Recovery Factor expenses in Texas.

•A $22 million increase in employee-related expenses.

•A $19 million increase in transmission and distribution expenses in Texas.

These increases were partially offset by:

•A $35 million decrease due to the voluntary severance program that occurred in the second quarter of 2024.

•A $29 million decrease related to recoverable energy assistance program expenses for qualified Ohio customers.

•Asset Impairments and Other Related Charges decreased $22 million due to the following:

•A $53 million decrease due to the Federal EPA’s revised CCR rules finalized in 2024.

This decrease was partially offset by:

•A $31 million increase due to an impairment of in-process internal use software development costs in 2025.

•Depreciation and Amortization expenses decreased $59 million primarily due to the following:

•A $71 million decrease in the amortization of securitized transition assets due to the maturity of Transition Funding III LLC securitization bonds.

•A $23 million decrease due to the deferral of eligible costs related to the UTM.

These decreases were partially offset by:

•A $37 million increase due to a higher depreciable base in Texas.

•Taxes Other Than Income Taxes increased $20 million primarily due to higher property taxes.

•Other Income decreased $8 million primarily due to lower interest income as a result of lower advances to affiliates.

•Allowance for Equity Funds Used During Construction increased $8 million due to a higher AFUDC base in Texas.

•Non-Service Cost Components of Net Period Benefit Cost decreased $9 million primarily due to an increase in loss amortization for the plans and a plan remeasurement triggered by settlements related to the voluntary severance program in 2024, partially offset by lower interest costs due to lower discount rates.

•Interest Expense increased $18 million primarily due to the following:

•A $46 million increase due to higher long-term debt balances and interest rates.

This increase was partially offset by:

•A $28 million decrease due to the deferral of eligible costs related to the UTM.

•Income Tax Expense increased $18 million primarily due to an increase in pretax book income.

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AEP TRANSMISSION HOLDCO

Summary of Investment in Transmission Assets for AEP Transmission Holdco

	December 31,
	2025		2024
	(in millions)
Plant in Service	$	17,662	$	15,835
Construction Work in Progress	2,167		2,206
Accumulated Depreciation and Amortization	1,968		1,626
Total Transmission Property, Net	$	17,861	$	16,415

Reconciliation of Year Ended December 31, 2024 to Year Ended December 31, 2025

Earnings Attributable to AEP Members from AEP Transmission Holdco

(in millions)

Year Ended December 31, 2024	$	790
Changes in Transmission Revenues:
Transmission Revenues	426
Total Change in Transmission Revenues	426
Changes in Expenses and Other:
Other Operation and Maintenance	(31)
Depreciation and Amortization	(47)
Taxes Other Than Income Taxes	(13)
Interest and Investment Income	(5)
Allowance for Equity Funds Used During Construction	4
Non-Service Cost Components of Net Periodic Pension Cost	4
Interest Expense	(19)
Total Change in Expenses and Other	(107)
Income Tax Expense	173
Equity Earnings of Unconsolidated Subsidiaries	(12)
Net Income Attributable to Noncontrolling Interests	(109)
Year Ended December 31, 2025	$	1,161

The major components of the increase in Transmission Revenues, which consists of wholesale sales to affiliates and nonaffiliates were as follows:

•Transmission Revenues increased $426 million primarily due to the following:

•A $214 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $212 million increase due to continued transmission investment.

Expenses and Other, Income Tax Expense, Equity Earnings of Unconsolidated Subsidiaries and Net Income Attributable to Noncontrolling Interests changed between years as follows:

•Other Operation and Maintenance expenses increased $31 million primarily due to an increase in employee-related expenses, vegetation management expenses and other various miscellaneous expenses, partially offset by a decrease due to the voluntary severance program that occurred in the second quarter of 2024.

•Depreciation and Amortization expenses increased $47 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $13 million primarily due to higher property taxes driven by increased transmission investment.

•Interest and Investment Income decreased $5 million primarily due to lower advances to affiliates.

•Interest Expense increased $19 million primarily due to higher long-term debt balances and interest rates.

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•Income Tax Expense decreased $173 million primarily due to the following:

•A $254 million decrease due to a reduction in Excess ADIT as a result of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

This decrease was partially offset by:

•A $64 million increase due to an increase in pretax book income.

•A $15 million increase due to an increase in state taxes.

•Equity Earnings of Unconsolidated Subsidiaries decreased $12 million primarily due to lower pretax earnings by ETT and PATH-WV.

•Net Income Attributable to Noncontrolling Interests increased $109 million primarily due to the Midwest Transmission noncontrolling interest transaction that closed in June 2025.

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GENERATION & MARKETING

Reconciliation of Year Ended December 31, 2024 to Year Ended December 31, 2025

Earnings Attributable to AEP Common Shareholders from Generation & Marketing

(in millions)

Year Ended December 31, 2024	$	289
Changes in Revenues:
Merchant Generation	90
Renewable Generation	(24)
Retail, Trading and Marketing	651
Total Change in Revenues	717
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(783)
Other Operation and Maintenance	47
Asset Impairments and Other Related Charges	76
Depreciation and Amortization	5
Interest and Investment Income	(1)
Non-Service Cost Components of Net Periodic Benefit Cost	(2)
Interest Expense	9
Total Change in Expenses and Other	(649)
Income Tax Expense	(69)
Equity Earnings of Unconsolidated Subsidiaries	(1)
Year Ended December 31, 2025	$	287

The major components of the increase in Revenues were as follows:

•Merchant Generation increased $90 million primarily due to higher realized prices in 2025.

•Renewable Generation decreased $24 million primarily due to the sale of AEP Onsite Partners in September 2024.

•Retail, Trading and Marketing increased $651 million primarily due to higher market prices in 2025.

Expenses and Other and Income Tax Expense changed between years as follows:

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $783 million primarily due to an increase in energy costs in 2025.

•Other Operation and Maintenance expenses decreased $47 million primarily due to renewable contract termination proceeds in 2025 and the sale of AEP OnSite Partners in September 2024.

•Asset Impairments and Other Related Charges decreased $76 million due to the Federal EPA’s revised CCR Rules finalized in 2024.

•Depreciation and Amortization expenses decreased $5 million primarily due to the sale of AEP Onsite Partners in September 2024.

•Interest Expense decreased $9 million primarily due to lower advances from affiliates.

•Income Tax Expense increased $69 million primarily due to the following:

•A $54 million increase due to a decrease in amortization of deferred ITCs related to the sale of NMRD and AEP OnSite Partners in 2024.

•A $14 million increase due to an increase in pretax book income.

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CORPORATE AND OTHER

2025 Compared to 2024

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $291 million in 2024 to a loss of $289 million in 2025 primarily due to:

•A $21 million decrease in interest expense primarily due to lower short-term debt balances and interest rates.

•A $19 million loss contingency recorded in 2024 associated with the SEC investigation.

•An $18 million increase in equity earnings.

•An $11 million increase due to the recognition of deferred revenues for completed agreements.

These increases in earnings were partially offset by:

•A $31 million decrease in Income Tax Benefit primarily due to an increase in state taxes.

•A $30 million decrease in interest income primarily due to lower advances to affiliates.

•A $7 million decrease at EIS primarily due to increased insurance reserves.

AEP CONSOLIDATED INCOME TAXES

2025 Compared to 2024

•Income Tax Expense increased $168 million primarily due to the following:

•A $212 million increase due to a reduction in Excess ADIT regulatory liabilities at I&M, PSO and SWEPCo as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking recorded in 2024.

•A $187 million increase due to an increase in pretax book income.

•A $54 million increase due to a decrease in amortization of deferred ITCs primarily due to the sale of NMRD and Onsite Partners in 2024.

•A $32 million increase due to a reduction in Excess ADIT regulatory liabilities as a result of the APSC’s denial of SWEPCo’s request to allow the merchant portion of the Turk Plant to serve Arkansas customers recorded in 2024.

•A $29 million increase due to a decrease in amortization of Excess ADIT.

•A $15 million increase due to an increase in state taxes.

These increases were partially offset by:

•A $368 million decrease due to a reduction in Excess ADIT as a result of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

FINANCIAL CONDITION

AEP measures financial condition by the strength of its balance sheet and the liquidity provided by its cash flows.

SIGNIFICANT CASH REQUIREMENTS

AEP’s contractual cash obligations include amounts reported on the balance sheets and other obligations disclosed in the footnotes. It is anticipated that these obligations will be satisfied through a combination of cash flows from operations, long-term debt issuances, short-term debt through AEP’s Commercial Paper Program or bank term loans, the use of the ATM Program, the March 2025 forward sale of equity agreement or other equity issuances.

Capital Expenditures

Continued capital investments reflect AEP’s dedication to enhance service and deliver safe, reliable power to customers. In October 2025, AEP announced a $72 billion capital plan for 2026-2030 driven by transmission and distribution infrastructure upgrades and new generation to support anticipated load growth. See “Budgeted Capital Expenditures” herein, for additional information.

Long-term Debt

Long-term debt maturities, including interest, represent a significant cash requirement for AEP and the Registrant Subsidiaries. See Note 15 - Financing Activities for additional information relating to the Registrant Subsidiaries’ long-term debt outstanding as of December 31, 2025, the weighted-average interest rate applicable to each debt category and a schedule of debt maturities over the next five years.

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Other Significant Cash Requirements

Operating and finance leases represent a significant component of funding requirements for AEP and the Registrant Subsidiaries. See Note 13 - Leases for additional information.

AEP subsidiaries have substantial commitments for fuel, energy and capacity contracts as part of the normal course of business. See Note 6 - Commitments, Guarantees and Contingencies for additional information.

As of December 31, 2025, AEP expected to make contributions to the pension plans totaling $83 million in 2026. Estimated contributions of $84 million in 2027 and $85 million in 2028 may vary significantly based on market returns, changes in actuarial assumptions and other factors. Based upon the projected benefit obligation and fair value of assets available to pay pension benefits, the pension plans were 98% funded as of December 31, 2025. See “Estimated Future Benefit Payments and Contributions” section of Note 8 for additional information.

Standby letters of credit are entered into with third-parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt security reserves. There is no collateral held in relation to any guarantees in excess of the ownership percentages. In the event any letters of credit are drawn, there is no recourse to third-parties. See “Letters of Credit” section of Note 6 for additional information.

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

	December 31,
	2025				2024
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	47,322	58.4	%	$	42,643	59.1	%
Short-term Debt	1,508		1.9		2,524		3.5
Total Debt	48,830		60.3		45,167		62.6
AEP Common Equity	31,138		38.4		26,944		37.3
Noncontrolling Interests	1,080		1.3		42		0.1
Total Debt and Equity Capitalization	$	81,048	100.0	%	$	72,153	100.0	%

AEP’s ratio of debt-to-total capital decreased from 62.6% to 60.3% as of December 31, 2024 and December 31, 2025, respectively, primarily due to an increase in earnings and the Midwest Transmission Holdings Noncontrolling Interest transaction, partially offset by an increase in long-term debt to support AEP’s capital investment plan in addition to working capital needs.

Liquidity

Liquidity, or access to cash, is an important factor in determining AEP’s financial stability.  Management believes AEP has adequate liquidity for the next twelve months and for the foreseeable future. As of December 31, 2025, AEP had $6 billion in revolving credit facilities to support its commercial paper program. Additional liquidity is available from cash from operations and a receivables securitization agreement.  Management is committed to maintaining adequate liquidity.  AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged. Sources of long-term funding include issuance of long-term debt, long-term asset securitizations, leasing agreements, hybrid securities or common stock. AEP and its utilities finance its operations with commercial paper and other variable rate instruments that are subject to fluctuations in interest rates. To the extent that there is an increase in interest rates, it could reduce future net income and cash flows and impact financial condition. In addition, market volatility and reduced liquidity in the financial markets could affect AEP’s ability to raise capital on reasonable terms to fund capital needs, including construction costs and refinancing maturing indebtedness.

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Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments.  As of December 31, 2025, available liquidity was approximately $5.6 billion as illustrated in the table below:

	Amount		Maturity (a)
	(in millions)
Commercial Paper Backup:
Revolving Credit Facility	$	5,000	March 2029
Revolving Credit Facility	1,000		March 2027
Cash and Cash Equivalents	197
Total Liquidity Sources	6,197
Less: AEP Commercial Paper Outstanding	605
Net Available Liquidity	$	5,592

AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries.  The program funds a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and the short-term debt requirements of subsidiaries that are not participating in either money pool for regulatory or operational reasons, as direct borrowers.  The maximum amount of commercial paper outstanding during 2025 was $2.9 billion.  The average amount of commercial paper outstanding during 2025 was $1.4 billion. The weighted-average yield for AEP’s commercial paper during 2025 was 4.47%.

Other Credit Facilities

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. As of December 31, 2025, AEP issues letters of credit on behalf of subsidiaries under six uncommitted facilities totaling $450 million.  The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of December 31, 2025 was $377 million with maturities ranging from January 2026 to November 2026.

Financing Plan

As of December 31, 2025, AEP had $3.2 billion of long-term debt due within one year. This included $1.6 billion of Senior Unsecured Notes, $1.1 billion of Term Loans, $240 million of Pollution Control Bonds with mandatory tender dates and credit support for variable interest rates that require the debt to be classified as current and $204 million of securitization bonds and DCC Fuel notes. Management plans to replace or refinance substantially all of the maturities due within one year on a long-term basis.

Securitized Accounts Receivables

AEP Credit’s receivables securitization agreement provides a commitment of $900 million from bank conduits to purchase receivables and expires in September 2027. As of December 31, 2025, the affiliated utility subsidiaries were in compliance with all requirements under the agreement.

Debt Covenants and Borrowing Limitations

AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%.  The method for calculating outstanding debt and capitalization is contractually-defined in AEP’s credit agreements.  Debt as defined in the revolving credit agreement excludes securitization bonds and debt of AEP Credit. As of December 31, 2025, this contractually-defined percentage was 54.7%. Non-performance under these covenants could result in an event of default under these credit agreements.  In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of AEP’s major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $100 million, would cause an event of default under these credit agreements.  This condition also applies, at the more restrictive level of $50 million of debt outstanding, in a majority of AEP’s non-exchange-traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable.  However, a default under AEP’s non-exchange-traded commodity contracts would not cause an event of default under its credit agreements.

The revolving credit facilities do not permit the lenders to refuse a draw on any facility if a material adverse change occurs.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders and AEP manages its borrowings to stay within those authorized limits.

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March 2025 Forward Sale of Equity

See “Forward Sale of Equity” section of Note 15 for additional information regarding AEP’s forward sale of 22,549,020 shares of common stock in March 2025.

ATM Program

AEP participates in an ATM offering program that allows AEP to issue, from time to time, shares of its common stock, including shares of common stock that may be sold pursuant to an equity forward sales agreement. As of December 31, 2025, approximately $3.5 billion of equity is available for issuance under the ATM offering program. See “ATM Program” section of Note 15 - Financing Activities for additional information.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.95 per share in January 2026.  Future dividends may vary depending upon AEP’s profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. Management does not believe these restrictions will have any significant impact on its ability to access cash to meet the payment of dividends on its common stock. See “Dividend Restrictions” section of Note 15 for additional information.

Credit Ratings

AEP and its utility subsidiaries do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade, but its access to the commercial paper market may depend on its credit ratings.  In addition, downgrades in AEP’s credit ratings by one of the rating agencies could increase its borrowing costs.  Counterparty concerns about the credit quality of AEP or its utility subsidiaries could subject AEP to additional collateral demands under adequate assurance clauses under its derivative and non-derivative energy contracts.

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CASH FLOW

AEP relies primarily on cash flows from operations, debt issuances, issuances of common stock and its existing cash and cash equivalents to fund its liquidity and investing activities. AEP’s investing and capital requirements are primarily capital expenditures, repaying of long-term debt and paying dividends to shareholders. AEP uses short-term debt, including commercial paper and bank term loans, as a bridge to long-term debt financing. The levels of borrowing may vary significantly due to the timing of long-term debt financings and the impact of fluctuations in cash flows.

	Years Ended December 31,
	2025		2024		2023
	(in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	$	246	$	379	$	557
Net Cash Flows from Operating Activities	6,944		6,804		5,012
Net Cash Flows Used for Investing Activities	(11,939)		(7,596)		(6,267)
Net Cash Flows from Financing Activities	5,017		659		1,077
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	22		(133)		(178)
Cash, Cash Equivalents and Restricted Cash at End of Period	$	268	$	246	$	379

Operating Activities

	Years Ended December 31,
	2025		2024		2023
	(in millions)
Net Income	$	3,696	$	2,976	$	2,213
Non-Cash Adjustments to Net Income (a)	3,621		3,383		3,376
Mark-to-Market of Risk Management Contracts	(116)		(81)		9
Pension Contributions to Qualified Plan Trust	(95)		—		—
Property Taxes	(42)		(45)		(41)
Deferred Fuel Over/Under Recovery, Net	133		277		893
Change in Other Noncurrent Assets (b)	(863)		(522)		(762)
Change in Other Noncurrent Liabilities	269		306		29
Change in Certain Components of Working Capital	341		510		(705)
Net Cash Flows from Operating Activities	$	6,944	$	6,804	$	5,012

(a)Includes Depreciation and Amortization, Deferred Income Taxes, Loss on the Sale of the Competitive Contracted Renewables Portfolio, Asset Impairments and Other Related Charges, Allowance for Equity Funds Used During Construction and Amortization of Nuclear Fuel.

(b)Includes Change in Regulatory Assets.

2025 Compared to 2024

Net Cash Flows from Operating Activities increased by $140 million primarily due to the following:

•A $958 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.

This increase in cash was partially offset by:

•A $341 million decrease in cash from Change in Other Noncurrent Assets primarily due to timing differences in collections from customers under rate rider mechanisms, including storm restoration expenses incurred in several jurisdictions. See Note 4 - Rate Matters and Note 5 - Effects of Regulation for additional information.

•A $169 million decrease in cash from the Change in Certain Components of Working Capital primarily due to an increase in fuel, material and supplies driven by higher coal inventory on hand, the timing of accounts receivable collections and changes in income tax payments and tax credits. These decreases were partially offset by the timing of accounts payable, employee-related benefits, proceeds received from the sale of transferable tax credits and increased margin deposits driven by increases in power prices.

•A $144 million decrease in cash primarily due to the timing of fuel and purchased power revenues and expenses.

•A $95 million decrease in cash due to a discretionary contribution to the qualified pension plan. See Note 8 - Benefit Plans for additional information.

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Investing Activities

	Years Ended December 31,
	2025		2024		2023
	(in millions)
Construction Expenditures	$	(8,453)	$	(7,631)	$	(7,378)
Acquisitions of Nuclear Fuel	(130)		(140)		(128)
Acquisitions of Generation Facilities	(3,453)		(399)		(155)
Proceeds from Sales of Assets	25		362		1,341
Proceeds from Sale of Equity Method Investment	—		114		—
Other	72		98		53
Net Cash Flows Used for Investing Activities	$	(11,939)	$	(7,596)	$	(6,267)

2025 Compared to 2024

Net Cash Flows Used for Investing Activities increased by $4.3 billion primarily due to the following:

•A $3.1 billion increase in Acquisitions of Generation Facilities.

•An $822 million increase in Construction Expenditures primarily due to increases in Vertically Integrated Utilities of $636 million and Transmission and Distribution Utilities of $634 million partially offset by decreases in Corporate and Other of $429 million driven by expenditures for fuel cell generation assets in 2024.

•A $337 million decrease in Proceeds from Sale of Assets primarily due to the sale of AEP OnSite Partners in 2024.

•A $114 million decrease in Proceeds from the Sale of AEP’s Equity Investment in NMRD.

See Note 7 - Acquisitions, Dispositions and Impairments for additional information.

Financing Activities

	Years Ended December 31,
	2025		2024		2023
	(in millions)
Issuance of Common Stock	$	775	$	552	$	1,000
Issuance/Retirement of Debt, Net	3,596		2,126		1,985
Principal Payments for Finance Lease Obligations	(51)		(65)		(68)
Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs	2,783		—		—
Dividends Paid on Common Stock	(2,008)		(1,898)		(1,752)
Other	(78)		(56)		(88)
Net Cash Flows from Financing Activities	$	5,017	$	659	$	1,077

2025 Compared to 2024

Net Cash Flows from Financing Activities increased by $4.4 billion primarily due to the following:

•A $3.1 billion increase in issuances of long-term debt.

•A $2.8 billion increase due to proceeds from the Midwest Transmission Holdings Noncontrolling Interest transaction. See “Noncontrolling Interest in Midwest Transmission Holdings” section of Note 7 for additional information.

These increases in cash were partially offset by:

•A $964 million increase in retirements of long-term debt.

•A $710 million decrease due to changes in short-term debt.

The following financing activities occurred during 2025:

AEP Common Stock:

•During 2025, AEP issued 8 million shares of common stock under the Forward Sale of Equity, ATM offering program, incentive compensation, employee saving and dividend reinvestment plans. See “Common Stock” section of Note 15 for additional information. AEP received net proceeds of $775 million related to these issuances.

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Debt:

•During 2025, AEP issued approximately $8.3 billion of long-term debt, including $3 billion of junior subordinated notes at interest rates ranging from 5.80% to 6.05%, $2.2 billion of other debt at various interest rates, $2.1 billion of senior unsecured notes at interest rates ranging from 5.38% to 5.85%, $478 million of securitization bonds at an interest rate of 5.30%, $320 million of pollution control bonds at interest rates ranging from 3.30% to 3.70% and $203 million of notes payable at various interest rates.

•During 2025, settlements of AEP’s interest rate derivatives resulted in net cash paid of $40 million for derivatives designated as fair value hedges.  As of December 31, 2025, AEP had a total notional amount of $500 million of outstanding interest rate derivatives designated as fair value hedges.

See “Financing Activities Subsequent Events” section of Note 15 for Long-term debt and other securities issued, retired and principal payments made after December 31, 2025 through February 12, 2026, the date that the 10-K was issued.

BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately $12.2 billion of capital expenditures in 2026.  For the four-year period, 2027 through 2030, management forecasts capital expenditures of $59.7 billion. Management’s forecasted capital expenditures reflect planned investments for transmission infrastructure and new generation resources to support existing customers and forecasted large load increases and continued improvements in distribution system reliability.

Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, supply chain issues, weather, legal reviews, technology advancements, inflation and the ability to access capital.  Management has funded, or expects to fund, these capital expenditures through cash flows from operations and financing activities.  Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged. The estimated capital expenditures by Business Segment are as follows:

	2026 Budgeted Capital Expenditures														2027-2030
Segment	Environmental		Generation		Renewables		Transmission		Distribution		Other (a)		Total		Total
	(in millions)
VIU	$	97	$	2,144	$	1,173	$	1,187	$	1,733	$	364	$	6,698	$	30,457
T&D	—		—		—		1,576		1,683		295		3,554		18,983
AEPTHCo	—		—		—		1,454		—		32		1,486		9,122
G&M	—		—		—		—		—		21		21		91
Corporate and Other	—		117		—		—		—		355		472		1,082
Total	$	97	$	2,261	$	1,173	$	4,217	$	3,416	$	1,067	$	12,231	$	59,735

(a)Amount primarily consists of facilities, software and telecommunications.

The 2026 estimated capital expenditures by Registrant Subsidiary are as follows:

	2026 Budgeted Capital Expenditures
Company	Environmental		Generation		Renewables		Transmission		Distribution		Other (a)		Total
	(in millions)
AEP Texas	$	—	$	—	$	—	$	1,208	$	949	$	194	$	2,351
AEPTCo	—		—		—		1,326		—		29		1,355
APCo	58		158		387		358		449		107		1,517
I&M	3		1,237		4		160		362		66		1,832
OPCo	—		—		—		368		734		101		1,203
PSO	4		305		738		172		412		66		1,697
SWEPCo	17		361		44		360		323		106		1,211

(a) Amount primarily consists of facilities, software and telecommunications.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING STANDARDS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect reported amounts and related disclosures, including amounts related to legal matters and contingencies.  Management considers an accounting estimate to be critical if:

•It requires assumptions to be made that were uncertain at the time the estimate was made; and

•Changes in the estimate or different estimates that could have been selected could have a material effect on net income or financial condition.

Management discusses the development and selection of critical accounting estimates as presented below with the Audit Committee of AEP’s Board of Directors and the Audit Committee reviews the disclosures relating to them.

Management believes that the current assumptions and other considerations used to estimate amounts reflected in the financial statements are appropriate.  However, actual results can differ significantly from those estimates.

The sections that follow present information about critical accounting estimates, as well as the effects of hypothetical changes in the material assumptions used to develop each estimate.

Regulatory Accounting

Nature of Estimates Required

The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated.

The Registrants recognize regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) for the economic effects of regulation.  Specifically, the timing of expense and income recognition is matched with regulated revenues.  Liabilities are also recorded for refunds, or probable refunds, to customers that have not been made.

Assumptions and Approach Used

When incurred costs are probable of recovery through regulated rates, regulatory assets are recorded on the balance sheets.  Management reviews the probability of recovery at each balance sheet date and whenever new events occur.  Similarly, regulatory liabilities are recorded when a determination is made that a refund is probable or when ordered by a commission.  Examples of new events that affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation.  The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs as well as the return of revenues, rate of return earned on invested capital and timing and amount of assets to be recovered through regulated rates.  If recovery of a regulatory asset is no longer probable, that regulatory asset is written-off as a charge against earnings.  A write-off of regulatory assets or establishment of a regulatory liability may also reduce future cash flows since there will be no recovery through regulated rates.

Effect if Different Assumptions Used

A change in the above assumptions may result in a material impact on net income.  See Note 5 - Effects of Regulation for additional information related to regulatory assets and regulatory liabilities.

Revenue Recognition – Unbilled Revenues

Nature of Estimates Required

AEP recognizes revenues from customers as the performance obligations of delivering energy to customers are satisfied.  The determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue accrual is recorded.  This estimate is reversed in the following month and actual revenue is recorded based on meter readings.  PSO and SWEPCo do not include the fuel portion in unbilled revenue in accordance with the applicable state commission regulatory treatment in Arkansas, Louisiana, Oklahoma and Texas.

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Accrued unbilled revenues for the Vertically Integrated Utilities segment were $387 million and $351 million as of December 31, 2025 and 2024, respectively. The changes in unbilled electric utility revenues for AEP’s Vertically Integrated Utilities segment were $36 million, $63 million and $(66) million for the years ended December 31, 2025, 2024 and 2023, respectively.  The changes in unbilled electric revenues are primarily due to changes in weather, rates and usage.  

Accrued unbilled revenues for the Transmission and Distribution Utilities segment were $206 million and $199 million as of December 31, 2025 and 2024, respectively. The changes in unbilled electric utility revenues for AEP’s Transmission and Distribution Utilities segment were $7 million, $8 million and $(30) million for the years ended December 31, 2025, 2024 and 2023, respectively.  The changes in unbilled electric revenues are primarily due to changes in weather, rates and usage.  

Accrued unbilled revenues for the Generation & Marketing segment were $159 million and $121 million as of December 31, 2025 and 2024, respectively. The changes in unbilled electric utility revenues for AEP’s Generation & Marketing segment were $38 million, $10 million and $2 million for the years ended December 31, 2025, 2024 and 2023, respectively.  

Assumptions and Approach Used

For each Registrant except AEPTCo, the monthly estimate for unbilled revenues is based upon a primary computation of net generation (generation plus purchases less sales) less the current month’s billed KWhs and estimated line losses, plus the prior month’s unbilled KWhs. However, due to the potential for meter reading issues, meter drift and other anomalies, a secondary computation is made, based upon an allocation of billed KWhs to the current month and previous month, on a billing cycle-by-cycle basis, and by dividing the current month aggregated result by the billed KWhs. The two methodologies are evaluated to confirm that they are not statistically different.

For AEP’s Generation & Marketing segment, management calculates unbilled revenues based on a primary computation of load as provided by PJM less the current month’s billed KWhs and estimated line losses, plus the prior month’s unbilled KWhs. However, due to the potential for meter reading issues, meter drift and other anomalies, a secondary computation is made, based upon using the most recent historic daily activity on a per contract basis. The two methodologies are evaluated to confirm that they are not statistically different.

Effect if Different Assumptions Used

For each Registrant except AEPTCo, if the two methodologies used to estimate unbilled revenue are statistically different, a limiter adjustment is made to bring the primary computation within one standard deviation of the secondary computation.

Additionally, significant fluctuations in energy demand for the unbilled period, weather, line losses or changes in the composition of customer classes could impact the estimate of unbilled revenue.

Accounting for Derivative Instruments

Nature of Estimates Required

Management considers fair value techniques, valuation adjustments related to credit and liquidity and judgments related to the probability of forecasted transactions occurring within the specified time period to be critical accounting estimates.  These estimates are considered significant because they are highly susceptible to change from period to period and are dependent on many subjective factors.

Assumptions and Approach Used

The Registrants measure the fair values of derivative instruments and hedge instruments accounted for using MTM accounting based primarily on exchange prices and broker quotes.  If a quoted market price is not available, the fair value is estimated based on the best market information available including valuation models that estimate future energy prices based on existing market and broker quotes and other assumptions.  Fair value estimates, based upon the best market information available, involve uncertainties and matters of significant judgment.  These uncertainties include forward market price assumptions.

The Registrants reduce fair values by estimated valuation adjustments for items such as discounting, liquidity and credit quality.  Liquidity adjustments are calculated by utilizing bid/ask spreads to estimate the potential fair value impact of liquidating open positions over a reasonable period of time.  Credit adjustments on risk management contracts are calculated using estimated default probabilities and recovery rates relative to the counterparties or counterparties with similar credit profiles and contractual netting agreements.

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With respect to hedge accounting, management assesses hedge effectiveness and evaluates a forecasted transaction’s probability of occurrence within the specified time period as provided in the original hedge documentation.

Effect if Different Assumptions Used

There is inherent risk in valuation modeling given the complexity and volatility of energy markets.  Therefore, it is possible that results in future periods may be materially different as contracts settle.

The probability that hedged forecasted transactions will not occur by the end of the specified time period could change operating results by requiring amounts currently classified in Accumulated Other Comprehensive Income (Loss) to be classified into Operating Income.

For additional information see Note 10 - Derivatives and Hedging and Note 11 - Fair Value Measurements.  See “Fair Value Measurements of Assets and Liabilities” section of Note 1 for AEP’s fair value calculation policy.

Long-Lived Assets

Nature of Estimates Required

In accordance with the requirements of “Property, Plant and Equipment” accounting guidance and “Regulated Operations” accounting guidance, the Registrants evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such assets may not be recoverable. Such events or changes in circumstance include planned abandonments, probable disallowances for ratemaking purposes of assets determined to be recently completed plant and assets that meet the held-for-sale criteria.  The Registrants utilize a group composite method of depreciation to estimate the useful lives of long-lived assets.  

An impairment evaluation of a long-lived, held and used asset may result from an abandonment, significant decreases in the market price of an asset, a significant adverse change in the extent or manner in which an asset is being used or in its physical condition, a significant adverse change in legal factors or in the business climate that could affect the value of an asset, as well as other economic or operations analyses.  If the book value of the asset is not recoverable through estimated, future undiscounted cash flows, the Registrants record an impairment to the extent that the fair value of the asset is less than its book value.  Performing an impairment evaluation involves a significant degree of estimation and judgment in areas such as identifying circumstances that indicate an impairment may exist, identifying and grouping affected assets and developing the non-discounted and discounted future cash flows (used to estimate fair value in the absence of market-based value, in some instances) associated with the asset.  Assets held for sale must be measured at the lower of the book value or fair value less cost to sell. An impairment is recognized if an asset’s fair value less costs to sell is less than its book value. Any impairment charge is recorded as a reduction to earnings.

Assumptions and Approach Used

The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties other than in a forced or liquidation sale.  Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available.  In the absence of quoted prices for identical or similar assets in active markets, the Registrants estimate fair value using various internal and external valuation methods including cash flow projections or other market indicators of fair value such as bids received, comparable sales or independent appraisals.  Cash flow estimates are based on relevant information available at the time the estimates are made.  Estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.  Also, when measuring fair value, management evaluates the characteristics of the asset or liability to determine if market participants would take those characteristics into account when pricing the asset or liability at the measurement date.  Such characteristics include, for example, the condition and location of the asset or restrictions on the use of the asset.  The Registrants perform depreciation studies that include a review of any external factors that may affect the useful life to determine composite depreciation rates and related lives which are subject to periodic review by state regulatory commissions for regulated assets.  The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.

Effect if Different Assumptions Used

In connection with the evaluation of long-lived assets in accordance with the requirements of “Property, Plant and Equipment” accounting guidance, the fair value of the asset can vary if different estimates and assumptions are used in the applied valuation techniques.  Estimates for depreciation rates contemplate the history of interim capital replacements and the amount of salvage expected.  In cases of impairment, the best estimate of fair value was made using valuation methods based on the most current

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information at that time.  Differences in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including, but not limited to, differences in subsequent market conditions, the level of bidder interest, the timing and terms of the transactions and management’s analysis of the benefits of the transaction.

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Pension and OPEB

AEPSC maintains a qualified, defined benefit pension plan (Qualified Plan), which covers substantially all nonunion and certain union employees, and unfunded, non-qualified supplemental plans (Nonqualified Plans) to provide benefits in excess of amounts permitted under the provisions of the tax law for participants in the Qualified Plan (collectively the Pension Plans).  AEPSC also sponsors OPEB plans to provide health and life insurance benefits for retired employees.  The Pension Plans and OPEB plans are collectively referred to as the Plans.

For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Investments Held in Trust for Future Liabilities” and “Fair Value Measurements of Assets and Liabilities” sections of Note 1.  See Note 8 - Benefit Plans for information regarding costs and assumptions for the Plans.

The following table shows the net periodic cost (credit) of the Plans:

	Years Ended December 31,
Net Periodic Cost (Credit)	2025		2024		2023
	(in millions)
Pension Plans	$	42	$	86	$	(24)
OPEB	(78)		(71)		(107)

The net periodic benefit cost is calculated based upon a number of actuarial assumptions, including expected long-term rates of return on the Plans’ assets.  In developing the expected long-term rate of return assumption for 2026, management evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions.  Management also considered historical returns of the investment markets and tax rates which affect a portion of the OPEB plans’ assets.  Management anticipates that the investment managers employed for the Plans will invest the assets to generate future returns averaging 6.75% for the Qualified Plan and 6% for the OPEB plans.

The expected long-term rate of return on the Plans’ assets is based on management’s targeted asset allocation and expected investment returns for each investment category.  Assumptions for the Plans are summarized in the following table:

	Pension Plans				OPEB
			Assumed/Expected				Assumed/Expected
	2026 Target		Long-Term		2026 Target		Long-Term
	Asset Allocation		Rate of Return		Asset Allocation		Rate of Return
Equity	35	%	8.50	%	63	%	7.52	%
Fixed Income	49	%	5.31	%	36	%	4.56	%
Other Investments	15	%	8.78	%	—		—
Cash and Cash Equivalents	1	%	3.00	%	1	%	3.00	%
Total	100	%			100	%

Management regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation.  Management believes that 6.75% for the Qualified Plan and 6% for the OPEB plans are reasonable estimates of the long-term rate of return on the Plans’ assets.  The Pension Plans’ assets had an actual gain of 10.52% and an actual gain of 2.59% for the years ended December 31, 2025 and 2024, respectively.  The OPEB plans’ assets had an actual gain of 14.72% and an actual gain of 8.98% for the years ended December 31, 2025 and 2024, respectively.  Management will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the assumptions as necessary.

AEP bases the determination of pension expense or income on a market-related valuation of assets, which reduces year-to-year volatility.  This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets.  Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.  As of December 31, 2025, AEP had cumulative losses of approximately $196 million for the Qualified Plan that remain to be recognized in the calculation of the market-related value of assets.  These unrecognized market-related net actuarial losses may result in increases in the future pension costs depending on several factors, including whether such losses at each measurement date exceed the corridor in accordance with “Compensation – Retirement Benefits” accounting guidance.

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The method used to determine the discount rate that AEP utilizes for determining future obligations is a duration-based method in which a hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability.  The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.  The discount rate as of December 31, 2025 under this method was 5.5% for the Qualified Plan, 5.3% for the Nonqualified Plans and 5.5% for the OPEB plans.  Due to the effect of the unrecognized net actuarial losses and based on an expected rate of return, discount rates and various other assumptions, management estimates costs (credits) for the Pension Plans will approximate $87 million, $139 million and $142 million in 2026, 2027 and 2028, respectively.  Based on an expected rate of return discount rate and various other assumptions, management estimates OPEB plan credits will approximate $90 million, $85 million and $91 million in 2026, 2027 and 2028, respectively. Future actual costs will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Plans.  The actuarial assumptions used may differ materially from actual results.  The effects of a 50 basis point change to selective actuarial assumptions are included in the “Effect if Different Assumptions Used” section below.

The value of AEP’s Pension Plans’ assets is $3.8 billion as of December 31, 2025 and $3.7 billion as of December 31, 2024.  During 2025, the Qualified Plan paid $374 million and the Nonqualified Plans paid $8 million in benefits to plan participants.  The value of AEP’s OPEB plans’ assets increased to $2.0 billion as of December 31, 2025 from $1.8 billion as of December 31, 2024 primarily due to positive investment returns. During 2025, the OPEB plans paid $105 million in benefits to plan participants.

Nature of Estimates Required

AEPSC sponsors pension and OPEB plans in various forms covering all employees who meet eligibility requirements.  These benefits are accounted for under “Compensation” and “Plan Accounting” accounting guidance.  The measurement of pension and OPEB obligations, costs and liabilities is dependent on a variety of assumptions.

Assumptions and Approach Used

The critical assumptions used in developing the required estimates includes discount rate, compensation increase rate, cash balance crediting rate, health care cost trend rate and expected return on plan assets. Other assumptions, such as retirement, mortality and turnover, are evaluated periodically and updated to reflect actual experience.

Effect if Different Assumptions Used

The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, longer or shorter life spans of participants or higher or lower lump sum versus annuity payout elections by plan participants.  These differences may result in a significant impact to the amount of pension and OPEB expense recorded.  If a 50 basis point change were to occur for the following assumptions, the approximate effect on the financial statements would be as follows:

	Pension Plans				OPEB
	+0.5%		-0.5%		+0.5%		-0.5%
	(in millions)
Effect on December 31, 2025 Benefit Obligations
Discount Rate	$	(164)	$	179	$	(23)	$	25
Compensation Increase Rate	23		(22)		NA		NA
Cash Balance Crediting Rate	48		(45)		NA		NA
Health Care Cost Trend Rate	NA		NA		5		(5)
Effect on 2025 Periodic Cost
Discount Rate	$	(9)	$	10	$	(1)	$	1
Compensation Increase Rate	6		(5)		NA		NA
Cash Balance Crediting Rate	11		(10)		NA		NA
Health Care Cost Trend Rate	NA		NA		1		(1)
Expected Return on Plan Assets	(20)		20		(9)		9

NA    Not applicable.

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Asset Retirement Obligations – Impact of the 2024 CCR Rule

Nature of Estimates Required

In April 2024, the Federal EPA finalized revisions to the CCR Rule to expand the scope of the rule to include inactive impoundments at inactive facilities as well as to establish requirements for currently exempt solid waste management units that involve the direct placement of CCR on the land. Accounting for the incremental asset retirement obligation arising from the revised CCR Rule requires significant judgment by management due to the significant measurement uncertainty in estimating the incremental liability. As a result of the rule, AEP recorded an incremental ARO of $674 million in the second quarter of 2024.

Assumptions and Approach Used

AROs are computed as the present value of the estimated costs associated with the future retirement of an asset and are recorded in the period in which the liability is incurred. Projections of the timing and amounts of future cash outlays are based on estimation of the extent and quantity of coal ash present at sites, projections of the when and how the liabilities will be remediated as well as the rate at which costs will escalate over time and discount rate, which may change significantly over time.

Effect if Different Assumptions Used

As further groundwater monitoring and other analysis is performed, management expects to refine the assumptions and underlying cost estimates used in recording the incremental asset retirement obligation arising from the revised CCR Rule. The estimated liability can significantly change if there are changes in the impacted coal ash site acreage inputs or if refinements in the assumptions over the remediation costs for legacy CCR surface impoundments and CCR management units, including assumptions over future groundwater monitoring requirements vary from the initial estimates. These future changes could have a material impact on the ARO and materially reduce future net income, cash flows and financial condition if AEP cannot ultimately recover these additional costs of compliance. See Note 6 – Commitments, Guarantees and Contingencies and Note 19 – Property, Plant and Equipment for additional information related to AROs and the CCR Rule.

ACCOUNTING STANDARDS

See Note 2 - New Accounting Standards for information related to accounting standards and SEC rulemaking activity.

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

Market risk evaluations are subject to certain limitations that may prevent a full reflection of the net market risk exposure. These limitations primarily relate to model and data constraints that rely on hypothetical assumptions and may not capture all potential future market conditions. These include the use of historical information, assumptions about market volatility and correlations, and dependence on observable inputs that may not be available for less liquid positions. As a result, the actual impact of market movements could differ from the estimates presented.

The Vertically Integrated Utilities segment is exposed to certain market risks as a major power producer and through transactions in power, coal, natural gas and marketing contracts. These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk. These risks represent the risk of loss that may impact this segment due to changes in the underlying market prices or rates.

The Transmission and Distribution Utilities segment is exposed to energy procurement risk and interest rate risk.

The Generation & Marketing segment conducts marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. This segment is exposed to certain market risks as a marketer of wholesale and retail electricity. These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk. These risks represent the risk of loss that may impact this segment due to changes in the underlying market prices or rates. In addition, the Generation & Marketing segment is also exposed to certain market risks as a power producer and through transactions in wholesale electricity, natural gas and marketing contracts.

Management employs risk management contracts including physical forward and financial forward purchase-and-sale contracts.  Management engages in risk management of power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business.  As a result, AEP is subject to price risk.  The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the AEP Board.  AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Regulated Risk Committee and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures.  The Regulated Risk Committee consists of AEPSC’s Chief Financial Officer, Executive Vice President and Chief Commercial Officer, Senior Vice President and Treasurer, Senior Vice President of Regulated Commercial Operations, President AEP Transmission, and Senior Vice President Finance. The Competitive Risk Committee consists of AEPSC’s Chief Financial Officer, Executive Vice President and Chief Commercial Officer, Senior Vice President and Treasurer, and Senior Vice President of Competitive Commercial Operations.  If commercial activities result in predetermined limits being exceeded, positions are modified to reduce the risk to be within the limits unless specifically approved by the respective committee.

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The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2024:

MTM Derivative Contract Net Assets (Liabilities)
Year Ended December 31, 2025
	Vertically Integrated Utilities		Transmission and Distribution Utilities		Generation & Marketing		Total
	(in millions)
Total MTM Risk Management Contracts - Commodity Net Assets (Liabilities) as of December 31, 2024	$	92	$	(48)	$	162	$	206
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period	(79)		2		(39)		(116)
Fair Value of New Contracts at Inception When Entered During the Period (a)	—		—		12		12
Changes in Fair Value Due to Market Fluctuations During the Period (b)	(10)		—		73		63
Changes in Fair Value Allocated to Regulated Jurisdictions (c)	140		13		—		153
Total MTM Risk Management Contracts - Commodity Net Assets (Liabilities) as of December 31, 2025	$	143	$	(33)	$	208	$	318
Commodity Cash Flow Hedge Contracts							98
Fair Value Hedge Contracts							(29)
Collateral Deposits							(80)
Total MTM Derivative Contract Net Assets as of December 31, 2025							$	307

(a)Reflects fair value on primarily auctions or long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  The contract prices are valued against market curves associated with the delivery location and delivery term.  A significant portion of the total volumetric position has been economically hedged.

(b)Market fluctuations are attributable to various factors such as supply/demand, weather, etc.

(c)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income.  These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable on the balance sheet.

See Note 10 – Derivatives and Hedging and Note 11 – Fair Value Measurements for additional information related to risk management contracts.  The following tables and discussion provide information on credit risk and market volatility risk.

Credit Risk

Credit risk is mitigated in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.  Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

AEP has risk management contracts (including non-derivative contracts) with numerous counterparties.  Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily.  As of December 31, 2025, credit exposure net of collateral to sub-investment grade counterparties was approximately 10.6%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss). 

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As of December 31, 2025, the following table approximates AEP’s counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:

Counterparty Credit Quality	Exposure Before Credit Collateral		Credit Collateral		Net Exposure		Number of Counterparties >10% of Net Exposure	Net Exposure of Counterparties >10%
	(in millions, except number of counterparties)
Investment Grade	$	564	$	76	$	488	3	$	301
Non-investment Grade	5		1		4		2	4
No External Ratings:
Internal Investment Grade	18		—		18		3	12
Internal Non-investment Grade	126		70		56		2	48
Total as of December 31, 2025	$	713	$	147	$	566

All exposure in the table above relates to AEPSC and AEPEP as AEPSC is agent for and transacts on behalf of certain AEP subsidiaries, including the Registrant Subsidiaries and AEPEP is agent for, and transacts on behalf of, other AEP subsidiaries.

In addition, AEP is exposed to credit risk related to participation in RTOs.  For each of the RTOs in which AEP participates, this risk is generally determined based on the proportionate share of member gross activity over a specified period of time.

Value at Risk (VaR) Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates VaR, to measure AEP’s commodity price risk in the risk management portfolio.  The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, as of December 31, 2025, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.

Management calculates the VaR for both a trading and non-trading portfolio. The trading portfolio consists primarily of contracts related to energy trading and marketing activities. The non-trading portfolio consists primarily of economic hedges of generation and retail supply activities.

The following tables show the end, high, average and low market risk as measured by VaR for the periods indicated:

VaR Model

Trading Portfolio

Twelve Months Ended								Twelve Months Ended
December 31, 2025								December 31, 2024
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	—	$	1	$	—	$	—	$	—	$	2	$	—	$	—

VaR Model

Non-Trading Portfolio

Twelve Months Ended								Twelve Months Ended
December 31, 2025								December 31, 2024
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	4	$	29	$	8	$	2	$	38	$	99	$	19	$	8

Management back-tests VaR results against performance due to actual price movements.  Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.

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As the VaR calculation captures recent price movements, management also performs regular stress testing of the trading portfolio to understand AEP’s exposure to extreme price movements.  A historical-based method is employed whereby the current trading portfolio is subjected to actual, observed price movements from the last several years in order to ascertain which historical price movements translated into the largest potential MTM loss.  Management then researches the underlying positions, price movements and market events that created the most significant exposure and reports the findings to the Risk Executive Committee, Regulated Risk Committee or Competitive Risk Committee as appropriate.

Interest Rate Risk

AEP is exposed to interest rate market fluctuations in the normal course of business operations. Prior to 2022, interest rates remained at low levels and the Federal Reserve maintained the federal funds target range at 0.0% to 0.25% for much of 2021. During 2022 and 2023, the Federal Reserve approved 11 rate increases for a total cumulative increase of 5.25%. In light of the progress on inflation and the balance of risks, the Federal Reserve authorized three rate cuts in 2024, totaling a cumulative decrease of 1.0%. In 2025, the Federal Reserve authorized three additional interest rate cuts, totaling a cumulative 0.75%. AEP has outstanding short and long-term debt which is subject to variable rates. AEP manages interest rate risk by limiting variable-rate exposures to a percentage of total debt, by entering into interest rate derivative instruments and by monitoring the effects of market changes on interest rates. For the twelve months ended December 31, 2025, 2024 and 2023, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense annually by $36 million, $33 million and $40 million, respectively.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

American Electric Power Company, Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of American Electric Power Company, Inc. and its subsidiaries (the “Company”) as of December 31, 2025 and 2024, and the related consolidated statements of income, of comprehensive income (loss), of changes in equity and of cash flows for each of the three years in the period ended December 31, 2025, including the related notes and financial statement schedules listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). We also have audited the 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of the 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, the 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 the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated 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 Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the 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 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. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated 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 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. 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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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.

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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 Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate 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 critical audit matters 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Accounting for the Effects of Cost-Based Regulation

As described in Notes 1 and 5 to the consolidated financial statements, the Company's consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. As of December 31, 2025, there were $5,230 million of deferred costs included in regulatory assets, $1,307 million of which were pending final regulatory approval, and $8,426 million of regulatory liabilities awaiting potential refund or future rate reduction, $119 million of which were pending final regulatory determination. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation.

The principal considerations for our determination that performing procedures relating to the accounting for the effects of cost-based regulation is a critical audit matter are (i) the significant judgment by management in assessing probability of the recovery of regulatory assets and refund of regulatory liabilities and (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the probability of recovery of regulatory assets and refund of regulatory liabilities.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's evaluation of new events, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation, including controls over the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others (i) evaluating the reasonableness of management's assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities; (ii) testing, on a sample basis, the regulatory assets and liabilities, including those subject to pending rate cases and regulatory proceedings, by considering (a) the provisions and formulas outlined in rate orders; (b) other regulatory correspondence; and (c) application of relevant regulatory precedents.

Valuation of Level 3 Energy Contracts

As described in Notes 1, 10 and 11 to the consolidated financial statements, the Company employs risk management commodity contracts including physical and financial forward purchase and sale contracts and, to a lesser extent, over-the-counter swaps and options to accomplish its risk management strategies. Certain over-the-counter and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. As disclosed by management, the fair value of these risk management commodity contracts is estimated based on the best market information available, including valuation models that estimate future energy prices based on existing market and broker quotes, and other assumptions. Fair value estimates, based upon the best market information available, involve uncertainties and matters of significant judgment including forward market price assumptions. Risk management commodity contracts are substantially comprised of energy contracts. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. Management utilized a forward market price assumption to value its level 3 energy contracts. The Company’s level 3 energy contracts assets and liabilities totaled $224 million and $144 million, respectively, as of December 31, 2025.

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The principal considerations for our determination that performing procedures relating to the valuation of Level 3 energy contracts is a critical audit matter are (i) the significant judgment by management when developing the fair value estimate of the level 3 energy contracts; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to management’s significant assumption relating to the forward market price; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's valuation of the level 3 risk management commodity contracts, including energy contracts. These procedures also included, among others (i) testing the completeness and accuracy of the underlying data provided by management; (ii) testing management's process for developing the fair value of the level 3 energy contracts; (iii) evaluating the appropriateness of the valuation models used in developing the fair value estimate of the level 3 energy contracts; and (iv) the involvement of professionals with specialized skill and knowledge to assist in evaluating the reasonableness of the forward market price assumption.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio

February 12, 2026

We have served as the Company’s auditor since 2017.

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of American Electric Power Company, Inc. and Subsidiary Companies (AEP) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.  AEP’s internal control 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.

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.

Management assessed the effectiveness of AEP’s internal control over financial reporting as of December 31, 2025.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013).  Based on management’s assessment, management concluded AEP’s internal control over financial reporting was effective as of December 31, 2025.

PricewaterhouseCoopers LLP, AEP’s independent registered public accounting firm has issued an audit report on the effectiveness of AEP’s internal control over financial reporting as of December 31, 2025.  The Report of Independent Registered Public Accounting Firm appears on the previous page.

95

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF INCOME

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

 (in millions, except per-share and share amounts)

	Years Ended December 31,
	2025		2024		2023
REVENUES
Vertically Integrated Utilities	$	12,556	$	11,414	$	11,304
Transmission and Distribution Utilities	6,097		5,880		5,677
Generation & Marketing	2,697		1,945		1,543
Other Revenues	526		482		458
TOTAL REVENUES	21,876		19,721		18,982
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	7,031		5,936		6,578
Other Operation	2,950		3,127		2,811
Maintenance	1,499		1,325		1,276
Asset Impairments and Other Related Charges	66		143		86
Loss on the Sale of the Competitive Contracted Renewables Portfolio	—		—		93
Depreciation and Amortization	3,380		3,290		3,090
Taxes Other Than Income Taxes	1,631		1,596		1,492
TOTAL EXPENSES	16,557		15,417		15,426
OPERATING INCOME	5,319		4,304		3,556
Other Income (Expense):
Other Income	48		65		64
Allowance for Equity Funds Used During Construction	245		211		175
Non-Service Cost Components of Net Periodic Benefit Cost	138		126		221
Interest Expense	(2,026)		(1,863)		(1,807)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS	3,724		2,843		2,209
Income Tax Expense (Benefit)	129		(39)		55
Equity Earnings of Unconsolidated Subsidiaries	101		94		59
NET INCOME	3,696		2,976		2,213
Net Income Attributable to Noncontrolling Interests	116		9		5
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	3,580	$	2,967	$	2,208
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	534,535,444		530,092,672		518,903,682
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	6.70	$	5.60	$	4.26
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	537,467,865		531,337,703		520,206,258
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	6.66	$	5.58	$	4.24
See Notes to Financial Statements of Registrants beginning on page 182.

96

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

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

(in millions)

	Years Ended December 31,
	2025		2024		2023
Net Income	$	3,696	$	2,976	$	2,213
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $(7), $1 and $(34) in 2025, 2024 and 2023, Respectively	(25)		5		(127)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0, $(1) and $(3) in 2025, 2024 and 2023, Respectively	1		(3)		(13)
Pension and OPEB Funded Status, Net of Tax of $17, $11 and $(4) in 2025, 2024 and 2023, Respectively	63		41		(16)
Recognition of Pension Settlement Costs, Net of Tax of $0, $2, and $0 in 2025, 2024 and 2023, Respectively	—		9		—
Reclassifications of KPCo Pension and OPEB Regulatory Assets, Net of Tax of $0, $0 and $4 in 2025, 2024 and 2023, Respectively	—		—		17
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	39		52		(139)
TOTAL COMPREHENSIVE INCOME	3,735		3,028		2,074
Total Comprehensive Income Attributable To Noncontrolling Interests	116		9		5
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	3,619	$	3,019	$	2,069
See Notes to Financial Statements of Registrants beginning on page 182.

97

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

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

(in millions)

	AEP Common Shareholders
	Common Stock								Accumulated Other Comprehensive Income (Loss)
	Shares	Amount		Paid-in Capital		Retained Earnings					Noncontrolling Interests		Total
TOTAL EQUITY – DECEMBER 31, 2022	525	$	3,413	$	8,051	$	12,346		$	84	$	229	$	24,123
Issuance of Common Stock	2	15		985									1,000
Common Stock Dividends						(1,752)		(a)					(1,752)
Dividends Paid to Noncontrolling Interest											(8)		(8)
Other Changes in Equity				38		(2)					(1)		35
Disposition of Competitive Contracted Renewables Portfolio											(186)		(186)
Net Income						2,208					5		2,213
Other Comprehensive Loss									(139)				(139)
TOTAL EQUITY – DECEMBER 31, 2023	527	3,428		9,074		12,800			(55)		39		25,286
Issuance of Common Stock	7	44		508									552
Common Stock Dividends						(1,898)		(a)					(1,898)
Dividends Paid to Noncontrolling Interest											(6)		(6)
Other Changes in Equity				24									24
Net Income						2,967					9		2,976
Other Comprehensive Income									52				52
TOTAL EQUITY – DECEMBER 31, 2024	534	3,472		9,606		13,869			(3)		42		26,986
Issuance of Common Stock	8	51		724									775
Capital Contribution from Noncontrolling Interest											38		38
Common Stock Dividends						(2,008)		(a)					(2,008)
Dividends Paid to Noncontrolling Interest											(108)		(108)
Other Changes in Equity				17									17
Midwest Transmission Holdings Noncontrolling Interest Transaction				1,791							992		2,783
Net Income						3,580					116		3,696
Other Comprehensive Income									39				39
TOTAL EQUITY – DECEMBER 31, 2025	542	$	3,523	$	12,138	$	15,441		$	36	$	1,080	$	32,218

(a)    Cash dividends declared per AEP common share were $3.74, $3.57 and $3.37 for the years ended December 31, 2025, 2024 and 2023, respectively.

See Notes to Financial Statements of Registrants beginning on page 182.

98

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2025 and 2024

(in millions)

	December 31,
	2025		2024
CURRENT ASSETS
Cash and Cash Equivalents	$	197	$	203
Restricted Cash (December 31, 2025 and 2024 Amounts Include $71 and $43, Respectively, Related to Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding, Storm Recovery Funding and Cost Recovery Funding)	71		43
Other Temporary Investments (December 31, 2025 and 2024 Amounts Include $209 and $207, Respectively, Related to EIS)	220		215
Accounts Receivable:
Customers	1,166		1,100
Accrued Unbilled Revenues	421		367
Pledged Accounts Receivable – AEP Credit	1,272		1,162
Miscellaneous	60		64
Allowance for Credit Losses	(52)		(61)
Total Accounts Receivable	2,867		2,632
Fuel	576		749
Materials and Supplies	1,046		966
Risk Management Assets	352		210
Accrued Tax Benefits	85		38
Regulatory Asset for Under-Recovered Fuel Costs	426		446
Prepayments and Other Current Assets	212		287
TOTAL CURRENT ASSETS	6,052		5,789
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	28,388		24,830
Transmission	42,557		38,872
Distribution	33,364		31,062
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	8,635		7,491
Construction Work in Progress	7,635		6,347
Total Property, Plant and Equipment	120,579		108,602
Accumulated Depreciation and Amortization	28,205		26,186
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	92,374		82,416
OTHER NONCURRENT ASSETS
Regulatory Assets	4,804		5,129
Securitized Assets	933		554
Spent Nuclear Fuel and Decommissioning Trusts	4,916		4,395
Goodwill	53		53
Long-term Risk Management Assets	265		289
Operating Lease Assets	661		580
Deferred Charges and Other Noncurrent Assets	4,402		3,873
TOTAL OTHER NONCURRENT ASSETS	16,034		14,873
TOTAL ASSETS	$	114,460	$	103,078
See Notes to Financial Statements of Registrants beginning on page 182.

99

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

December 31, 2025 and 2024

(dollars in millions)

			December 31,
			2025		2024
CURRENT LIABILITIES
Accounts Payable			$	3,429	$	2,638
Short-term Debt:
Securitized Debt for Receivables – AEP Credit			900		900
Other Short-term Debt			608		1,624
Total Short-term Debt			1,508		2,524
Long-term Debt Due Within One Year (December 31, 2025 and 2024 Amounts Include $207 and $217, Respectively, Related to DCC Fuel, Restoration Funding, Appalachian Consumer Rate Relief Funding, Storm Recovery Funding, Transource Energy and Cost Recovery Funding)			3,194		3,335
Risk Management Liabilities			132		100
Customer Deposits			507		455
Accrued Taxes			2,002		1,922
Accrued Interest			544		453
Obligations Under Operating Leases			100		92
Other Current Liabilities			1,898		1,490
TOTAL CURRENT LIABILITIES			13,314		13,009
NONCURRENT LIABILITIES
Long-term Debt (December 31, 2025 and 2024 Amounts Include $1,294 and $827, Respectively, Related to DCC Fuel, Restoration Funding, Appalachian Consumer Rate Relief Funding, Storm Recovery Funding, Transource Energy and Cost Recovery Funding)			44,128		39,308
Long-term Risk Management Liabilities			178		224
Deferred Income Taxes			10,951		9,972
Regulatory Liabilities and Deferred Investment Tax Credits			8,362		8,344
Asset Retirement Obligations			3,556		3,531
Employee Benefits and Pension Obligations			232		361
Obligations Under Operating Leases			578		504
Deferred Credits and Other Noncurrent Liabilities			905		801
TOTAL NONCURRENT LIABILITIES			68,890		63,045
TOTAL LIABILITIES			82,204		76,054
Rate Matters (Note 4)
Commitments and Contingencies (Note 6)
Contingently Redeemable Performance Share Awards			38		38
EQUITY
Common Stock – Par Value – $6.50 Per Share:
	2025	2024
Shares Authorized	600,000,000	600,000,000
Shares Issued	542,048,288	534,094,530
(1,186,815 Shares were Held in Treasury as of December 31, 2025 and 2024, Respectively)			3,523		3,472
Paid-in Capital			12,138		9,606
Retained Earnings			15,441		13,869
Accumulated Other Comprehensive Income (Loss)			36		(3)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY			31,138		26,944
Noncontrolling Interests			1,080		42
TOTAL EQUITY			32,218		26,986
TOTAL LIABILITIES AND EQUITY			$	114,460	$	103,078
See Notes to Financial Statements of Registrants beginning on page 182.

100

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

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

(in millions)

	Years Ended December 31,
	2025		2024		2023
OPERATING ACTIVITIES
Net Income	$	3,696	$	2,976	$	2,213
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	3,380		3,290		3,090
Deferred Income Taxes	311		58		185
Loss on the Sale of the Competitive Contracted Renewables Portfolio	—		—		93
Asset Impairments and Other Related Charges	66		143		86
Allowance for Equity Funds Used During Construction	(245)		(211)		(175)
Mark-to-Market of Risk Management Contracts	(116)		(81)		9
Amortization of Nuclear Fuel	109		103		97
Pension Contributions to Qualified Plan Trust	(95)		—		—
Property Taxes	(42)		(45)		(41)
Deferred Fuel Over/Under-Recovery, Net	133		277		893
Change in Regulatory Assets	(304)		(174)		(316)
Change in Other Noncurrent Assets	(559)		(348)		(446)
Change in Other Noncurrent Liabilities	269		306		29
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(246)		(156)		236
Fuel, Materials and Supplies	115		172		(504)
Accounts Payable	252		85		(253)
Accrued Taxes, Net	32		240		22
Other Current Assets	85		(13)		(44)
Other Current Liabilities	103		182		(162)
Net Cash Flows from Operating Activities	6,944		6,804		5,012
INVESTING ACTIVITIES
Construction Expenditures	(8,453)		(7,631)		(7,378)
Purchases of Investment Securities	(2,981)		(2,923)		(2,864)
Sales of Investment Securities	2,935		2,878		2,795
Acquisitions of Nuclear Fuel	(130)		(140)		(128)
Acquisitions of Generation Facilities	(3,453)		(399)		(155)
Proceeds from Sales of Assets	25		362		1,341
Proceeds from Sale of Equity Method Investment	—		114		—
Other Investing Activities	118		143		122
Net Cash Flows Used for Investing Activities	(11,939)		(7,596)		(6,267)
FINANCING ACTIVITIES
Capital Contribution from Noncontrolling Interest	38		—		—
Issuance of Common Stock, Net	775		552		1,000
Issuance of Long-term Debt	8,261		5,117		5,463
Issuance of Short-term Debt with Original Maturities greater than 90 Days	320		724		1,070
Change in Short-term Debt with Original Maturities less than 90 Day, Net	(658)		(159)		(1,223)
Retirement of Long-term Debt	(3,649)		(2,685)		(2,196)
Redemption of Short-term Debt with Original Maturities greater than 90 Days	(678)		(871)		(1,129)
Principal Payments for Finance Lease Obligations	(51)		(65)		(68)
Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs	2,783		—		—
Dividends Paid on Common Stock	(2,008)		(1,898)		(1,752)
Dividends Paid on Noncontrolling Interest	(108)		(6)		(8)
Other Financing Activities	(8)		(50)		(80)
Net Cash Flows from Financing Activities	5,017		659		1,077
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	22		(133)		(178)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	246		379		557
Cash, Cash Equivalents and Restricted Cash at End of Period	$	268	$	246	$	379
See Notes to Financial Statements of Registrants beginning on page 182.

101

AEP TEXAS INC. AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
	Years Ended December 31,
	2025	2024	2023
	(in millions of KWhs)
Retail:
Residential	12,853	12,654	12,659
Commercial	19,562	15,852	13,549
Industrial	13,810	13,247	12,672
Miscellaneous	622	634	636
Total Retail	46,847	42,387	39,516

Summary of Heating and Cooling Degree Days
	Years Ended December 31,
	2025	2024	2023
	(in degree days)
Actual – Heating	348	196	197
Normal – Heating	323	316	318
Actual – Cooling	2,956	3,249	3,208
Normal – Cooling	2,641	2,770	2,737

102

AEP Texas Inc. and Subsidiaries

Reconciliation of Year Ended December 31, 2024 to Year Ended December 31, 2025

Net Income

(in millions)

Year Ended December 31, 2024	$	420
Changes in Revenues:
Retail Revenues	141
Transmission Revenues	44
Other Revenues	(66)
Total Change in Revenues	119
Changes in Expenses and Other:
Other Operation and Maintenance	(94)
Depreciation and Amortization	53
Taxes Other Than Income Taxes	(5)
Interest Income	(5)
Allowance for Equity Funds Used During Construction	7
Non-Service Cost Components of Net Periodic Benefit Cost	2
Interest Expense	(10)
Total Change in Expenses and Other	(52)
Income Tax Expense	1
Year Ended December 31, 2025	$	488

The major components of the increase in Revenues were as follows:

•Retail Revenues increased $141 million primarily due to a $130 million increase from base rate and rider revenues.

•Transmission Revenues increased $44 million due to the following:

•A $92 million increase in interim rates driven by increased transmission investments.

This increase was partially offset by:

•A $48 million decrease due to lower peak loads included in 2025 billing rates.

•Other Revenues decreased $66 million primarily due to a $74 million decrease in securitization revenues resulting from the maturity of Transition Funding III LLC securitization bonds in December 2024.

Expenses and Other changed between years as follows:

•Other Operation and Maintenance expenses increased $94 million primarily due to the following:

•A $54 million increase in recoverable Transmission Cost Recovery Factor expenses.

•A $19 million increase in transmission and distribution expenses.

•A $13 million increase due to an impairment of in-process internal use software development costs.

•A $12 million increase in employee-related expenses.

These increases were partially offset by:

•A $20 million decrease due to the voluntary severance program that occurred in the second quarter of 2024.

•Depreciation and Amortization expenses decreased $53 million primarily due to the following:

•A $71 million decrease in the amortization of securitized transition assets due to the maturity of Transition Funding III LLC securitization bonds.

•A $23 million decrease due to the deferral of eligible costs related to the UTM.

These decreases were partially offset by:

•A $37 million increase due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $5 million primarily due to higher property taxes driven by increased investment, partially offset by the deferral of eligible costs related to the UTM.

•Interest Income decreased $5 million primarily due to lower interest rates on advances to affiliates.

•Allowance for Equity Funds Used During Construction increased $7 million primarily due to a higher AFUDC base.

•Interest Expense increased $10 million primarily due to the following:

•A $36 million increase due to higher long-term debt balances and interest rates.

This increase was partially offset by:

•A $28 million decrease due to the deferral of eligible costs related to the UTM.

103

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

AEP Texas Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of AEP Texas Inc. and its subsidiaries (the “Company”) as of December 31, 2025 and 2024, and the related consolidated statements of income, of comprehensive income (loss), of changes in common shareholder's equity and of cash flows for each of the three years in the period ended December 31, 2025, including 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 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 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 of these consolidated financial statements 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 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 Matters

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 critical audit matters 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.

Accounting for the Effects of Cost-Based Regulation

As described in Notes 1 and 5 to the consolidated financial statements, the Company's consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. As of December 31, 2025, there were $402 million of deferred costs included in regulatory assets, $181 million of which were pending final regulatory approval, and $1,286 million of regulatory liabilities awaiting potential refund or future rate reduction. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation.

104

The principal considerations for our determination that performing procedures relating to the accounting for the effects of cost-based regulation is a critical audit matter are (i) the significant judgment by management in assessing probability of the recovery of regulatory assets and refund of regulatory liabilities and (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the probability of recovery of regulatory assets and refund of regulatory liabilities.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's evaluation of new events, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation, including controls over the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others (i) evaluating the reasonableness of management's assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities; (ii) testing, on a sample basis, the regulatory assets and liabilities, including those subject to pending rate cases and regulatory proceedings, by considering (a) the provisions and formulas outlined in rate orders; (b) other regulatory correspondence; and (c) application of relevant regulatory precedents.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio

February 12, 2026

We have served as the Company's auditor since 2017.

105

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of AEP Texas Inc. and Subsidiaries (AEP Texas) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.  AEP Texas’ internal control 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.

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.

Management assessed the effectiveness of AEP Texas’ internal control over financial reporting as of December 31, 2025.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013).  Based on management’s assessment, management concluded AEP Texas’ internal control over financial reporting was effective as of December 31, 2025.

This annual report does not include an audit report from PricewaterhouseCoopers LLP, AEP Texas’ registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit AEP Texas to provide only management’s report in this annual report.

106

AEP TEXAS INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

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

(in millions)

	Years Ended December 31,
	2025		2024		2023
REVENUES
Electric Transmission and Distribution	$	2,187	$	2,071	$	1,892
Sales to AEP Affiliates	5		5		5
Other Revenues	7		4		5
TOTAL REVENUES	2,199		2,080		1,902
EXPENSES
Other Operation	705		625		541
Maintenance	104		90		92
Depreciation and Amortization	441		494		469
Taxes Other Than Income Taxes	169		164		161
TOTAL EXPENSES	1,419		1,373		1,263
OPERATING INCOME	780		707		639
Other Income (Expense):
Interest Income	2		7		3
Allowance for Equity Funds Used During Construction	53		46		28
Non-Service Cost Components of Net Periodic Benefit Cost	22		20		19
Interest Expense	(268)		(258)		(233)
INCOME BEFORE INCOME TAX EXPENSE	589		522		456
Income Tax Expense	101		102		86
NET INCOME	$	488	$	420	$	370
The common stock of AEP Texas is wholly-owned by Parent.
See Notes to Financial Statements of Registrants beginning on page 182.

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AEP TEXAS INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

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

(in millions)

	Years Ended December 31,
	2025		2024		2023
Net Income	$	488	$	420	$	370
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0, $2 and $0 in 2025, 2024 and 2023, Respectively	(1)		6		1
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0, $0 and $0 in 2025, 2024 and 2023, Respectively	—		—		(1)
Pension and OPEB Funded Status, Net of Tax of $0, $0 and $0 in 2025, 2024 and 2023, Respectively	1		—		—
TOTAL OTHER COMPREHENSIVE INCOME	—		6		—
TOTAL COMPREHENSIVE INCOME	$	488	$	426	$	370
See Notes to Financial Statements of Registrants beginning on page 182.

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AEP TEXAS INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY

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

(in millions)

	Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022	$	1,558	$	2,355	$	(9)	$	3,904
Capital Contribution from Parent	527						527
Return of Capital to Parent	(5)						(5)
Net Income			370				370
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2023	2,080		2,725		(9)		4,796
Capital Contribution from Parent	14						14
Return of Capital to Parent	(1)						(1)
Common Stock Dividends			(350)				(350)
Net Income			420				420
Other Comprehensive Income					6		6
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2024	2,093		2,795		(3)		4,885
Capital Contribution from Parent	453						453
Net Income			488				488
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2025	$	2,546	$	3,283	$	(3)	$	5,826
See Notes to Financial Statements of Registrants beginning on page 182.

109

AEP TEXAS INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2025 and 2024

(in millions)

	December 31,
	2025		2024
CURRENT ASSETS
Restricted Cash (December 31, 2025 and 2024 Amounts Include $14 and $24, Respectively, Related to Transition Funding and Restoration Funding)	$	14	$	24
Advances to Affiliates	7		7
Accounts Receivable:
Customers	189		183
Affiliated Companies	15		11
Accrued Unbilled Revenues	101		97
Allowance for Credit Losses	—		(4)
Total Accounts Receivable	305		287
Materials and Supplies	168		170
Prepayments and Other Current Assets	15		12
TOTAL CURRENT ASSETS	509		500
PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission	8,229		7,546
Distribution	6,835