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.

107

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.

108

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		6,251
Other Property, Plant and Equipment	1,239		1,175
Construction Work in Progress	1,766		1,118
Total Property, Plant and Equipment	18,069		16,090
Accumulated Depreciation and Amortization	2,205		2,046
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	15,864		14,044
OTHER NONCURRENT ASSETS
Regulatory Assets	402		354
Securitized Assets (December 31, 2025 and 2024 Amounts Include $94 and $117, Respectively, Related to Restoration Funding)	94		117
Operating Lease Assets	52		54
Deferred Charges and Other Noncurrent Assets	154		131
TOTAL OTHER NONCURRENT ASSETS	702		656
TOTAL ASSETS	$	17,075	$	15,200
See Notes to Financial Statements of Registrants beginning on page 182.

110

AEP TEXAS INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

December 31, 2025 and 2024

(in millions)

	December 31,
	2025		2024
CURRENT LIABILITIES
Advances from Affiliates	$	188	$	285
Accounts Payable:
General	652		366
Affiliated Companies	60		35
Long-term Debt Due Within One Year – Nonaffiliated (December 31, 2025 and 2024 Amounts Include $25 and $24, Respectively, Related to Restoration Funding)	75		325
Accrued Taxes	118		127
Accrued Interest (December 31, 2025 and 2024 Amounts Include $1 and $2, Respectively, Related to Restoration Funding)	64		55
Obligations Under Operating Leases	14		13
Other Current Liabilities	247		201
TOTAL CURRENT LIABILITIES	1,418		1,407
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated (December 31, 2025 and 2024 Amounts Include $78 and $102, Respectively, Related to Restoration Funding)	6,941		6,117
Deferred Income Taxes	1,430		1,323
Regulatory Liabilities and Deferred Investment Tax Credits	1,286		1,285
Obligations Under Operating Leases	40		43
Deferred Credits and Other Noncurrent Liabilities	134		140
TOTAL NONCURRENT LIABILITIES	9,831		8,908
TOTAL LIABILITIES	11,249		10,315
Rate Matters (Note 4)
Commitments and Contingencies (Note 6)
COMMON SHAREHOLDER’S EQUITY
Paid-in Capital	2,546		2,093
Retained Earnings	3,283		2,795
Accumulated Other Comprehensive Income (Loss)	(3)		(3)
TOTAL COMMON SHAREHOLDER’S EQUITY	5,826		4,885
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY	$	17,075	$	15,200
See Notes to Financial Statements of Registrants beginning on page 182.

111

AEP TEXAS INC. AND SUBSIDIARIES

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	$	488	$	420	$	370
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	441		494		469
Deferred Income Taxes	71		78		64
Allowance for Equity Funds Used During Construction	(53)		(46)		(28)
Pension Contributions to Qualified Plan Trust	(12)		—		—
Change in Other Noncurrent Assets	(108)		(91)		(97)
Change in Other Noncurrent Liabilities	85		39		24
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(18)		(8)		(28)
Materials and Supplies	2		21		(52)
Accounts Payable	72		25		(24)
Accrued Taxes, Net	(10)		30		12
Other Current Assets	3		(6)		4
Other Current Liabilities	(41)		8		(54)
Net Cash Flows from Operating Activities	920		964		660
INVESTING ACTIVITIES
Construction Expenditures	(1,920)		(1,414)		(1,477)
Other Investing Activities	68		55		69
Net Cash Flows Used for Investing Activities	(1,852)		(1,359)		(1,408)
FINANCING ACTIVITIES
Capital Contribution from Parent	453		14		527
Return of Capital to Parent	—		(1)		(5)
Issuance of Long-term Debt – Nonaffiliated	1,293		842		505
Change in Advances from Affiliates, Net	(97)		181		7
Retirement of Long-term Debt – Nonaffiliated	(724)		(296)		(279)
Principal Payments for Finance Lease Obligations	(8)		(8)		(7)
Dividends Paid on Common Stock	—		(350)		—
Other Financing Activities	5		3		2
Net Cash Flows from Financing Activities	922		385		750
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(10)		(10)		2
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	24		34		32
Cash, Cash Equivalents and Restricted Cash at End of Period	$	14	$	24	$	34
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	244	$	241	$	226
Noncash Acquisitions Under Finance Leases	7		5		5
Construction Expenditures Included in Current Liabilities as of December 31,	514		266		112
See Notes to Financial Statements of Registrants beginning on page 182.

112

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

Summary of Investment in Transmission Assets for AEPTCo

	As of December 31,
	2025		2024
	(in millions)
Plant In Service	$	17,113	$	15,429
CWIP	2,005		1,965
Accumulated Depreciation	1,915		1,578
Total Transmission Property, Net	$	17,203	$	15,816

AEP Transmission Company, LLC and Subsidiaries

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

Earnings Attributable to AEP Member

(in millions)

Year Ended December 31, 2024	$	688
Changes in Transmission Revenues:
Transmission Revenues	428
Total Change in Transmission Revenues	428
Changes in Expenses and Other:
Other Operation and Maintenance	(27)
Depreciation and Amortization	(47)
Taxes Other Than Income Taxes	(12)
Interest Income - Affiliated	(5)
Allowance for Equity Funds Used During Construction	4
Interest Expense	(20)
Total Change in Expenses and Other	(107)
Income Tax Expense	175
Net Income Attributable to Noncontrolling Interest	(109)
Year Ended December 31, 2025	$	1,075

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

•Transmission Revenues increased $428 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 $214 million increase due to continued transmission investment.

Expenses and Other, Income Tax Expense and Net Income Attributable to Noncontrolling Interest changed between years as follows:

•Other Operation and Maintenance expenses increased $27 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 $12 million primarily due to higher property taxes driven by increased transmission investment.

•Interest Income - Affiliated decreased $5 million primarily due to lower advances to affiliates.

•Interest Expense increased $20 million primarily due to higher long-term debt balances and interest rates.

113

•Income Tax Expense decreased $175 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 $67 million increase due to an increase in pretax book income.

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

114

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Member of

AEP Transmission Company, LLC

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of AEP Transmission Company, LLC and its subsidiaries (the “Company”) as of December 31, 2025 and 2024, and the related consolidated statements of income, of changes in member's 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 schedule listed in the index appearing under Item 15(a)(2) (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 $73 million of deferred costs included in regulatory assets, $9 million of which were pending final regulatory approval, and $708 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.

115

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.

116

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of AEP Transmission Company, LLC and Subsidiaries (AEPTCo) 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.  AEPTCo’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 AEPTCo’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 AEPTCo’s internal control over financial reporting was effective as of December 31, 2025.

This annual report does not include an audit report from PricewaterhouseCoopers LLP, AEPTCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit AEPTCo to provide only management’s report in this annual report.

117

AEP TRANSMISSION COMPANY, LLC 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
Transmission Revenues	$	428	$	401	$	363
Sales to AEP Affiliates	1,790		1,582		1,463
(Provision for)/Reversal of – Revenue Refund – Affiliated	79		(70)		(146)
(Provision for)/ Reversal of – Revenue Refund – Nonaffiliated	22		(22)		(9)
TOTAL REVENUES	2,319		1,891		1,671
EXPENSES
Other Operation	154		137		109
Maintenance	31		21		20
Depreciation and Amortization	478		431		394
Taxes Other Than Income Taxes	321		309		283
TOTAL EXPENSES	984		898		806
OPERATING INCOME	1,335		993		865
Other Income (Expense):
Interest Income - Affiliated	5		10		8
Allowance for Equity Funds Used During Construction	93		89		83
Interest Expense	(234)		(214)		(195)
INCOME BEFORE INCOME TAX EXPENSE	1,199		878		761
Income Tax Expense	15		190		147
NET INCOME	1,184		688		614
Net Income Attributable to Noncontrolling Interest	109		—		—
EARNINGS ATTRIBUTABLE TO AEP MEMBER	$	1,075	$	688	$	614
AEPTCo is wholly-owned by AEP Transmission Holdco.
See Notes to Financial Statements of Registrants beginning on page 182.

118

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY

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

(in millions)

	Paid-in Capital		Retained Earnings		Noncontrolling Interest		Total Member’s Equity
TOTAL MEMBER'S EQUITY - DECEMBER 31, 2022	$	3,022	$	2,851	$	—	$	5,873
Capital Contribution from AEP Member	30						30
Return of Capital to AEP Member	(8)						(8)
Dividends Paid to AEP Member			(175)				(175)
Net Income			614				614
TOTAL MEMBER'S EQUITY - DECEMBER 31, 2023	3,044		3,290		—		6,334
Capital Contribution from AEP Member	62						62
Return of Capital to AEP Member	(5)						(5)
Dividends Paid to AEP Member			(128)				(128)
Net Income			688				688
TOTAL MEMBER'S EQUITY - DECEMBER 31, 2024	3,101		3,850		—		6,951
Capital Contribution from AEP Member	70						70
Capital Contribution from Noncontrolling Interest					34		34
Dividends Paid to AEP Member			(3,274)				(3,274)
Dividends Paid to Noncontrolling Interest					(105)		(105)
Midwest Transmission Holdings Noncontrolling Interest Transaction	1,791				992		2,783
Net Income			1,075		109		1,184
TOTAL MEMBER'S EQUITY - DECEMBER 31, 2025	$	4,962	$	1,651	$	1,030	$	7,643
See Notes to Financial Statements of Registrants beginning on page 182.

119

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2025 and 2024

(in millions)

	December 31,
	2025		2024
CURRENT ASSETS
Advances to Affiliates	$	71	$	30
Accounts Receivable:
Customers	94		59
Affiliated Companies	153		134
Miscellaneous	—		1
Total Accounts Receivable	247		194
Prepayments and Other Current Assets	4		12
TOTAL CURRENT ASSETS	322		236
TRANSMISSION PROPERTY
Transmission Property	16,542		14,913
Other Property, Plant and Equipment	571		516
Construction Work in Progress	2,005		1,965
Total Transmission Property	19,118		17,394
Accumulated Depreciation and Amortization	1,915		1,578
TOTAL TRANSMISSION PROPERTY – NET	17,203		15,816
OTHER NONCURRENT ASSETS
Regulatory Assets	73		—
Deferred Property Taxes	326		309
Deferred Charges and Other Noncurrent Assets	75		9
TOTAL OTHER NONCURRENT ASSETS	474		318
TOTAL ASSETS	$	17,999	$	16,370
See Notes to Financial Statements of Registrants beginning on page 182.

120

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND MEMBER’S EQUITY

December 31, 2025 and 2024

	December 31,
	2025		2024
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	143	$	85
Accounts Payable:
General	477		360
Affiliated Companies	164		117
Long-term Debt Due Within One Year – Nonaffiliated	425		90
Accrued Taxes	650		666
Accrued Interest	46		45
Obligations Under Operating Leases	1		1
Other Current Liabilities	41		45
TOTAL CURRENT LIABILITIES	1,947		1,409
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	6,174		5,678
Deferred Income Taxes	1,481		1,279
Regulatory Liabilities	708		878
Obligations Under Operating Leases	2		1
Deferred Credits and Other Noncurrent Liabilities	44		174
TOTAL NONCURRENT LIABILITIES	8,409		8,010
TOTAL LIABILITIES	10,356		9,419
Rate Matters (Note 4)
Commitments and Contingencies (Note 6)
MEMBER’S EQUITY
Paid-in Capital	4,962		3,101
Retained Earnings	1,651		3,850
TOTAL MEMBER’S EQUITY	6,613		6,951
Noncontrolling Interest	1,030		—
TOTAL EQUITY	7,643		6,951
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	17,999	$	16,370
See Notes to Financial Statements of Registrants beginning on page 182.

121

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

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	$	1,184	$	688	$	614
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	478		431		394
Deferred Income Taxes	(152)		110		44
Allowance for Equity Funds Used During Construction	(93)		(89)		(83)
Property Taxes	(17)		(22)		(20)
Change in Other Noncurrent Assets	(80)		(1)		8
Change in Other Noncurrent Liabilities	(127)		(17)		134
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(53)		13		(41)
Materials and Supplies	—		—		11
Accounts Payable	75		10		23
Accrued Taxes, Net	(16)		97		43
Accrued Interest	1		5		11
Other Current Assets	7		(1)		—
Other Current Liabilities	(22)		14		—
Net Cash Flows from Operating Activities	1,185		1,238		1,138
INVESTING ACTIVITIES
Construction Expenditures	(1,569)		(1,477)		(1,496)
Change in Advances to Affiliates, Net	(41)		37		(63)
Acquisitions of Assets	(10)		(5)		(7)
Other Investing Activities	42		17		7
Net Cash Flows Used for Investing Activities	(1,578)		(1,428)		(1,559)
FINANCING ACTIVITIES
Capital Contribution from AEP Member	70		62		30
Capital Contribution from Noncontrolling Interest	34		—		—
Return of Capital to AEP Member	—		(5)		(8)
Issuance of Long-term Debt – Nonaffiliated	929		446		689
Retirement of Long-term Debt – Nonaffiliated	(102)		(95)		(60)
Change in Advances from Affiliates, Net	58		(90)		(55)
Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs	2,783		—		—
Dividends Paid to AEP Member	(3,274)		(128)		(175)
Dividends Paid to Noncontrolling Interest	(105)		—		—
Net Cash Flows from Financing Activities	393		190		421
Net Change in Cash and Cash Equivalents	—		—		—
Cash and Cash Equivalents at Beginning of Period	—		—		—
Cash and Cash Equivalents at End of Period	$	—	$	—	$	—
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	227	$	204	$	180
Construction Expenditures Included in Current Liabilities as of December 31,	343		263		178
See Notes to Financial Statements of Registrants beginning on page 182.

122

APPALACHIAN POWER COMPANY 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	10,909	10,483	10,126
Commercial	5,975	5,948	5,728
Industrial	8,565	8,666	8,710
Miscellaneous	835	829	804
Total Retail	26,284	25,926	25,368
Wholesale (a)	3,058	2,243	2,191
Total KWhs	29,342	28,169	27,559

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

Summary of Heating and Cooling Degree Days
	Years Ended December 31,
	2025	2024	2023
	(in degree days)
Actual – Heating	2,257	1,713	1,537
Normal – Heating	2,134	2,181	2,208
Actual – Cooling	1,186	1,544	1,145
Normal – Cooling	1,241	1,250	1,251

123

Appalachian Power Company and Subsidiaries

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

Net Income

(in millions)

Year Ended December 31, 2024	$	422
Changes in Revenues:
Retail Revenues	140
Off-system Sales	7
Transmission Revenues	23
Other Revenues	6
Total Change in Revenues	176
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	8
Other Operation and Maintenance	(95)
Depreciation and Amortization	(30)
Taxes Other Than Income Taxes	5
Interest Income	(1)
Allowance for Equity Funds Used During Construction	1
Non-Service Cost Components of Net Periodic Benefit Cost	(6)
Interest Expense	(12)
Total Change in Expenses and Other	(130)
Income Tax Expense	(11)
Year Ended December 31, 2025	$	457

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

•Retail Revenues increased $140 million primarily due to the following:

•A $57 million increase in base rate and rider revenues.

•A $50 million increase in fuel revenues.

•A $30 million increase in weather-related usage driven by a 32% increase in heating degree days, partially offset by a 23% decrease in cooling degree days.

•A $6 million increase in weather-normalized revenues primarily in the residential and commercial classes.

•Off-system Sales increased $7 million primarily due to capacity revenues recognized from the RPM auction for the 2025-2026 planning year.

•Transmission Revenues increased $23 million primarily due to the following:

•An $18 million increase due to continued transmission investment.

•A $6 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•Other Revenues increased $6 million primarily due to increased rent received from associated companies.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $8 million primarily to the following:

•An $18 million decrease due to the prior year amortization of Excess ADIT through the West Virginia ENEC.

•A $17 million decrease due to the impact to the West Virginia ENEC as a result of the June 2025 FERC NOLC order.

These decreases were partially offset by:

•A $27 million increase in purchased power prices and renewable energy credit revenue.

•Other Operation and Maintenance expenses increased $95 million primarily due to the following:

•A $42 million increase in transmission expenses primarily due to:

•An $18 million increase in recoverable PJM expenses.

•A $15 million increase due to the June 2025 FERC NOLC order.

•A $27 million increase in distribution expenses primarily due to an increase in storm-related expenses, partially offset by a decrease in vegetation management costs.

124

•A $21 million increase due to recoverable energy assistance program expenses for qualified Virginia customers.

•A $13 million increase in employee-related expenses.

•An $11 million increase due to an impairment of in-process internal use software development costs.

These increases were partially offset by:

•A $26 million decrease due to the voluntary severance program that occurred in the second quarter of 2024.

•Depreciation and Amortization expenses increased $30 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes decreased $5 million primarily due to lower business and occupation taxes, partially offset by higher property taxes.

•Non-Service Cost Components of Net Periodic Benefit Cost increased $6 million primarily due to lower asset returns in prior years and a higher cash balance interest crediting rate, partially offset by an increase in the discount rate.

•Interest Expense increased $12 million primarily due to higher long-term debt balances.

•Income Tax Expense increased $11 million primarily due to the following:

•An $18 million increase due to an increase in flow-through CAMT expense.

•A $14 million increase due to a decrease in amortization of Excess ADIT.

These increases were partially offset by:

•A $23 million decrease 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.

125

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Appalachian Power Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Appalachian Power Company 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 $1,522 million of deferred costs included in regulatory assets, $440 million of which were pending final regulatory approval, and $1,111 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.

126

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.

127

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Appalachian Power Company and Subsidiaries (APCo) 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.  APCo’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 APCo’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 APCo’s internal control over financial reporting was effective as of December 31, 2025.

This annual report does not include an audit report from PricewaterhouseCoopers LLP, APCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit APCo to provide only management’s report in this annual report.

128

APPALACHIAN POWER COMPANY 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 Generation, Transmission and Distribution	$	3,912	$	3,769	$	3,464
Sales to AEP Affiliates	279		248		239
Other Revenues	18		16		18
TOTAL REVENUES	4,209		4,033		3,721
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	1,398		1,406		1,435
Other Operation	867		805		748
Maintenance	356		323		272
Depreciation and Amortization	632		602		572
Taxes Other Than Income Taxes	172		177		163
TOTAL EXPENSES	3,425		3,313		3,190
OPERATING INCOME	784		720		531
Other Income (Expense):
Interest Income	4		5		3
Allowance for Equity Funds Used During Construction	17		16		12
Non-Service Cost Components of Net Periodic Benefit Cost	21		27		32
Interest Expense	(283)		(271)		(270)
INCOME BEFORE INCOME TAX EXPENSE	543		497		308
Income Tax Expense	86		75		14
NET INCOME	$	457	$	422	$	294
The common stock of APCo is wholly-owned by Parent.
See Notes to Financial Statements of Registrants beginning on page 182.

129

APPALACHIAN POWER COMPANY 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	$	457	$	422	$	294
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0, $0 and $0 in 2025, 2024 and 2023, Respectively	(1)		(1)		(1)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0, $0 and $(1) in 2025, 2024 and 2023, Respectively	—		(1)		(3)
Pension and OPEB Funded Status, Net of Tax of $4, $5 and $1 in 2025, 2024 and 2023, Respectively	14		17		5
TOTAL OTHER COMPREHENSIVE INCOME	13		15		1
TOTAL COMPREHENSIVE INCOME	$	470	$	437	$	295
See Notes to Financial Statements of Registrants beginning on page 182.

130

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY

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

(in millions)

	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022	$	260	$	1,829	$	2,891	$	(5)	$	4,975
Capital Contribution from Parent			7						7
Return of Capital to Parent			(1)						(1)
Net Income					294				294
Other Comprehensive Income							1		1
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2023	260		1,835		3,185		(4)		5,276
Capital Contribution from Parent			114						114
Return of Capital to Parent			(4)						(4)
Common Stock Dividends					(75)				(75)
Net Income					422				422
Other Comprehensive Income							15		15
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2024	260		1,945		3,532		11		5,748
Capital Contribution from Parent			12						12
Common Stock Dividends					(50)				(50)
Net Income					457				457
Other Comprehensive Income							13		13
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2025	$	260	$	1,957	$	3,939	$	24	$	6,180
See Notes to Financial Statements of Registrants beginning on page 182.

131

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2025 and 2024

(in millions)

	December 31,
	2025		2024
CURRENT ASSETS
Cash and Cash Equivalents	$	5	$	4
Restricted Cash for Securitized Funding	18		16
Advances to Affiliates	17		18
Accounts Receivable:
Customers	171		186
Affiliated Companies	142		110
Accrued Unbilled Revenues	112		93
Allowance for Credit Losses	(2)		(2)
Total Accounts Receivable	423		387
Fuel	229		308
Materials and Supplies	139		132
Risk Management Assets	81		36
Regulatory Asset for Under-Recovered Fuel Costs	83		148
Prepayments and Other Current Assets	38		46
TOTAL CURRENT ASSETS	1,033		1,095
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	7,886		7,273
Transmission	5,277		5,001
Distribution	5,938		5,569
Other Property, Plant and Equipment	1,175		1,063
Construction Work in Progress	802		743
Total Property, Plant and Equipment	21,078		19,649
Accumulated Depreciation and Amortization	6,365		6,036
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	14,713		13,613
OTHER NONCURRENT ASSETS
Regulatory Assets	1,439		1,366
Securitized Assets	78		106
Employee Benefits and Pension Assets	251		204
Operating Lease Assets	95		67
Deferred Charges and Other Noncurrent Assets	183		215
TOTAL OTHER NONCURRENT ASSETS	2,046		1,958
TOTAL ASSETS	$	17,792	$	16,666
See Notes to Financial Statements of Registrants beginning on page 182.

132

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

December 31, 2025 and 2024

	December 31,
	2025		2024
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	209	$	95
Accounts Payable:
General	375		427
Affiliated Companies	173		206
Long-term Debt Due Within One Year - Nonaffiliated	1,131		799
Customer Deposits	94		87
Accrued Taxes	116		169
Obligations Under Operating Leases	15		14
Other Current Liabilities	271		229
TOTAL CURRENT LIABILITIES	2,384		2,026
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	5,128		4,862
Deferred Income Taxes	2,130		2,034
Regulatory Liabilities and Deferred Investment Tax Credits	1,111		1,116
Asset Retirement Obligations	707		767
Employee Benefits and Pension Obligations	26		30
Obligations Under Operating Leases	81		54
Deferred Credits and Other Noncurrent Liabilities	45		29
TOTAL NONCURRENT LIABILITIES	9,228		8,892
TOTAL LIABILITIES	11,612		10,918
Rate Matters (Note 4)
Commitments and Contingencies (Note 6)
COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 30,000,000 Shares
Outstanding – 13,499,500 Shares	260		260
Paid-in Capital	1,957		1,945
Retained Earnings	3,939		3,532
Accumulated Other Comprehensive Income (Loss)	24		11
TOTAL COMMON SHAREHOLDER’S EQUITY	6,180		5,748
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	17,792	$	16,666
See Notes to Financial Statements of Registrants beginning on page 182.

133

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

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	$	457	$	422	$	294
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	632		602		572
Deferred Income Taxes	42		(17)		(54)
Allowance for Equity Funds Used During Construction	(17)		(16)		(12)
Mark-to-Market of Risk Management Contracts	(44)		(35)		66
Deferred Fuel Over/Under-Recovery, Net	59		136		280
Change in Regulatory Assets	(155)		(115)		(20)
Change in Other Noncurrent Assets	(17)		(47)		(95)
Change in Other Noncurrent Liabilities	54		12		(2)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(36)		(46)		18
Fuel, Materials and Supplies	72		24		(174)
Accounts Payable	(62)		166		(126)
Accrued Taxes, Net	(59)		51		25
Other Current Assets	16		(4)		(16)
Other Current Liabilities	(20)		11		(33)
Net Cash Flows from Operating Activities	922		1,144		723
INVESTING ACTIVITIES
Construction Expenditures	(1,056)		(1,009)		(1,053)
Change in Advances to Affiliates, Net	1		1		1
Acquisitions of Assets	(548)		(1)		(11)
Other Investing Activities	19		16		8
Net Cash Flows Used for Investing Activities	(1,584)		(993)		(1,055)
FINANCING ACTIVITIES
Capital Contribution from Parent	12		114		7
Return of Capital to Parent	—		(4)		(1)
Issuance of Long-term Debt – Nonaffiliated	1,143		481		200
Change in Advances from Affiliates, Net	114		(245)		157
Retirement of Long-term Debt – Nonaffiliated	(548)		(414)		(27)
Principal Payments for Finance Lease Obligations	(9)		(9)		(8)
Dividends Paid on Common Stock	(50)		(75)		—
Other Financing Activities	3		1		2
Net Cash Flows from (Used for) Financing Activities	665		(151)		330
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash for Securitized Funding	3		—		(2)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period	20		20		22
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period	$	23	$	20	$	20
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	272	$	257	$	260
Noncash Acquisitions Under Finance Leases	4		2		5
Construction Expenditures Included in Current Liabilities as of December 31,	143		159		101
See Notes to Financial Statements of Registrants beginning on page 182.

134

INDIANA MICHIGAN POWER COMPANY 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	5,473	5,301	5,169
Commercial	6,571	5,273	4,971
Industrial	7,218	7,298	7,309
Miscellaneous	46	49	55
Total Retail	19,308	17,921	17,504
Wholesale (a)	6,381	6,278	5,215
Total KWhs	25,689	24,199	22,719

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

Summary of Heating and Cooling Degree Days
	Years Ended December 31,
	2025	2024	2023
	(in degree days)
Actual – Heating	3,713	2,859	2,917
Normal – Heating	3,642	3,721	3,734
Actual – Cooling	927	987	751
Normal – Cooling	883	867	871

135

Indiana Michigan Power Company and Subsidiaries

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

Net Income

(in millions)

Year Ended December 31, 2024	$	391
Changes in Revenues:
Retail Revenues	315
Off-system Sales	137
Transmission Revenues	9
Other Revenues	(2)
Total Change in Revenues	459
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(184)
Purchased Electricity from AEP Affiliates	(61)
Other Operation and Maintenance	(58)
Asset Impairments and Other Related Charges	6
Depreciation and Amortization	(33)
Taxes Other Than Income Taxes	(3)
Other Income	8
Non-Service Cost Components of Net Periodic Benefit Cost	2
Interest Expense	(17)
Total Change in Expenses and Other	(340)
Income Tax Expense	(96)
Year Ended December 31, 2025	$	414

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

•Retail Revenues increased $315 million primarily due to the following:

•A $109 million increase in rider revenues.

•A $100 million increase in weather-normalized revenues primarily in the commercial class.

•An $89 million increase due to the implementation of new base rates in Indiana and Michigan.

•A $76 million increase in fuel revenues.

•A $23 million increase in weather-related usage primarily due to a 30% increase in heating degree days.

These increases were partially offset by:

•An $86 million decrease due to regulatory provisions for refund.

•Off-system Sales increased $137 million primarily due to economic hedging activity and Rockport Plant, Unit 2 merchant sales.

•Transmission Revenues increased $9 million primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $184 million primarily due to an increase in recoverable fuel and purchased power costs and an increase in Rockport Plant, Unit 2, merchant generation fuel costs.

•Purchased Electricity from AEP Affiliates increased $61 million primarily due to an increase in purchased electricity from AEGCo.

136

•Other Operation and Maintenance expenses increased $58 million primarily due to the following:

•A $38 million increase in distribution expenses primarily due to an increase in vegetation management costs and other distribution-related expenses.

•A $20 million increase in transmission expenses primarily due to a $25 million increase in recoverable PJM expenses, partially offset by a $6 million decrease due to the June 2025 FERC order related to the treatment of stand-alone NOLCs in transmission formula rates.

•An $18 million increase in employee-related expenses.

•A $14 million increase in nuclear expenses at Cook Plant.

These increases were partially offset by:

•A $15 million decrease due to the voluntary severance program that occurred in the second quarter of 2024.

•A $13 million decrease in demand side management expenses.

•An $11 million decrease in non-utility operation expenses due to a decrease in River Transportation Division barging expenses.

•Asset Impairments and Other Related Charges decreased $6 million due to the following:

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

This decrease was partially offset by:

•A $7 million increase due to an impairment of in-process internal use software development costs.

•Depreciation and Amortization expenses increased $33 million primarily due to the following:

•A $20 million increase 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 $15 million increase due to a higher depreciable base.

•Other Income increased $8 million primarily due to an increase in AFUDC due to a higher AFUDC base and an increase in equity rates.

•Interest Expense increased $17 million primarily 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.

•Income Tax Expense increased $96 million primarily due to the following:

•A $55 million increase due to a reduction in Excess ADIT regulatory liabilities as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking recorded in 2024.

•A $25 million increase due to an increase in pretax book income.

•An $18 million increase due to a decrease in amortization of Excess ADIT.

•A $16 million increase due to a decrease in PTCs.

•A $9 million increase due to an increase in state taxes.

These increases were partially offset by:

•A $32 million decrease due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of stand-alone NOLCs in transmission formula rates.

137

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Indiana Michigan Power Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Indiana Michigan Power Company 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 $585 million of deferred costs included in regulatory assets, $118 million of which were pending final regulatory approval, and $2,957 million of regulatory liabilities awaiting potential refund or future rate reduction, $27 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.

138

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.

139

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Indiana Michigan Power Company and Subsidiaries (I&M) 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.  I&M’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 I&M’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 I&M’s internal control over financial reporting was effective as of December 31, 2025.

This annual report does not include an audit report from PricewaterhouseCoopers LLP, I&M’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit I&M to provide only management’s report in this annual report.

140

INDIANA MICHIGAN POWER COMPANY 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 Generation, Transmission and Distribution	$	3,096	$	2,552	$	2,469
Sales to AEP Affiliates	14		15		9
Provision for Revenue Refund – Affiliated	(3)		(14)		(11)
Provision for Revenue Refund – Nonaffiliated	(142)		(57)		(3)
Other Revenues – Affiliated	58		65		59
Other Revenues – Nonaffiliated	8		11		13
TOTAL REVENUES	3,031		2,572		2,536
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	601		417		411
Purchased Electricity from AEP Affiliates	270		209		181
Other Operation	731		729		663
Maintenance	291		235		239
Asset Impairment and Other Related Charges	7		13		—
Depreciation and Amortization	514		481		470
Taxes Other Than Income Taxes	92		89		84
TOTAL EXPENSES	2,506		2,173		2,048
OPERATING INCOME	525		399		488
Other Income (Expense):
Other Income	21		13		13
Non-Service Cost Components of Net Periodic Benefit Cost	20		18		31
Interest Expense	(151)		(134)		(137)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	415		296		395
Income Tax Expense (Benefit)	1		(95)		59
NET INCOME	$	414	$	391	$	336
The common stock of I&M is wholly-owned by Parent.
See Notes to Financial Statements of Registrants beginning on page 182.

141

INDIANA MICHIGAN POWER COMPANY 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	$	414	$	391	$	336
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
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	2		1		1
TOTAL OTHER COMPREHENSIVE INCOME	2		1		—
TOTAL COMPREHENSIVE INCOME	$	416	$	392	$	336
See Notes to Financial Statements of Registrants beginning on page 182.

142

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY

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

(in millions)

	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022	$	57	$	989	$	1,963	$	(1)	$	3,008
Capital Contribution from Parent			9						9
Common Stock Dividends					(212)				(212)
Net Income					336				336
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2023	57		998		2,087		(1)		3,141
Capital Contribution from Parent			16						16
Return of Capital to Parent			(2)						(2)
Common Stock Dividends					(150)				(150)
Net Income					391				391
Other Comprehensive Income							1		1
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2024	57		1,012		2,328		—		3,397
Capital Contribution from Parent			21						21
Common Stock Dividends					(50)				(50)
Net Income					414				414
Other Comprehensive Income							2		2
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2025	$	57	$	1,033	$	2,692	$	2	$	3,784
See Notes to Financial Statements of Registrants beginning on page 182.

143

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2025 and 2024

(in millions)

	December 31,
	2025		2024
CURRENT ASSETS
Cash and Cash Equivalents	$	2	$	2
Advances to Affiliates	192		—
Accounts Receivable:
Customers	103		59
Affiliated Companies	90		79
Accrued Unbilled Revenues	17		21
Miscellaneous	2		6
Total Accounts Receivable	212		165
Fuel	61		83
Materials and Supplies	222		212
Risk Management Assets	10		18
Regulatory Asset for Under-Recovered Fuel Costs	—		11
Prepayments and Other Current Assets	85		53
TOTAL CURRENT ASSETS	784		544
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	5,483		5,503
Transmission	2,055		1,958
Distribution	3,823		3,535
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	1,058		992
Construction Work in Progress	403		335
Total Property, Plant and Equipment	12,822		12,323
Accumulated Depreciation, Depletion and Amortization	4,878		4,644
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	7,944		7,679
OTHER NONCURRENT ASSETS
Regulatory Assets	585		548
Spent Nuclear Fuel and Decommissioning Trusts	4,916		4,395
Operating Lease Assets	52		52
Deferred Charges and Other Noncurrent Assets	344		318
TOTAL OTHER NONCURRENT ASSETS	5,897		5,313
TOTAL ASSETS	$	14,625	$	13,536
See Notes to Financial Statements of Registrants beginning on page 182.

144

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

December 31, 2025 and 2024

(dollars in millions)

	December 31,
	2025		2024
CURRENT LIABILITIES
Advances from Affiliates	$	—	$	127
Accounts Payable:
General	232		202
Affiliated Companies	125		99
Long-term Debt Due Within One Year – Nonaffiliated (December 31, 2025 and 2024 Amounts Include $117 and $79, Respectively, Related to DCC Fuel)	117		269
Customer Deposits	55		59
Accrued Taxes	112		102
Accrued Interest	42		41
Obligations Under Operating Leases	17		12
Regulatory Liability for Over-Recovered Fuel Costs	19		10
Other Current Liabilities	230		150
TOTAL CURRENT LIABILITIES	949		1,071
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	3,444		3,225
Deferred Income Taxes	1,219		1,176
Regulatory Liabilities and Deferred Investment Tax Credits	2,938		2,481
Asset Retirement Obligations	2,165		2,089
Obligations Under Operating Leases	37		40
Deferred Credits and Other Noncurrent Liabilities	89		57
TOTAL NONCURRENT LIABILITIES	9,892		9,068
TOTAL LIABILITIES	10,841		10,139
Rate Matters (Note 4)
Commitments and Contingencies (Note 6)
COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 2,500,000 Shares
Outstanding  – 1,400,000 Shares	57		57
Paid-in Capital	1,033		1,012
Retained Earnings	2,692		2,328
Accumulated Other Comprehensive Income (Loss)	2		—
TOTAL COMMON SHAREHOLDER’S EQUITY	3,784		3,397
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY	$	14,625	$	13,536
See Notes to Financial Statements of Registrants beginning on page 182.

145

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

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	$	414	$	391	$	336
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	514		481		470
Deferred Income Taxes	(13)		(117)		(54)
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net	(39)		13		26
Asset Impairment and Other Related Charges	7		13		—
Allowance for Equity Funds Used During Construction	(18)		(13)		(11)
Mark-to-Market of Risk Management Contracts	8		20		(22)
Amortization of Nuclear Fuel	109		103		97
Deferred Fuel Over/Under-Recovery, Net	20		(9)		56
Change in Other Noncurrent Assets	(59)		(17)		(81)
Change in Other Noncurrent Liabilities	98		41		47
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(47)		(23)		71
Fuel, Materials and Supplies	12		1		(61)
Accounts Payable	57		(45)		23
Accrued Taxes, Net	(22)		(3)		2
Other Current Assets	10		2		(6)
Other Current Liabilities	45		32		(13)
Net Cash Flows from Operating Activities	1,096		870		880
INVESTING ACTIVITIES
Construction Expenditures	(646)		(583)		(550)
Change in Advances to Affiliates, Net	(192)		—		23
Purchases of Investment Securities	(2,959)		(2,902)		(2,845)
Sales of Investment Securities	2,909		2,851		2,788
Acquisitions of Nuclear Fuel	(130)		(140)		(128)
Other Investing Activities	33		6		5
Net Cash Flows Used for Investing Activities	(985)		(768)		(707)
FINANCING ACTIVITIES
Capital Contribution from Parent	21		16		9
Return of Capital to Parent	—		(2)		—
Issuance of Long-term Debt - Nonaffiliated	351		80		565
Change in Advances from Affiliates, Net	(127)		64		(187)
Retirement of Long-term Debt - Nonaffiliated	(300)		(103)		(343)
Principal Payments for Finance Lease Obligations	(6)		(7)		(7)
Dividends Paid on Common Stock	(50)		(150)		(212)
Net Cash Flows Used for Financing Activities	(111)		(102)		(175)
Net Decrease in Cash and Cash Equivalents	—		—		(2)
Cash and Cash Equivalents at Beginning of Period	2		2		4
Cash and Cash Equivalents at End of Period	$	2	$	2	$	2
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	145	$	144	$	132
Noncash Acquisitions Under Finance Leases	2		2		5
Construction Expenditures Included in Current Liabilities as of December 31,	94		77		68
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,	10		24		24
See Notes to Financial Statements of Registrants beginning on page 182.

146

OHIO POWER COMPANY 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	14,584	14,128	13,440
Commercial	26,625	20,295	16,870
Industrial	14,210	14,121	13,899
Miscellaneous	106	108	109
Total Retail (a)	55,525	48,652	44,318
Wholesale (b)	2,250	2,014	1,922
Total KWhs	57,775	50,666	46,240

(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
	Years Ended December 31,
	2025	2024	2023
	(in degree days)
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

147

Ohio Power Company and Subsidiaries

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

Net Income

(in millions)

Year Ended December 31, 2024	$	306
Changes in Revenues:
Retail Revenues	54
Off-system Sales	56
Transmission Revenues	28
Other Revenues	(18)
Total Change in Revenues	120
Changes in Expenses and Other:
Purchased Electricity for Resale	(67)
Purchased Electricity from AEP Affiliates	33
Other Operation and Maintenance	(66)
Asset Impairments and Other Related Charges	35
Depreciation and Amortization	6
Taxes Other Than Income Taxes	(14)
Other Income	(2)
Allowance for Equity Funds Used During Construction	2
Non-Service Cost Components of Net Periodic Benefit Cost	2
Interest Expense	(10)
Total Change in Expenses and Other	(81)
Income Tax Expense	(20)
Equity Earnings of Unconsolidated Subsidiaries	3
Year Ended December 31, 2025	$	328

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

•Retail Revenues increased $54 million primarily due to the following:

•A $41 million increase in rider revenues.

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

These increases were partially offset by:

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

•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 $28 million primarily due to continued transmission investment.

•Other Revenues decreased $18 million primarily 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.

•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.

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

•Other Operation and Maintenance expenses increased $66 million primarily due to the following:

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

•A $10 million increase in employee-related expenses.

These increases were partially offset by:

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

•A $15 million decrease due to the voluntary severance program that occurred in the second quarter of 2024.

148

•Asset Impairments and Other Related Charges decreased $35 million primarily 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:

•An $18 million increase due to an impairment of in-process internal use software development costs in 2025.

•Depreciation and Amortization expenses decreased $6 million primarily due to capital rider under-recoveries.

•Taxes Other Than Income Taxes increased $14 million primarily due to higher property taxes.

•Interest Expense increased $10 million primarily due to higher debt balances.

•Income Tax Expense increased $20 million primarily due to a decrease in amortization of Excess ADIT.

149

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Ohio Power Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Ohio Power Company and its subsidiaries (the “Company”) as of December 31, 2025 and 2024, and the related consolidated statements of income, 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 $326 million of deferred costs included in regulatory assets and $893 million of regulatory liabilities awaiting potential refund or future rate reduction, $77 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.

150

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.

151

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Ohio Power Company and Subsidiaries (OPCo) 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.  OPCo’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 OPCo’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 OPCo’s internal control over financial reporting was effective as of December 31, 2025.

This annual report does not include an audit report from PricewaterhouseCoopers LLP, OPCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit OPCo to provide only management’s report in this annual report.

152

OHIO POWER COMPANY 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
Electricity, Transmission and Distribution	$	3,891	$	3,793	$	3,768
Sales to AEP Affiliates	45		23		31
Other Revenues	12		12		12
TOTAL REVENUES	3,948		3,828		3,811
EXPENSES
Purchased Electricity for Resale	878		811		1,128
Purchased Electricity from AEP Affiliates	65		98		87
Other Operation	1,267		1,198		1,092
Maintenance	253		256		212
Asset Impairments and Other Related Charges	18		53		—
Depreciation and Amortization	380		386		316
Taxes Other Than Income Taxes	574		560		507
TOTAL EXPENSES	3,435		3,362		3,342
OPERATING INCOME	513		466		469
Other Income (Expense):
Other Income	1		3		1
Allowance for Equity Funds Used During Construction	25		23		17
Non-Service Cost Components of Net Periodic Benefit Cost	17		15		26
Interest Expense	(158)		(148)		(131)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS (LOSS)	398		359		382
Income Tax Expense	72		52		54
Equity Earnings (Loss) of Unconsolidated Subsidiaries	2		(1)		—
NET INCOME	$	328	$	306	$	328
The common stock of OPCo is wholly-owned by Parent.
See Notes to Financial Statements of Registrants beginning on page 182.

153

OHIO POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY

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

(in millions)

	Common Stock		Paid-in Capital		Retained Earnings		Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022	$	321	$	838	$	1,929	$	3,088
Capital Contribution from Parent			175				175
Common Stock Dividends					(20)		(20)
Net Income					328		328
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2023	321		1,013		2,237		3,571
Capital Contribution from Parent			7				7
Net Income					306		306
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2024	321		1,020		2,543		3,884
Capital Contribution from Parent			10				10
Common Stock Dividends					(71)		(71)
Net Income					328		328
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2025	$	321	$	1,030	$	2,800	$	4,151
See Notes to Financial Statements of Registrants beginning on page 182.

154

OHIO POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2025 and 2024

(in millions)

	December 31,
	2025		2024
CURRENT ASSETS
Cash and Cash Equivalents	$	5	$	5
Advances to Affiliates	—		115
Accounts Receivable:
Customers	109		189
Affiliated Companies	132		118
Accrued Unbilled Revenues	29		31
Miscellaneous	—		9
Total Accounts Receivable	270		347
Materials and Supplies	191		141
Prepayments and Other Current Assets	25		20
TOTAL CURRENT ASSETS	491		628
PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission	3,916		3,664
Distribution	7,661		7,244
Other Property, Plant and Equipment	1,289		1,256
Construction Work in Progress	811		691
Total Property, Plant and Equipment	13,677		12,855
Accumulated Depreciation and Amortization	2,993		2,884
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	10,684		9,971
OTHER NONCURRENT ASSETS
Regulatory Assets	326		379
Operating Lease Assets	50		60
Deferred Charges and Other Noncurrent Assets	659		661
TOTAL OTHER NONCURRENT ASSETS	1,035		1,100
TOTAL ASSETS	$	12,210	$	11,699
See Notes to Financial Statements of Registrants beginning on page 182.

155

OHIO POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

December 31, 2025 and 2024

(dollars in millions)

	December 31,
	2025		2024
CURRENT LIABILITIES
Advances from Affiliates	$	79	$	—
Accounts Payable:
General	391		344
Affiliated Companies	197		205
Risk Management Liabilities	5		7
Customer Deposits	108		108
Accrued Taxes	858		836
Obligations Under Operating Leases	13		12
Other Current Liabilities	239		183
TOTAL CURRENT LIABILITIES	1,890		1,695
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	3,718		3,716
Long-term Risk Management Liabilities	28		40
Deferred Income Taxes	1,268		1,201
Regulatory Liabilities and Deferred Investment Tax Credits	893		988
Obligations Under Operating Leases	37		48
Deferred Credits and Other Noncurrent Liabilities	225		127
TOTAL NONCURRENT LIABILITIES	6,169		6,120
TOTAL LIABILITIES	8,059		7,815
Rate Matters (Note 4)
Commitments and Contingencies (Note 6)
COMMON SHAREHOLDER'S EQUITY
Common Stock – No Par Value:
Authorized – 40,000,000 Shares
Outstanding  – 27,952,473 Shares	321		321
Paid-in Capital	1,030		1,020
Retained Earnings	2,800		2,543
TOTAL COMMON SHAREHOLDER’S EQUITY	4,151		3,884
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY	$	12,210	$	11,699
See Notes to Financial Statements of Registrants beginning on page 182.

156

OHIO POWER COMPANY AND SUBSIDIARIES

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	$	328	$	306	$	328
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	380		386		316
Deferred Income Taxes	47		8		8
Asset Impairments and Other Related Charges	18		53		—
Allowance for Equity Funds Used During Construction	(25)		(23)		(17)
Mark-to-Market of Risk Management Contracts	(14)		(3)		11
Property Taxes	(22)		(25)		(12)
Change in Regulatory Assets	30		45		(91)
Change in Other Noncurrent Assets	(32)		(38)		(138)
Change in Other Noncurrent Liabilities	41		58		—
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	77		(170)		73
Materials and Supplies	(32)		55		(7)
Accounts Payable	57		6		24
Accrued Taxes, Net	11		76		28
Other Current Assets	5		(7)		—
Other Current Liabilities	(1)		43		(61)
Net Cash Flows from Operating Activities	868		770		462
INVESTING ACTIVITIES
Construction Expenditures	(1,058)		(930)		(990)
Change in Advances to Affiliates, Net	115		(115)		—
Other Investing Activities	60		34		41
Net Cash Flows Used for Investing Activities	(883)		(1,011)		(949)
FINANCING ACTIVITIES
Capital Contribution from Parent	10		7		175
Issuance of Long-term Debt – Nonaffiliated	—		346		395
Change in Advances from Affiliates, Net	79		(111)		(62)
Principal Payments for Finance Lease Obligations	(4)		(5)		(5)
Dividends Paid on Common Stock	(71)		—		(20)
Other Financing Activities	1		2		1
Net Cash Flows from Financing Activities	15		239		484
Net Decrease in Cash and Cash Equivalents	—		(2)		(3)
Cash and Cash Equivalents at Beginning of Period	5		7		10
Cash and Cash Equivalents at End of Period	$	5	$	5	$	7
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	147	$	139	$	124
Noncash Acquisitions Under Finance Leases	2		2		4
Construction Expenditures Included in Current Liabilities as of December 31,	145		158		98
See Notes to Financial Statements of Registrants beginning on page 182.

157

PUBLIC SERVICE COMPANY OF OKLAHOMA

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	6,197	6,293	6,138
Commercial	5,931	5,673	5,190
Industrial	5,864	5,882	5,932
Miscellaneous	1,265	1,279	1,255
Total Retail	19,257	19,127	18,515
Wholesale (a)	416	179	180
Total KWhs	19,673	19,306	18,695

(a)Includes municipalities and cooperatives, unit power and other wholesale customers.

Summary of Heating and Cooling Degree Days
	Years Ended December 31,
	2025	2024	2023
	(in degree days)
Actual – Heating	1,668	1,311	1,405
Normal – Heating	1,714	1,727	1,750
Actual – Cooling	2,163	2,450	2,330
Normal – Cooling	2,247	2,202	2,190

158

Public Service Company of Oklahoma

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

Net Income

(in millions)

Year Ended December 31, 2024	$	249
Changes in Revenues:
Retail Revenues (a)	172
Transmission Revenues	11
Other Revenues	(7)
Total Change in Revenues	176
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(9)
Other Operation and Maintenance	(101)
Depreciation and Amortization	12
Taxes Other Than Income Taxes	(2)
Allowance for Funds Used During Construction	4
Non-Service Cost Components of Net Periodic Benefit Cost	(3)
Interest Expense	(44)
Total Change in Expenses and Other	(143)
Income Tax Benefit	(30)
Year Ended December 31, 2025	$	252

(a)Includes firm wholesale sales to municipals and cooperatives.

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

•Retail Revenues increased $172 million primarily due to the following:

•A $205 million increase in base rate and rider revenues.

•A $22 million increase in weather-normalized revenues primarily in the residential class partially offset by a decrease in the industrial class.

These increases were partially offset by:

•A $46 million decrease in fuel revenue primarily due to lower authorized fuel rates.

•A $20 million decrease in weather-related usage driven by a 12% decrease in cooling degree days offset by a 27% increase in heating degree days.

•Transmission Revenues increased $11 million primarily due to continued transmission investment and the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•Other Revenues decreased $7 million primarily due to revenues from a customer project to enhance transmission resiliency in 2024.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $9 million primarily due to increased recoverable PTCs and increased fuel and purchased power costs, offset by lower current amortization of under-recovered deferred fuel regulatory assets as a result of lower authorized fuel rates.

•Other Operation and Maintenance expenses increased $101 million primarily due to the following:

•A $62 million increase in transmission expenses primarily due to SPP expenses and the June 2025 FERC NOLC order.

•A $13 million increase in generation expenses primarily due to acquisitions of generation facilities in 2025.

•A $12 million increase in customer service and information expenses driven by energy efficiency programs.

•A $12 million increase in distribution expenses primarily due to overhead line maintenance.

•A $12 million increase in employee-related expenses.

•A $7 million increase due to an impairment of in-process internal use software development costs.

159

These increases were partially offset by:

•A $10 million decrease in expenses from a customer project to enhance transmission resiliency in 2024.

•A $10 million decrease due to the voluntary severance program that occurred in the second quarter of 2024.

•Depreciation and Amortization expenses decreased $12 million primarily due to the following:

•A $43 million decrease due to the under-recovery of regulatory assets related to renewables.

•A $9 million decrease due to the under-recovery of regulatory assets related to Senate Bill 998 and the Dispatchable Resource Rider.

These decreases were partially offset by:

•A $41 million increase due to a higher depreciable base.

•Interest Expense increased $44 million primarily due to higher long-term debt balances 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.

•Income Tax Benefit decreased $30 million primarily due to the following:

•A $48 million decrease due to a reduction in Excess ADIT regulatory liabilities as a result of the IRS PLR received regarding the treatment of standalone NOLCs in retail ratemaking recorded in 2024.

This decrease was partially offset by:

•A $13 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.

160

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Public Service Company of Oklahoma

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Public Service Company of Oklahoma (the “Company”) as of December 31, 2025 and 2024, and the related 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 “financial statements”). In our opinion, the 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 financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to 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 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 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 financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the 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 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 financial statements, the Company's 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 $674 million of deferred costs included in regulatory assets, $84 million of which were pending final regulatory approval, and $717 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.

161

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 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.

162

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Public Service Company of Oklahoma (PSO) 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.  PSO’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 PSO’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 PSO’s internal control over financial reporting was effective as of December 31, 2025.

This annual report does not include an audit report from PricewaterhouseCoopers LLP, PSO’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit PSO to provide only management’s report in this annual report.

163

PUBLIC SERVICE COMPANY OF OKLAHOMA

STATEMENTS OF INCOME

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

(in millions)

	Years Ended December 31,
	2025		2024		2023
REVENUES
Electric Generation, Transmission and Distribution	$	2,002	$	1,820	$	1,968
Sales to AEP Affiliates	9		7		1
Other Revenues	11		19		8
TOTAL REVENUES	2,022		1,846		1,977
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	752		743		955
Other Operation	501		416		356
Maintenance	129		113		112
Depreciation and Amortization	260		272		256
Taxes Other Than Income Taxes	79		77		64
TOTAL EXPENSES	1,721		1,621		1,743
OPERATING INCOME	301		225		234
Other Income (Expense):
Interest Income	2		2		2
Allowance for Equity Funds Used During Construction	11		7		8
Non-Service Cost Components of Net Periodic Benefit Cost	8		11		14
Interest Expense	(140)		(96)		(103)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	182		149		155
Income Tax Expense (Benefit)	(70)		(100)		(54)
NET INCOME	$	252	$	249	$	209
The common stock of PSO is wholly-owned by Parent.
See Notes to Financial Statements of Registrants beginning on page 182.

164

PUBLIC SERVICE COMPANY OF OKLAHOMA

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	$	252	$	249	$	209
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0, $1 and $0 in 2025, 2024 and 2023, Respectively	(1)		4		(2)
TOTAL COMPREHENSIVE INCOME	$	251	$	253	$	207
See Notes to Financial Statements of Registrants beginning on page 182.

165

PUBLIC SERVICE COMPANY OF OKLAHOMA

STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S EQUITY

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

(in millions)

	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2022	$	157	$	1,043	$	1,218	$	1	$	2,419
Capital Contribution from Parent			1						1
Return of Capital to Parent			(4)						(4)
Common Stock Dividends					(52)				(52)
Net Income					209				209
Other Comprehensive Loss							(2)		(2)
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2023	157		1,040		1,375		(1)		2,571
Capital Contribution from Parent			2						2
Common Stock Dividends					(140)				(140)
Net Income					249				249
Other Comprehensive Income							4		4
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2024	157		1,042		1,484		3		2,686
Capital Contribution from Parent			676						676
Net Income					252				252
Other Comprehensive Loss							(1)		(1)
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2025	$	157	$	1,718	$	1,736	$	2	$	3,613
See Notes to Financial Statements of Registrants beginning on page 182.

166

PUBLIC SERVICE COMPANY OF OKLAHOMA

BALANCE SHEETS

ASSETS

December 31, 2025 and 2024

(in millions)

	December 31,
	2025		2024
CURRENT ASSETS
Cash and Cash Equivalents	$	2	$	2
Advances to Affiliates	—		232
Accounts Receivable:
Customers	109		75
Affiliated Companies	45		33
Miscellaneous	4		—
Total Accounts Receivable	158		108
Fuel	3		17
Materials and Supplies	119		109
Risk Management Assets	42		21
Accrued Tax Benefits	8		36
Regulatory Asset for Under-Recovered Fuel Costs	37		65
Prepayments and Other Current Assets	14		18
TOTAL CURRENT ASSETS	383		608
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	4,365		2,772
Transmission	1,433		1,345
Distribution	3,987		3,699
Other Property, Plant and Equipment	1,292		550
Construction Work in Progress	635		379
Total Property, Plant and Equipment	11,712		8,745
Accumulated Depreciation and Amortization	2,748		2,213
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	8,964		6,532
OTHER NONCURRENT ASSETS
Regulatory Assets	637		528
Employee Benefits and Pension Assets	95		74
Operating Lease Assets	126		106
Deferred Charges and Other Noncurrent Assets	13		62
TOTAL OTHER NONCURRENT ASSETS	871		770
TOTAL ASSETS	$	10,218	$	7,910
See Notes to Financial Statements of Registrants beginning on page 182.

167

PUBLIC SERVICE COMPANY OF OKLAHOMA

BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

December 31, 2025 and 2024

	December 31,
	2025		2024
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	171	$	—
Accounts Payable:
General	339		201
Affiliated Companies	87		59
Long-term Debt Due Within One Year – Nonaffiliated	51		126
Risk Management Liabilities	27		6
Customer Deposits	115		73
Accrued Taxes	37		33
Accrued Interest	67		33
Obligations Under Operating Leases	11		10
Other Current Liabilities	104		78
TOTAL CURRENT LIABILITIES	1,009		619
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	3,475		2,730
Deferred Income Taxes	1,113		931
Regulatory Liabilities and Deferred Investment Tax Credits	717		690
Asset Retirement Obligations	136		119
Obligations Under Operating Leases	122		102
Deferred Credits and Other Noncurrent Liabilities	33		33
TOTAL NONCURRENT LIABILITIES	5,596		4,605
TOTAL LIABILITIES	6,605		5,224
Rate Matters (Note 4)
Commitments and Contingencies (Note 6)
COMMON SHAREHOLDER’S EQUITY
Common Stock – Par Value – $15 Per Share:
Authorized – 11,000,000 Shares
Issued – 10,482,000 Shares
Outstanding – 9,013,000 Shares	157		157
Paid-in Capital	1,718		1,042
Retained Earnings	1,736		1,484
Accumulated Other Comprehensive Income (Loss)	2		3
TOTAL COMMON SHAREHOLDER’S EQUITY	3,613		2,686
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	10,218	$	7,910
See Notes to Financial Statements of Registrants beginning on page 182.

168

PUBLIC SERVICE COMPANY OF OKLAHOMA

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	$	252	$	249	$	209
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	260		272		256
Deferred Income Taxes	150		21		8
Allowance for Equity Funds Used During Construction	(11)		(7)		(8)
Mark-to-Market of Risk Management Contracts	2		(27)		33
Deferred Fuel Over/Under-Recovery, Net	28		54		313
Change in Other Regulatory Assets	(54)		—		(108)
Change in Other Noncurrent Assets	4		(45)		(71)
Change in Other Noncurrent Liabilities	3		7		8
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(50)		32		(16)
Fuel, Materials and Supplies	8		15		(17)
Accounts Payable	68		18		(58)
Accrued Taxes, Net	31		(2)		(13)
Other Current Assets	2		(4)		10
Other Current Liabilities	52		(34)		45
Net Cash Flows from Operating Activities	745		549		591
INVESTING ACTIVITIES
Construction Expenditures	(824)		(598)		(562)
Change in Advances to Affiliates, Net	232		(232)		—
Acquisitions of Generation Facilities	(1,676)		—		(146)
Other Investing Activities	10		5		15
Net Cash Flows Used for Investing Activities	(2,258)		(825)		(693)
FINANCING ACTIVITIES
Capital Contribution from Parent	676		2		1
Return of Capital to Parent	—		—		(4)
Issuance of Long-term Debt – Nonaffiliated	793		596		470
Change in Advances from Affiliates, Net	171		(54)		(310)
Retirement of Long-term Debt – Nonaffiliated	(126)		(126)		(1)
Principal Payments for Finance Lease Obligations	(3)		(3)		(3)
Dividends Paid on Common Stock	—		(140)		(52)
Other Financing Activities	2		—		—
Net Cash Flows from Financing Activities	1,513		275		101
Net Decrease in Cash and Cash Equivalents	—		(1)		(1)
Cash and Cash Equivalents at Beginning of Period	2		3		4
Cash and Cash Equivalents at End of Period	$	2	$	2	$	3
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	106	$	102	$	87
Noncash Acquisitions Under Finance Leases	2		2		2
Construction Expenditures Included in Current Liabilities as of December 31,	185		88		73
See Notes to Financial Statements of Registrants beginning on page 182.

169

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

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	6,276	6,081	6,138
Commercial	5,662	5,588	5,538
Industrial	5,155	5,157	5,147
Miscellaneous	67	69	71
Total Retail	17,160	16,895	16,894
Wholesale (a)	5,804	5,467	5,429
Total KWhs	22,964	22,362	22,323

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

Summary of Heating and Cooling Degree Days
	Years Ended December 31,
	2025	2024	2023
	(in degree days)
Actual – Heating	1,023	780	727
Normal – Heating	1,143	1,158	1,174
Actual – Cooling	2,868	3,041	2,853
Normal – Cooling	2,370	2,382	2,365

170

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

Earnings Attributable to SWEPCo Common Shareholder

(in millions)

Year Ended December 31, 2024	$	321
Changes in Revenues:
Retail Revenues (a)	264
Off-system Sales	1
Transmission Revenues	50
Other Revenues	3
Total Change in Revenues	318
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	6
Other Operation and Maintenance	(80)
Asset Impairments and Other Related Charges	(6)
Depreciation and Amortization	(40)
Taxes Other Than Income Taxes	(4)
Interest Income	(3)
Allowance for Equity Funds Used During Construction	9
Non-Service Cost Components of Net Periodic Benefit Cost	6
Interest Expense	(51)
Total Change in Expenses and Other	(163)
Income Tax Benefit	(89)
Equity Earnings of Unconsolidated Subsidiary	(1)
Net Income Attributable to Noncontrolling Interest	2
Year Ended December 31, 2025	$	388

(a)Includes firm wholesale sales to municipals and cooperatives.

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

•Retail Revenues increased $264 million primarily due to the following:

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

•A $106 million increase in rider revenues.

•Transmission Revenues increased $50 million primarily due to the following:

•A $35 million increase due to continued transmission investment.

•A $27 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

These increases were partially offset by:

•A $12 million decrease due to a provision for refund related to probable over-recovery of FERC transmission formula rates.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $6 million primarily due to a current year decrease in amortization of under-recovered deferred fuel regulatory assets.

•Other Operation and Maintenance expenses increased $80 million primarily due to the following:

•A $51 million increase in transmission expenses primarily due to:

•A $29 million increase due to continued transmission investment.

•A $10 million increase related to the June 2025 FERC NOLC order.

•An $8 million increase in vegetation management expenses.

•A $32 million increase in distribution expenses primarily due to an increase in vegetation management and storm-related costs.

•A $14 million increase in employee-related expenses.

•A $12 million increase in renewable generation operation and maintenance expenses.

171

These increases were partially offset by:

•A $17 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 $6 million due to an impairment of in-process internal use software development costs.

•Depreciation and Amortization expenses increased $40 million primarily due to the following:

•A $31 million increase due to a higher depreciable base.

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

•A $6 million increase due to the amortization of an NOLC regulatory asset recognized in 2025.

These increases were partially offset by:

•An $18 million decrease due to the under-recovery of regulatory assets related to renewables.

•Allowance for Equity Funds Used During Construction increased $9 million primarily due to increased AFUDC base and rates.

•Non-Service Cost Components of Net Periodic Benefit Cost decreased $6 million primarily due to a plan remeasurement triggered by settlements related to the voluntary severance program in 2024.

•Interest Expense increased $51 million primarily due to the following:

•A $28 million increase associated with Storm Recovery Funding securitization bonds.

•A $28 million increase due to a prior year deferral of expenses in Texas as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking.

•Income Tax Benefit decreased $89 million primarily due to the following:

•A $109 million decrease due to a reduction in Excess ADIT regulatory liabilities as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking recorded in 2024.

•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.

•A $32 million decrease due to an increase in pretax book income.

These decreases were partially offset by:

•A $42 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.

•A $27 million increase due to an increase in PTCs.

•A $14 million increase due to a decrease in state taxes.

172

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Southwestern Electric Power Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Southwestern Electric Power Company 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 (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 $1,018 million of deferred costs included in regulatory assets, $445 million of which were pending final regulatory approval, and $576 million of regulatory liabilities awaiting potential refund or future rate reduction, $7 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.

173

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.

174

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Southwestern Electric Power Company Consolidated (SWEPCo) 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.  SWEPCo’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 SWEPCo’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 SWEPCo’s internal control over financial reporting was effective as of December 31, 2025.

This annual report does not include an audit report from PricewaterhouseCoopers LLP, SWEPCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit SWEPCo to provide only management’s report in this annual report.

175

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

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 Generation, Transmission and Distribution	$	2,281	$	2,149	$	2,155
Sales to AEP Affiliates	71		71		82
(Provision for)/Reversal of – Revenue Refund – Affiliated	12		(9)		(35)
Provision for Refund	(20)		(182)		(21)
Other Revenues	10		7		2
TOTAL REVENUES	2,354		2,036		2,183
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	727		733		807
Other Operation	458		423		361
Maintenance	194		149		159
Asset Impairments and Other Related Charges	6		—		86
Depreciation and Amortization	429		389		343
Taxes Other Than Income Taxes	129		125		135
TOTAL EXPENSES	1,943		1,819		1,891
OPERATING INCOME	411		217		292
Other Income (Expense):
Interest Income	11		14		19
Allowance for Equity Funds Used During Construction	23		14		11
Non-Service Cost Components of Net Periodic Benefit Cost	7		1		14
Interest Expense	(157)		(106)		(147)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS	295		140		189
Income Tax Expense (Benefit)	(95)		(184)		(33)
Equity Earnings of Unconsolidated Subsidiary	1		2		2
NET INCOME	391		326		224
Net Income Attributable to Noncontrolling Interest	3		5		4
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	388	$	321	$	220
The common stock of SWEPCo is wholly-owned by Parent.
See Notes to Financial Statements of Registrants beginning on page 182.

176

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

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	$	391	$	326	$	224
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
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 $1, $2 and $1 in 2025, 2024 and 2023, Respectively	5		6		2
TOTAL OTHER COMPREHENSIVE INCOME	5		6		1
TOTAL COMPREHENSIVE INCOME	396		332		225
Total Comprehensive Income Attributable to Noncontrolling Interest	3		5		4
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	393	$	327	$	221
See Notes to Financial Statements of Registrants beginning on page 182.

177

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

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

(in millions)

	SWEPCo Common Shareholder
	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interest		Total
TOTAL EQUITY – DECEMBER 31, 2022	$	—	$	1,442	$	2,236	$	(4)	$	1	$	3,675
Capital Contribution from Parent			50								50
Common Stock Dividends					(175)						(175)
Common Stock Dividends – Nonaffiliated									(5)		(5)
Net Income					220				4		224
Other Comprehensive Income							1				1
TOTAL EQUITY – DECEMBER 31, 2023	—		1,492		2,281		(3)		—		3,770
Capital Contribution from Parent			59								59
Return of Capital to Parent			(1)								(1)
Common Stock Dividends					(250)						(250)
Common Stock Dividends – Nonaffiliated									(5)		(5)
Net Income					321				5		326
Other Comprehensive Income							6				6
TOTAL EQUITY – DECEMBER 31, 2024	—		1,550		2,352		3		—		3,905
Capital Contribution from Parent			601								601
Common Stock Dividends – Nonaffiliated									(3)		(3)
Net Income					388				3		391
Other Comprehensive Income							5				5
TOTAL EQUITY – DECEMBER 31, 2025	$	—	$	2,151	$	2,740	$	8	$	—	$	4,899
See Notes to Financial Statements of Registrants beginning on page 182.

178

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2025 and 2024

(in millions)

	December 31,
	2025		2024
CURRENT ASSETS
Cash and Cash Equivalents	$	2	$	2
Restricted Cash (December 31, 2025 and 2024 Amounts Include $15 and $3, Respectively, Related to Storm Recovery Funding)	15		3
Advances to Affiliates	23		2
Accounts Receivable:
Customers	63		35
Affiliated Companies	91		54
Miscellaneous	10		9
Total Accounts Receivable	164		98
Fuel	83		87
Materials and Supplies (December 31, 2025 and 2024 Amounts Include $1 and $2, Respectively, Related to Sabine)	88		81
Risk Management Assets	35		18
Accrued Tax Benefits	17		26
Regulatory Asset for Under-Recovered Fuel Costs	115		107
Prepayments and Other Current Assets	14		14
TOTAL CURRENT ASSETS	556		438
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	6,621		5,288
Transmission	3,302		2,864
Distribution	3,242		3,007
Other Property, Plant and Equipment (December 31, 2025 and 2024 Amounts Include $125 and $167, Respectively, Related to Sabine)	942		940
Construction Work in Progress	712		627
Total Property, Plant and Equipment	14,819		12,726
Accumulated Depreciation and Amortization (December 31, 2025 and 2024 Amounts Include $125 and $167, Respectively, Related to Sabine)	3,478		3,280
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	11,341		9,446
OTHER NONCURRENT ASSETS
Regulatory Assets	903		921
Securitized Assets (December 31, 2025 and 2024 Amounts Include $315 and $331, Respectively, Related to Storm Recovery Funding)	315		331
Deferred Charges and Other Noncurrent Assets	409		359
TOTAL OTHER NONCURRENT ASSETS	1,627		1,611
TOTAL ASSETS	$	13,524	$	11,495
See Notes to Financial Statements of Registrants beginning on page 182.

179

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

December 31, 2025 and 2024

	December 31,
	2025		2024
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	—	$	275
Accounts Payable:
General	392		265
Affiliated Companies	89		57
Short-term Debt – Nonaffiliated	3		6
Long-term Debt Due Within One Year – Nonaffiliated (December 31, 2025 and 2024 Amounts Include $17 and $23, Respectively, Related to Storm Recovery Funding)	917		23
Risk Management Liabilities	9		2
Customer Deposits	79		75
Accrued Taxes	68		49
Accrued Interest	49		41
Obligations Under Operating Leases	7		8
Provision for Refund	81		71
Other Current Liabilities	191		160
TOTAL CURRENT LIABILITIES	1,885		1,032
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated (December 31, 2025 and 2024 Amounts Include $304 and $309, Respectively, Related to Storm Recovery Funding)	3,057		3,958
Long-term Debt – Affiliated	1,000		—
Deferred Income Taxes	1,458		1,271
Regulatory Liabilities and Deferred Investment Tax Credits	531		611
Asset Retirement Obligations	252		257
Employee Benefits and Pension Obligations	39		46
Obligations Under Operating Leases	195		138
Provision for Refund	47		108
Storm Reserve	108		106
Deferred Credits and Other Noncurrent Liabilities	53		63
TOTAL NONCURRENT LIABILITIES	6,740		6,558
TOTAL LIABILITIES	8,625		7,590
Rate Matters (Notes 4)
Commitments and Contingencies (Note 6)
EQUITY
Common Stock – Par Value – $18 Per Share:
Authorized – 3,680 Shares
Outstanding – 3,680 Shares	—		—
Paid-in Capital	2,151		1,550
Retained Earnings	2,740		2,352
Accumulated Other Comprehensive Income (Loss)	8		3
TOTAL COMMON SHAREHOLDER’S EQUITY	4,899		3,905
Noncontrolling Interest	—		—
TOTAL EQUITY	4,899		3,905
TOTAL LIABILITIES AND EQUITY	$	13,524	$	11,495
See Notes to Financial Statements of Registrants beginning on page 182.

180

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

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	$	391	$	326	$	224
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	429		389		343
Deferred Income Taxes	82		(74)		54
Asset Impairments and Other Related Charges	6		—		86
Allowance for Equity Funds Used During Construction	(23)		(14)		(11)
Mark-to-Market of Risk Management Contracts	(8)		(20)		19
Deferred Fuel Over/Under-Recovery, Net	104		156		184
Provision for Refund – Turk Plant	—		79		—
Change in Other Noncurrent Assets	(36)		(69)		(102)
Change in Other Noncurrent Liabilities	(125)		(41)		11
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(66)		(3)		20
Fuel, Materials and Supplies	(3)		29		(31)
Accounts Payable	77		3		(8)
Accrued Taxes, Net	28		(8)		(5)
Provision for Refund – Turk Plant	—		68		—
Other Current Assets	7		10		20
Other Current Liabilities	12		(14)		(1)
Net Cash Flows from Operating Activities	875		817		803
INVESTING ACTIVITIES
Construction Expenditures	(935)		(741)		(781)
Change in Advances to Affiliates, Net	(21)		—		—
Acquisition of Renewable Energy Facilities	(1,229)		(399)		—
Other Investing Activities	14		11		4
Net Cash Flows Used for Investing Activities	(2,171)		(1,129)		(777)
FINANCING ACTIVITIES
Capital Contribution from Parent	601		59		50
Return of Capital to Parent	—		(1)		—
Issuance of Long-term Debt – Nonaffiliated	—		336		347
Issuance of Long-term Debt – Affiliated	1,000		—		—
Change in Short-term Debt – Nonaffiliated	(3)		1		4
Change in Advances from Affiliates, Net	(275)		186		(222)
Retirement of Long-term Debt – Nonaffiliated	(11)		—		(94)
Principal Payments for Finance Lease Obligations	(4)		(14)		(19)
Dividends Paid on Common Stock	—		(250)		(175)
Dividends Paid on Common Stock – Nonaffiliated	(3)		(5)		(5)
Other Financing Activities	3		2		2
Net Cash Flows from (Used for) Financing Activities	1,308		314		(112)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	12		2		(86)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	5		3		89
Cash, Cash Equivalents and Restricted Cash at End of Period	$	17	$	5	$	3
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	156	$	139	$	129
Noncash Acquisitions Under Finance Leases	3		2		7
Construction Expenditures Included in Current Liabilities as of December 31,	225		137		64
See Notes to Financial Statements of Registrants beginning on page 182.

181

INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANTS

The notes to financial statements are a combined presentation for the Registrants. The following list indicates Registrants to which the notes apply. Specific disclosures within each note apply to all Registrants unless indicated otherwise.

Note	Registrant	Page Number
Organization and Summary of Significant Accounting Policies	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	183
New Accounting Standards	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	197
Comprehensive Income	AEP	199
Rate Matters	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	201
Effects of Regulation	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	214
Commitments, Guarantees and Contingencies	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	232
Acquisitions, Dispositions and Impairments	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	238
Benefit Plans	AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo	242
Business Segments	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	258
Derivatives and Hedging	AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo	263
Fair Value Measurements	AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo	272
Income Taxes	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	283
Leases	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	292
Voluntary Severance Program	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	297
Financing Activities	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	298
Stock-based Compensation	AEP	307
Related Party Transactions	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	311
Variable Interest Entities and Equity Method Investments	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	315
Property, Plant and Equipment	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	323
Revenue from Contracts with Customers	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	329

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1.  ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The disclosures in this note apply to all Registrants unless indicated otherwise.

ORGANIZATION

The Registrants engage in the generation, transmission and distribution of electric power.  The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines.  Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions.

AEP also provides competitive electric and gas supply for residential, commercial and industrial customers in deregulated electricity markets. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services.  I&M provides barging services to both affiliated and nonaffiliated companies.  

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rates and Service Regulation

AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate.  The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over certain issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company.  The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes.  Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system.

The FERC regulates wholesale power markets and wholesale power transactions.  The Registrants’ wholesale power transactions are generally market-based.  Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs.  Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts.  These contracts are generally formula rate mechanisms, which are trued-up to actual costs annually.  

The state regulatory commissions regulate all of the retail distribution operations and rates of AEP’s retail public utility subsidiaries on a cost basis.  The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas.  For generation in Ohio, customers who have not switched to a CRES provider for generation receive SSO from OPCo and pay market-based auction rates. In the ERCOT region of Texas, AEP Texas customers are required to choose an REP for generation service and pay market-based rates. 

The FERC also regulates the Registrants’ wholesale transmission operations and rates.  Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring.  Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEPTCo’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based.

In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis.

In addition, the FERC regulates the Operating Agreement, TA and TCA, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement.  The FERC also regulates the PCA. See Note 17 - Related Party Transactions for additional information.

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Principles of Consolidation

AEP and the Registrant Subsidiaries’ consolidated financial statements include wholly-owned subsidiaries and VIEs, of which AEP or a Registrant Subsidiary is the primary beneficiary. Intercompany items are eliminated in consolidation.  

The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest.  Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings or losses is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income.

AEP, I&M, PSO and SWEPCo have undivided ownership interests in generating units that are jointly-owned.  The proportionate share of the operating costs associated with such facilities is included on the income statements and the assets and liabilities are reflected on the balance sheets.  See Note 18 - Variable Interest Entities and Equity Method Investments and Note 19 - Property, Plant and Equipment for additional information.

Accounting for the Effects of Cost-Based Regulation

The Registrants’ 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.  In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred 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 by matching income with its passage to customers in cost-based regulated rates.

Use of Estimates

The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes.  These estimates include, but are not limited to, inventory valuation, allowance for credit losses, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, AROs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits.  The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements.  Actual results could ultimately differ from those estimates.

Cash and Cash Equivalents

Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.

Restricted Cash (Applies to AEP, AEP Texas, APCo and SWEPCo)

Restricted Cash primarily includes funds held by trustees for the payment of securitization bonds.

Reconciliation of Cash, Cash Equivalents and Restricted Cash

The following tables provide a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the balance sheets that sum to the total of the same amounts shown on the statement of cash flows:

	AEP				AEP Texas				APCo				SWEPCo
	Year Ended December 31,
	2025		2024		2025		2024		2025		2024		2025		2024
	(in millions)
Cash and Cash Equivalents	$	197	$	203	$	—	$	—	$	5	$	4	$	2	$	2
Restricted Cash	71		43		14		24		18		16		15		3
Total Cash, Cash Equivalents and Restricted Cash	$	268	$	246	$	14	$	24	$	23	$	20	$	17	$	5

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Other Temporary Investments (Applies to AEP)

Other Temporary Investments primarily include marketable securities and investments by its protected cell of EIS. These securities have readily determinable fair values and are carried at fair value with changes in fair value recognized in net income.  The cost of securities sold is based on the specific identification or weighted-average cost method. See “Fair Value Measurements of Other Temporary Investments” section of Note 11 for additional information.

Inventory

Fossil fuel inventories are carried at average cost with the exception of AGR, which carries these inventories at the lower of average cost or net realizable value.  Materials and supplies inventories are carried at average cost.

Accounts Receivable and Allowance for Credit Losses

Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities.

Revenue is recognized over time as the performance obligations of delivering energy to customers are satisfied.  To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing.

AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo.  Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit.  AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for a portion of its interests in the billed and unbilled receivables acquired from the affiliated utility subsidiaries. See “Securitized Accounts Receivable – AEP Credit” section of Note 15 for additional information.

Generally, AEP Credit recognizes bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. The assessment is performed separately for each participating AEP subsidiary, which inherently contemplates any differences in geographical risk characteristics for the allowance for credit losses. For receivables related to APCo’s West Virginia operations, the allowance for credit losses is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable.

For customer accounts receivables relating to risk management activities, accounts receivable are reviewed for potential credit losses at a specific counterparty level basis. For AEP Texas, allowances for credit losses are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recognized based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable, unless specifically identified.

In addition to these processes, management contemplates available current information, as well as any reasonable and supportable forecast information, to determine if allowances for credit losses should be further adjusted in accordance with the accounting guidance for “Credit Losses.” Management’s assessments contemplate expected losses over the life of the accounts receivable.

Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries)

APCo, I&M, OPCo, PSO and SWEPCo do not have any significant customers that comprise 10% or more of their operating revenues. AEP Texas had significant customers which account for the following percentages of Total Revenues for the years ended December 31 and Accounts Receivable – Customers as of December 31:

Significant Customers of AEP Texas:
NRG Energy and Vistra Corp	2025		2024		2023
Percentage of Total Revenues	38	%	40	%	41	%
Percentage of Accounts Receivable – Customers	33	%	37	%	34	%

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AEPTCo had significant transactions with AEP Subsidiaries which on a combined basis account for the following percentages of Total Revenues for the years ended December 31 and Total Accounts Receivable as of December 31:

Significant Customers of AEPTCo:
AEP Subsidiaries	2025		2024		2023
Percentage of Total Revenues	81	%	80	%	79	%
Percentage of Total Accounts Receivable	62	%	69	%	60	%

The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuous basis to minimize credit risk.  The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs.  Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements.

Renewable Energy Credits (Applies to all Registrants except AEP Texas and AEPTCo)

In regulated jurisdictions, the Registrants record renewable energy credits (RECs) at cost.  For RECs acquired in AEP’s nonregulated operations within the Generation & Marketing segment, management records those RECs at the lower of cost or net realizable value.  The Registrants follow the inventory model for these RECs.  RECs are reported in Materials and Supplies on the balance sheets.  The purchases and sales of RECs are reported in the Operating Activities section of the statements of cash flows. RECs that are consumed to meet applicable state renewable portfolio standards are recorded in Purchased Electricity, Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income.  The net margin on sales of RECs affects the determination of deferred fuel and REC costs.

Property, Plant and Equipment

Regulated

Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts.  Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation.  The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss.  The equipment in each primary electric plant account is identified as a separate group.  The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received.  These rates and the related lives are subject to periodic review.  Removal costs accrued are typically recorded as regulatory liabilities when the revenue received for removal costs accrued exceeds actual removal costs incurred. The removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued.

The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses.

Nuclear fuel, including nuclear fuel in the fabrication phase, is included in Other Property, Plant and Equipment on the balance sheets.

Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.”  When it becomes probable that an asset in-service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed or is not probable, the cost of that asset shall be written down to its then current estimated fair value, with the change charged to expense, and the asset is removed from plant-in-service or CWIP.

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, as opposed to 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, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.

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Nonregulated

Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions.  Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals.  Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation.  A gain or loss would be recorded if the retirement is not considered an interim routine replacement.  Removal costs are charged to expense when incurred.

Allowance for Funds Used During Construction and Interest Capitalization

For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant.  The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense on the statements of income.  For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”

Asset Retirement Obligations (Applies to all Registrants except AEPTCo)

The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, wind farms, solar farms and certain coal-mining facilities. I&M records ARO for the decommissioning of the Cook Plant. Certain registrants also record AROs related to the Federal EPA’s revised CCR Rule. For operating facilities, the present value of the liability is added to the cost of the associated asset and depreciated over the remaining life of the asset. For retired facilities, the present value of the liability is expensed, and where future recovery through rates is probable, the present value of the liability is subsequently deferred as a regulatory asset.

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. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be decommissioned and the liabilities will be remediated as well as the inflation rate and discount rate, which may change significantly over time. The estimated costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected.

Valuation of Nonderivative Financial Instruments

The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments.

Fair Value Measurements of Assets and Liabilities (Applies to all Registrants except AEPTCo)

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value.  Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.

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For commercial activities, exchange-traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange-traded derivatives where there is insufficient market liquidity to warrant inclusion in Level 1.  Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated.  Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace.  When multiple broker quotes are obtained, the quoted bid and ask prices are averaged.  In certain circumstances, a broker quote may be discarded if it is a clear outlier.  Management uses a historical correlation analysis between the broker quoted location and the illiquid locations.  If the points are highly correlated, these locations are included within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket-based inputs.  Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.  The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market.  A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility.

AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts.  AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value.  AEP’s management performs its own valuation testing to verify the fair values of the securities.  AEP receives audit reports of the trustee’s operating controls and valuation processes.  

Assets in the benefits and nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and equity securities.  They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets.  Items classified as Level 2 are primarily investments in individual fixed income securities.  Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and matrices.  The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.  Investments classified as Other are valued using Net Asset Value as a practical expedient. Items classified as Other are primarily cash equivalent funds, common collective trusts, commingled funds, structured products, private equity, real estate and infrastructure investments. These investments do not have a readily determinable fair value or they contain redemption restrictions which may include the right to suspend redemptions under certain circumstances. Redemption restrictions may also prevent certain investments from being redeemed at the reporting date for the underlying value.

Deferred Fuel Costs (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

The cost of purchased electricity, fuel and related emission allowances and emission control chemicals/consumables is charged to Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily using the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is an expectation that refunds or recoveries will extend beyond a one year period, based on a company’s filing with a commission or a commission directive. These deferrals are incorporated into the development of future fuel rates billed to or refunded to customers. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. The Registrants share the majority of their Off-system Sales margins to customers either through an active FAC or other rate mechanisms. Where the FAC or Off-system Sales sharing mechanism is capped, frozen, non-existent or applicable to merchant operations, changes in fuel costs or sharing of Off-system Sales impact earnings.

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Revenue Recognition

Regulatory Accounting

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.  Regulatory assets (deferred expenses or alternative revenues recognized in accordance with the guidance for “Regulated Operations”) and regulatory liabilities (deferred 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 by matching revenue with its passage to customers in cost-based regulated rates.

When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets.  Regulatory assets are reviewed for probability of recovery at each balance sheet date or whenever new events occur.  Examples of new events include the issuance of a regulatory commission order or passage of new legislation.  If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is derecognized as a charge against income.

Retail and Wholesale Supply and Delivery of Electricity

The Registrants recognize revenues from customers for retail and wholesale electricity sales and electricity transmission and distribution delivery services.  The Registrants recognize such revenues on the statements of income as the performance obligations of delivering energy to customers are satisfied. Recognized revenues include both billed and unbilled amounts.  In accordance with the applicable state commission’s regulatory treatment, PSO and SWEPCo do not include the fuel portion in unbilled revenue, but rather recognize such revenues when billed to customers.

Wholesale transmission revenue is based on FERC-approved formula rate filings made for each calendar year using estimated costs. Revenues initially recognized per the annual rate filing are compared to actual costs, resulting in the subsequent recognition of an over or under-recovered amount, with interest, that is refunded or recovered, respectively, in a future year’s rates. These annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations”. An estimated annual true-up is recorded by the Registrants in the fourth quarter of each calendar year and a final annual true-up is recognized by the Registrants in the second quarter of each calendar year following the filing of annual FERC reports. Any portion of the true-ups applicable to an affiliated company is recorded as Accounts Receivable - Affiliated Companies or Accounts Payable - Affiliated Companies on the balance sheets. Any portion of the true-ups applicable to third-parties is recorded as Regulatory Assets or Regulatory Liabilities on the balance sheets. See Note 20 - Revenue from Contracts with Customers for additional information.

Gross versus Net Presentation of Certain Electricity Supply and Delivery Activities

Most of the power produced at the generation plants is sold to PJM or SPP.  The Registrants also purchase power from PJM and SPP to supply power to customers.  Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income.  However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of AEP’s nonregulated subsidiaries are reported as gross purchases or sales.

Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income.  Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances.  Certain derivatives that economically hedge future commodity risk are recorded in the same line item on the statements of income as that of the associated risk being hedged. Realized gains and losses on cash flow hedges are recorded in Total Revenues or Purchased Electricity depending on the nature of the risk being hedged. Derivative purchases elected normal used to serve accrual based obligations are recorded in Purchased Electricity on the statements of income.  All other non-trading derivative purchases are recorded net in revenues.

In general, the Registrants record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated.  In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

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Energy Marketing and Risk Management Activities (Applies to all Registrants except AEPTCo)

The Registrants engage in power, capacity, and to a lesser extent, natural gas marketing as major power producers and participants in electricity and natural gas markets. The Registrants also engage in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and on adjacent markets.  These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices.  These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options.  Certain energy marketing and risk management transactions are with RTOs.

The Registrants recognize revenues from marketing and risk management transactions that are not derivatives as the performance obligation of delivering the commodity is satisfied. Expenses from marketing and risk management transactions that are not derivatives are also recognized upon delivery of the commodity.

The Registrants use MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election. Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities, as appropriate, and on the statements of income in Total Revenues. Realized gains and losses on marketing and risk management transactions are included in revenues or expenses based on the transaction’s facts and circumstances. However, in regulated jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge).  In the event the Registrants designate a cash flow hedge, the cash flow hedge’s gain or loss is initially recorded as a component of AOCI.  When the forecasted transaction is realized and affects net income, the Registrants subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. See “Accounting for Cash Flow Hedging Strategies” section of Note 10 for additional information.

Levelization of Nuclear Refueling Outage Costs (Applies to AEP and I&M)

In accordance with regulatory orders, I&M defers incremental operation and maintenance costs associated with periodic refueling outages at its Cook Plant and amortizes the costs over approximately 18 months, beginning with the month following the start of each unit’s refueling outage and lasting until the end of the month in which the same unit’s next scheduled refueling outage begins.

Maintenance

The Registrants expense maintenance costs as incurred.  If it becomes probable that the Registrants will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues.  In certain regulated jurisdictions, the Registrants defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.

Income Taxes and Investment and Production Tax Credits

The Registrants use the liability method of accounting for income taxes.  Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled.

When the flow-through method of accounting for temporary differences is required by a regulator to be reflected in regulated revenues (that is, when deferred taxes are not included in the cost-of-service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense.

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AEP and subsidiaries apply the deferral methodology for the recognition of ITCs. Deferred ITCs are amortized to income tax expense over the life of the asset that generated the credit. Amortization of deferred ITCs begins when the asset is placed in-service, except where regulatory commissions reflect ITCs in the ratemaking process, then amortization begins when the utility is able to utilize the ITC on a stand-alone basis. Alternatively, PTCs reduce income tax expense as they are earned. PTCs are earned when electricity is produced. Absent IRS guidance on the calculation of “gross receipts”, the Nuclear PTC recognized is based on electricity produced and an estimate of gross receipts. If, and when, IRS guidance is issued, the value of the Nuclear PTC will be updated to reflect such guidance, if necessary.

Transferable tax credits established by the IRA are accounted for in accordance with the accounting guidance for “Income Taxes” by the Registrants. Proceeds from sales of transferable tax credits are included as a component of Operating Activities on the statement of cash flows and presented as net within the Income Taxes Footnote.

The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.”  The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense on the statements of income.

AEP and subsidiaries join in the filing of a consolidated federal income tax return. The benefit of current tax loss of the parent company (Parent Company Loss Benefit) to the AEP System subsidiaries is accounted for as an allocation through equity. The consolidated NOL of the AEP System is allocated to each company in the consolidated group with taxable loss. With the exception of the allocation of the consolidated AEP System NOL, Parent Company Loss Benefit and general business tax credits, the method of allocation reflects a separate return result for each company in the consolidated group.

Excise Taxes (Applies to all Registrants except AEPTCo)

As agents for some state and local governments, the Registrants collect from customers certain excise taxes levied by those state or local governments on customers.  The Registrants do not record these taxes as revenue or expense.

Debt

Gains and losses from the reacquisition of debt used to finance regulated electric utility assets are deferred and amortized over the remaining term of the reacquired debt in accordance with their ratemaking treatment unless the debt is refinanced.  If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates.  Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition.

Debt discounts, premiums and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt.  The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations.  The net amortization expense is included in Interest Expense on the statements of income.

Pension and OPEB Plans (Applies to all Registrants except AEPTCo)

AEPSC sponsors a qualified pension plan and two unfunded non-qualified pension plans.  Substantially all AEP subsidiary employees are covered by the qualified plan or both the qualified and a non-qualified pension plan.  AEPSC also sponsors OPEB plans to provide health and life insurance benefits for retired employees.  The Registrant Subsidiaries account for their participation in the AEPSC sponsored pension and OPEB plans using multiple-employer accounting.  See Note 8 - Benefit Plans for additional information including significant accounting policies associated with the plans.

Investments Held in Trust for Future Liabilities (Applies to all Registrants except AEPTCo)

AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and SNF disposal.  All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations.  The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities.  To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers.  Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate.  Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities.  The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance.

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Benefit Plans

All benefit plan assets are invested in accordance with each plan’s investment policy.  The investment policy outlines the investment objectives, strategies and target asset allocations by plan.

The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns.  Strategies used include:

•Maintaining a long-term investment horizon.

•Diversifying assets to help control volatility of returns at acceptable levels.

•Managing fees, transaction costs and tax liabilities to maximize investment earnings.

•Using active management of investments where appropriate risk/return opportunities exist.

•Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks.

•Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification.

The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities.  The current target asset allocations are as follows:

Pension Plan Assets	Target
Equity	35	%
Fixed Income	49	%
Other Investments	15	%
Cash and Cash Equivalents	1	%
OPEB Plans Assets	Target
Equity	63	%
Fixed Income	36	%
Cash and Cash Equivalents	1	%

The investment policy for each benefit plan contains various investment limitations.  The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies or certain commingled funds).  However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law.

For equity investments, the concentration limits are generally as follows:

•No security in excess of 5% of the outstanding class of equity of any one company.

•Cash equivalents must be less than 10% of an investment manager’s equity portfolio.

•No securities may be bought or sold on margin or other use of leverage.

For fixed income investments, each investment manager’s portfolio is compared to investment grade, diversified benchmark indices.

A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation.  Real estate properties are illiquid, difficult to value and not actively traded.  The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties.  To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to diversify holdings by region, property type and risk classification.  Real estate holdings include core, value-added and opportunistic classifications.

A portion of the pension assets is invested in private equity.  Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance.  Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded.  The pension plan uses limited partnerships to invest across the private equity investment spectrum.  The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise.  The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investments.  

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AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses.  AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral.  All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested.  The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security.  The securities lending program’s objective is to provide modest incremental income with a limited increase in risk. As of December 31, 2025 and 2024, the fair value of securities on loan as part of the program was $139 million and $60 million, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2025 and 2024.

Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts.  The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust.  Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid.  Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities.  With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds.  A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges.  The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities.

Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal.  The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities.

Nuclear Trust Funds (Applies to AEP and I&M)

Nuclear decommissioning and SNF trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and SNF disposal liabilities.  By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines.  In general, limitations include:

•Acceptable investments (rated investment grade or above when purchased).

•Maximum percentage invested in a specific type of investment.

•Prohibition of investment in obligations of AEP, I&M or their affiliates.

•Withdrawals permitted only for payment of decommissioning costs and trust expenses.

I&M maintains trust funds for each regulatory jurisdiction.  Regulatory approval is required to withdraw decommissioning funds.  These funds are managed by an external investment manager that must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets.  I&M records these securities at fair value.  I&M classifies debt securities in the trust funds as available-for-sale due to their long-term purpose.

Other-than-temporary impairments for investments in debt securities are considered realized losses as a result of securities being managed by an external investment management firm.  The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy.  Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment.  I&M records unrealized gains, unrealized losses and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates.  Consequently, changes in fair value of trust assets do not affect earnings or AOCI.  See the “Nuclear Contingencies” section of Note 6 for additional discussion of nuclear matters.  See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts.

193

Comprehensive Income (Loss)

Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources.  It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners.  Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).

Stock-Based Compensation Plans

As of December 31, 2025, AEP had performance shares and restricted stock units outstanding under the American Electric Power System 2024 Long-Term Incentive Plan (2024 LTIP) and the American Electric Power System 2015 Long-Term Incentive Plan (2015 LTIP).  Upon vesting, all outstanding performance shares and restricted stock units settle in AEP common stock. The impact of AEP’s stock-based compensation plan is insignificant to the financial statements of the Registrant Subsidiaries.

AEP maintains a variety of tax-qualified and non-qualified deferred compensation plans for employees and non-employee directors that include, among other options, an investment in or an investment return equivalent to that of AEP common stock.  This includes AEP career shares maintained under the American Electric Power System Stock Ownership Requirement Plan (SORP), which facilitates executives in meeting minimum stock ownership requirements assigned to them by the Human Resources Committee of the Board of Directors.  AEP career shares are derived from vested performance shares granted to employees under a long-term incentive plan. AEP career shares accrue additional dividend shares in an amount equal to dividends paid on AEP common shares at the closing market price on the dividend payments date. All AEP career shares are settled in shares of AEP common stock after the executive’s service with AEP ends.

Performance shares are classified as temporary equity on the balance sheets until the awards vest. Upon vesting, the performance shares are classified as permanent equity. These awards may be settled in cash upon an employee’s qualifying termination due to a change in control. Because such event is not solely within the control of the company, these awards are classified outside of permanent equity until the awards vest.

AEP compensates non-employee directors, in part, with stock units under the American Electric Power Company, Inc. Stock Unit Accumulation Plan for Non-Employee Directors.

Management measures and recognizes compensation expense for all share-based payment awards to employees and directors based on estimated fair values. For awards that are paid in shares with service only vesting conditions, management recognizes compensation expense on a straight-line basis over the vesting period.  Stock-based compensation expense recognized on the statements of income for the years ended December 31, 2025, 2024 and 2023 is based on the number of outstanding awards at the end of each period without a reduction for estimated forfeitures. AEP accounts for forfeitures in the period in which they occur.

For the years ended December 31, 2025, 2024 and 2023, compensation costs are included in Net Income for performance shares, career shares, restricted stock units, unrestricted shares, non-employee director stock units and other qualified and non-qualified deferred compensation plans that provide an investment in or an investment return equivalent to that of AEP common stock. Compensation costs may also be capitalized. See Note 16 - Stock-based Compensation for additional information.

Noncontrolling Interests (Applies to AEP, AEPTCo and SWEPCo)

Noncontrolling interests represent the portion of equity in certain consolidated subsidiaries that is not attributable to the Registrants. For these subsidiaries, the Registrants hold a controlling financial interest, but not all the outstanding equity. The noncontrolling owners’ share of the subsidiaries’ net assets is presented as Noncontrolling Interests within Total Equity on the balance sheets. The portion of net income and other comprehensive income attributable to noncontrolling interests is presented separately in the statements of income and statements of comprehensive income. Distributions to noncontrolling interest holders are recorded as reductions to the noncontrolling interest balance. Contributions from noncontrolling interest holders are recorded as additions to the noncontrolling interest balance. Changes in the Registrant’s ownership interest in a subsidiary that do not result in a loss of control are accounted for as equity transactions. Any difference between the consideration transferred and the adjustment to the noncontrolling interest is recognized directly in Paid-in Capital.

194

Equity Method Investments in Unconsolidated Entities (Applies to AEP and SWEPCo)

The equity method of accounting is used for equity investments where either AEP or SWEPCo exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings or losses is included in Equity Earnings (Loss) of Unconsolidated Subsidiaries on the statements of income. AEP and SWEPCo regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recognized when the investment has experienced a loss in value that is other-than-temporary in nature.

As of December 31, 2025, AEP’s equity method investments include ETT, DHLC and Gigawatt AI. See Note 18 - Variable Interest Entities and Equity Method Investments for additional information.

Change in Presentation

In 2025, the Company changed its rounding presentation in the Registrant’s financial statements and accompanying tabular footnote disclosures to the nearest whole number in millions, except per share data. The change had no material impact on previously reported financial information, however certain amounts reported for prior periods may differ by insignificant amounts due to the rounding presentation. In addition, historical percentages and per share amounts presented may not recalculate due to rounding. This change does not impact the comparability of the Registrant’s financial statements and related disclosures.

Earnings Per Share (EPS) (Applies to AEP)

Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted-average number of common shares outstanding during the period.  Diluted EPS is calculated by adjusting the weighted-average outstanding common shares, assuming conversion of all potentially dilutive securities. Dilutive securities are primarily related to forward sale of equity agreements and restricted stock units. See Note 15 - Financing Activities for more information regarding the forward sale of equity agreements.

The following table presents AEP’s basic and diluted EPS calculations included on the statements of income:

	Years Ended December 31,
	2025				2024				2023
	(in millions, except per-share data)
			$/share				$/share				$/share
Earnings Attributable to AEP Common Shareholders	$	3,580			$	2,967			$	2,208
Weighted-Average Number of Basic AEP Common Shares Outstanding	534.5		$	6.70	530.1		$	5.60	518.9		$	4.26
Weighted-Average Dilutive Effect	3.0		(0.04)		1.2		(0.02)		1.3		(0.02)
Weighted-Average Number of Diluted AEP Common Shares Outstanding	537.5		$	6.66	531.3		$	5.58	520.2		$	4.24

There were no antidilutive shares outstanding as of December 31, 2025, 2024 and 2023.

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Supplementary Income Statement Information

The following tables provide the components of Depreciation and Amortization for the years ended December 31, 2025, 2024 and 2023:

2025
Depreciation and Amortization	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Depreciation and Amortization of Property, Plant and Equipment	$	3,325	$	420	$	478	$	652	$	471	$	380	$	293	$	391
Amortization of Certain Securitized Assets	46		18		—		—		—		—		—		20
Amortization of Regulatory Assets and Liabilities	9		3		—		(20)		43		—		(33)		18
Total Depreciation and Amortization	$	3,380	$	441	$	478	$	632	$	514	$	380	$	260	$	429

2024
Depreciation and Amortization	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Depreciation and Amortization of Property, Plant and Equipment	$	3,149	$	406	$	431	$	600	$	456	$	386	$	263	$	375
Amortization of Certain Securitized Assets	91		91		—		—		—		—		—		—
Amortization of Regulatory Assets and Liabilities	50		(3)		—		2		25		—		9		14
Total Depreciation and Amortization	$	3,290	$	494	$	431	$	602	$	481	$	386	$	272	$	389

2023
Depreciation and Amortization	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Depreciation and Amortization of Property, Plant and Equipment	$	2,927	$	380	$	394	$	571	$	440	$	316	$	241	$	323
Amortization of Certain Securitized Assets	92		92		—		—		—		—		—		—
Amortization of Regulatory Assets and Liabilities	71		(3)		—		1		30		—		15		20
Total Depreciation and Amortization	$	3,090	$	469	$	394	$	572	$	470	$	316	$	256	$	343

Supplementary Cash Flow Information (Applies to AEP)

	Years Ended December 31,
Cash Flow Information	2025		2024		2023
	(in millions)
Cash Paid for:
Interest, Net of Capitalized Amounts	$	1,894	$	1,838	$	1,674
Noncash Investing and Financing Activities:
Acquisitions Under Finance Leases	44		30		49
Construction Expenditures Included in Current Liabilities as of December 31,	1,935		1,312		842
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,	10		24		24
Noncash Increase in Noncurrent Assets from the Sale of the Competitive Contracted Renewables Portfolio	—		—		75

196

2. NEW ACCOUNTING STANDARDS

The disclosures in this note apply to all Registrants unless indicated otherwise.

Management reviews the FASB’s standard-setting process and the SEC’s rulemaking activity to determine the relevance, if any, to the Registrants’ business. The following standards/rules will impact the Registrants’ financial statements.

SEC Climate Disclosure Rule

In March 2024, the SEC adopted final rules that would require registrants to disclose certain climate-related information in registration statements and annual reports. Litigation challenging the new rules was filed by multiple parties in multiple jurisdictions, which have been consolidated and assigned to the U.S. Court of Appeals for the Eighth Circuit. In March 2025, the SEC announced that it voted to end its defense of the final climate disclosure rules. In April 2025, 18 states filed a motion to intervene in the case and to hold the case in abeyance until the SEC takes action to amend or rescind the rules. In July 2025, the SEC filed a status report stating that it does not intend to review or reconsider the rules and asked the Court of Appeals to make a ruling on the case. In September 2025, the Court of Appeals issued an order holding the case in abeyance until the SEC either formally defends the rules or initiates a new rulemaking process for reconsideration.

ASU 2023-09 “Improvements to Income Tax Disclosures” (ASU 2023-09)

In December 2023, the FASB issued ASU 2023-09, to address investors’ suggested enhancements to (a) better understand an entity’s exposure to potential changes in jurisdictional tax legislation and the ensuing risks and opportunities, (b) assess income tax information that affects cash flow forecasts and capital allocation decisions and (c) identify potential opportunities to increase future cash flows.

The new standard requires an annual rate reconciliation disclosure of the following categories regardless of materiality: state and local income tax, net of federal income tax effect, foreign tax effects, effect of changes in tax laws or rates enacted in the current period, effect of cross-border tax laws, tax credits, changes in valuation allowances, nontaxable or nondeductible items and changes in unrecognized tax benefits.

The new standard also requires an annual disclosure of the amount of income taxes paid (net of refunds received) disaggregated by federal, state and foreign taxes and by individual jurisdictions that are equal to or greater than 5 percent of total income taxes paid. Disclosure of income (loss) from continuing operations before income tax expense (benefit) disaggregated between domestic and foreign jurisdictions and income tax expense (benefit) from continuing operations disaggregated by federal, state and foreign jurisdictions is required.

The new standard removes the requirement to disclose the cumulative amount of each type of temporary difference when a deferred tax liability is not recognized because of the exceptions to comprehensive recognition of deferred taxes related to subsidiaries and corporate joint ventures.

Management adopted ASU 2023-09 and its related implementation guidance effective January 1, 2025 for the annual reporting period and applied the amendments retrospectively to all prior periods presented in the annual consolidated financial statements. The adoption of the new standard did not impact the results of operations, statements of financial position or cash flows. See Note 12 - Income Taxes for additional information.

197

ASU 2024-03 “Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures” (ASU 2024-03)

In November 2024, the FASB issued ASU 2024-03, the intent of which is to improve financial reporting and respond to investor input by requiring public business entities to disclose additional information about certain expenses in the notes to financial statements in interim and annual reporting periods. Among other provisions, the new standard requires disclosure of disaggregated amounts for expenses such as employee compensation, depreciation, and intangible asset amortization included in each expense caption presented on the face of the income statement. Public business entities are required to include certain amounts that are already required to be disclosed under GAAP in the same disclosure as the other disaggregation requirements as well as a qualitative description of any amounts remaining in relevant expense captions that are not separately disaggregated quantitatively. The new standard also requires disclosure of the total amount of selling expenses and, in annual reporting periods, an entity’s definition of selling expenses. An entity is not precluded from providing additional voluntary disclosures that may provide investors with additional decision-useful information.

The amendments in the new standard are effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. The amendments in the new standard should be applied either prospectively to financial statements issued for reporting periods after the effective date or retrospectively to any or all prior periods presented in the financial statements. Management is evaluating the new standard and has not yet determined when, or the method by which, the Registrants will adopt its amendments.

ASU 2025-06 “Intangibles—Goodwill and Other—Internal-Use Software” (ASU 2025-06)

In September 2025, the FASB issued ASU 2025-06, the intent of which is to modernize the cost capitalization threshold for internal-use software development costs by removing all references to software project development stages and providing new guidance on how to evaluate whether the probable-to-complete recognition threshold has been met for the commencement of capitalization of eligible costs.

The amendments in the new standard may be applied on either a retrospective, prospective or modified prospective basis for public business entities for fiscal years beginning after December 15, 2027 with early adoption permitted. Management elected to early adopt this standard prospectively beginning on January 1, 2026. The adoption of the new standard is not expected to have a material impact on the results of operations, statements of financial position or cash flows.

198

3.  COMPREHENSIVE INCOME

The disclosures in this note apply to AEP only. The impact of AOCI is not material to the financial statements of the Registrant Subsidiaries.

Presentation of Comprehensive Income

The following tables provide AEP’s components of changes in AOCI and details of reclassifications from AOCI for the years ended December 31, 2025, 2024 and 2023.  The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 - Benefit Plans for additional information.

	Cash Flow Hedges				Pension and OPEB
For the Year Ended December 31, 2025	Commodity		Interest Rate		Amortization of Deferred Costs		Changes in Funded Status		Total
	(in millions)
Balance in AOCI as of December 31, 2024	$	99	$	3	$	99	$	(204)	$	(3)
Change in Fair Value Recognized in AOCI, Net of Tax	(9)		(1)		—		63		53
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)	(15)		—		—		—		(15)
Interest Expense (a)	—		(4)		—		—		(4)
Amortization of Prior Service Cost (Credit)	—		—		(1)		—		(1)
Amortization of Actuarial (Gains) Losses	—		—		2		—		2
Reclassifications from AOCI, before Income Tax (Expense) Benefit	(15)		(4)		1		—		(18)
Income Tax (Expense) Benefit	(3)		(1)		—		—		(4)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(12)		(3)		1		—		(14)
Net Current Period Other Comprehensive Income (Loss)	(21)		(4)		1		63		39
Balance in AOCI as of December 31, 2025	$	78	$	(1)	$	100	$	(141)	$	36

	Cash Flow Hedges				Pension and OPEB
For the Year Ended December 31, 2024	Commodity		Interest Rate		Amortization of Deferred Costs		Changes in Funded Status		Total
	(in millions)
Balance in AOCI as of December 31, 2023	$	105	$	(8)	$	93	$	(245)	$	(55)
Change in Fair Value Recognized in AOCI, Net of Tax	3		6		—		41		50
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)	(11)		—		—		—		(11)
Interest Expense (a)	—		6		—		—		6
Amortization of Prior Service Cost (Credit)	—		—		(5)		—		(5)
Amortization of Actuarial (Gains) Losses	—		—		1		—		1
Recognition of Pension Settlement Costs	—		—		11		—		11
Reclassifications from AOCI, before Income Tax (Expense) Benefit	(11)		6		7		—		2
Income Tax (Expense) Benefit	(2)		1		1		—		—
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(9)		5		6		—		2
Net Current Period Other Comprehensive Income (Loss)	(6)		11		6		41		52
Balance in AOCI as of December 31, 2024	$	99	$	3	$	99	$	(204)	$	(3)

199

	Cash Flow Hedges				Pension and OPEB
For the Year Ended December 31, 2023	Commodity		Interest Rate		Amortization of Deferred Costs		Changes in Funded Status		Total
	(in millions)
Balance in AOCI as of December 31, 2022	$	224	$	—	$	106	$	(246)	$	84
Change in Fair Value Recognized in AOCI, Net of Tax	(176)		(6)		—		(16)		(198)
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)	72		—		—		—		72
Interest Expense (a)	—		(3)		—		—		(3)
Amortization of Prior Service Cost (Credit)	—		—		(21)		—		(21)
Amortization of Actuarial (Gains) Losses	—		—		5		—		5
Reclassifications from AOCI, before Income Tax (Expense) Benefit	72		(3)		(16)		—		53
Income Tax (Expense) Benefit	15		(1)		(3)		—		11
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	57		(2)		(13)		—		42
Reclassifications of KPCo Pension and OPEB Regulatory Assets to AOCI, before Income Tax (Expense) Benefit	—		—		—		21		21
Income Tax (Expense) Benefit	—		—		—		4		4
Reclassifications of KPCo Pension and OPEB Regulatory Assets to AOCI, Net of Income Tax (Expense) Benefit	—		—		—		17		17
Net Current Period Other Comprehensive Income (Loss)	(119)		(8)		(13)		1		(139)
Balance in AOCI as of December 31, 2023	$	105	$	(8)	$	93	$	(245)	$	(55)

(a)Amounts reclassified to the referenced line item on the statements of income.

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4.  RATE MATTERS

The disclosures in this note apply to all Registrants unless indicated otherwise.

The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions.  Rate matters can have a material impact on net income, cash flows and possibly financial condition.  The Registrants’ recent significant rate orders and pending rate filings are addressed in this note.

AEP Texas Rate Matters (Applies to AEP and AEP Texas)

AEP Texas Interim Transmission and Distribution Rates

Through December 31, 2025, AEP Texas’ cumulative revenues from transmission and distribution interim base rate increases that are subject to review are estimated to be approximately $118 million. A base rate review could result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition.

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.

APCo and WPCo Rate Matters (Applies to AEP and APCo)

ENEC (Expanded Net Energy Cost) Filings

In January 2024, the WVPSC issued an order resolving APCo’s and WPCo’s ( the Companies) 2021-2023 ENEC cases. In the order, the WVPSC: (a) disallowed $232 million in ENEC under-recovered costs as of February 28, 2023 ($136 million related to APCo) and (b) approved the recovery of $321 million of ENEC under-recovered costs as of February 28, 2023 ($174 million related to APCo) plus a 4% debt carrying charge rate over a ten-year recovery period starting September 1, 2024.

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In February 2024, the Companies filed briefs with the West Virginia Supreme Court (WVSC) to initiate an appeal of the January 2024 order. Following arguments that were held in September 2024, the WVSC issued a November 2024 opinion affirming in part and reversing in part the WVPSC’s January 2024 ENEC order. The WVSC remanded the ENEC case to the WVPSC to afford the Companies an opportunity to examine, analyze, rebut and refute the calculation of the $232 million disallowance.

In March 2025, the WVPSC entered an order in the Companies’ 2021-2023 ENEC remand cases further describing its calculations of the ordered $232 million disallowance. In June 2025, the Companies submitted direct testimony on remand supporting a reduction to the WVPSC’s previously-ordered disallowance of at least $179 million.

In August 2025, WVPSC staff and an intervening party submitted testimony recommending the continued disallowance of $232 million of ENEC under-recovered costs as of February 28, 2023, with the intervening party recommending that the WVPSC consider a larger disallowance based on alleged imprudence of coal procurement.

A hearing on the 2021-2023 ENEC remand cases was held in October 2025. If any additional 2021-2023 ENEC costs are not recoverable or refunds are ordered, it would reduce future net income and cash flows and impact financial condition.

In April 2024, the Companies submitted their 2024 ENEC update case proposing a $58 million annual increase in ENEC rates when compared to existing ENEC rates. The Companies proposed that this ENEC rate change would: (a) become effective September 1, 2024, (b) include a $20 million annual increase in ENEC rates related to the period ending February 29, 2024 and the forecast period September 2024 through August 2025 and (c) include a $38 million annual increase in ENEC rates for the recovery of $321 million of ENEC under-recovered costs as of February 28, 2023, over a ten-year period, plus a 4% debt carrying charge rate. In August 2024, the WVPSC issued an order approving the requested $38 million annual increase effective September 1, 2024. In March 2025, the WVPSC issued an order approving the requested $20 million annual increase effective March 11, 2025.

In April 2025, the Companies submitted their 2025 ENEC update filing proposing a $72 million annual increase in ENEC rates. In September 2025, the WVPSC issued an order on the Companies’ 2025 ENEC update filing approving an annual ENEC revenue requirement increase of $70 million with no change in ENEC rates charged to customers. The WVPSC ordered this ENEC customer rate increase to occur upon securitization which is expected in the first half of 2026 as further described in the “2025 West Virginia Securitization Filing” section below. The WVPSC denied an intervenor-recommended ENEC under-recovery disallowance of $19 million.

Virginia Fuel Adjustment Clause (FAC) Review

In 2023, APCo submitted its annual fuel cost filing with the Virginia SCC. Interim Virginia FAC rates were implemented in November 2023. In APCo's 2022 Virginia fuel update filing, the Virginia SCC ordered the Virginia Staff to commence an audit of APCo’s fuel costs for the years ended December 31, 2019, 2020, 2021 and 2022. The Virginia Staff analyzed APCo’s 2019 through 2022 fuel procurement activities and concluded the procurement practices were reasonable and prudent and recommended no disallowances. In May 2024, the Virginia SCC issued an order approving the audit of APCo’s 2019 and 2020 fuel costs but concluded that the review of APCo fuel costs for 2021 and 2022 should remain open for further evaluation as part of APCo’s 2024 fuel cost filing.

In September 2024, APCo submitted its annual Virginia fuel cost filing with the Virginia SCC proposing no change in annual APCo Virginia FAC rates charged to customers for the period November 2024 through October 2025. In January 2025, an intervening party recommended a minimum fuel under-recovery disallowance of $20 million related to alleged imprudent operations of Amos and Mountaineer generating units during October 2021 and November 2021. There were no other recommended disallowances by intervenors or Virginia Staff regarding APCo’s historical period Virginia fuel under-recovery balance through October 31, 2024. Virginia Staff also recommended that the Virginia SCC close APCo’s open review periods related to 2021 and 2022 Virginia fuel costs with no cost disallowances. A hearing was held in May 2025. In June 2025, the Hearing Examiner issued a report recommending that the Virginia SCC order: (a) no change in annual APCo Virginia FAC rates for the period November 2024 through October 2025, (b) no cost disallowances for APCo’s Virginia FAC review period ending October 31, 2024 and (c) no cost disallowances for APCo’s 2021 and 2022 Virginia fuel cost review periods. In December 2025, the Virginia SCC issued an order approving the recommendations of the Hearing Examiner.

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2024 West Virginia Base Rate Case

In November 2024, APCo and WPCo (the Companies) filed a request with the WVPSC for a net $251 million annual increase in base rates based upon a proposed 10.8% ROE and a proposed capital structure of 52% debt and 48% common equity. The requested net annual increase in base rates excludes the Companies’ proposed $94 million annual Modified Rate Base Cost (MRBC) surcharge update proposed to be effective in a separate proceeding and the existing $21 million annual Mitchell Base Rate Surcharge that are both proposed to be rolled into base rates upon the Companies’ anticipated 2025 change in base rates. The Companies’ proposed base rate increase includes recovery of approximately $118 million in previously deferred major storm expenses over a three-year period plus a carrying charge on the deferral balance, capital structure changes including an increase in ROE, an increase in depreciation expense related to proposed changes in depreciation rates and increased capital investments and increases in distribution and generation operation and maintenance expenses.

The Companies’ November 2024 West Virginia base rate filing also included two sets of alternative frameworks to simplify rates and customer bills and provide predictable future rate increases. The Companies’ first framework includes: (a) securitization, (b) approval of a major storm expense recovery and tracking mechanism and (c) freezing of OATT revenues in the ENEC. This framework includes securitization in a concurrent proceeding of approximately $2.4 billion of West Virginia jurisdictional assets. Securitization of those items could reduce the Companies’ combined requested increase in annual base rates to $37 million. See the “2025 West Virginia Securitization Filing” section below for additional information.

The Companies also submitted an alternative ratemaking proposal that includes: (a) a separate surcharge that would allow the Companies up to a 3% annual increase in overall West Virginia rates for four consecutive years on April 1st of each year after the implementation of base rates in this case, (b) the elimination of all of the Companies’ existing West Virginia jurisdictional surcharges except for the ENEC, with the revenues of these eliminated riders rolled into base rates and (c) the creation of a new West Virginia jurisdictional environmental and new generation surcharge. This alternative proposal would allow the Companies to submit a base rate case filing in advance of and in lieu of the annual April 1st 3% increase and would require the Companies to submit a base rate case filing at the end of the proposed four-year period.

In August 2025, the WVPSC issued an order on the Companies’ base case filing. The WVPSC’s order: (a) approved a combined annual base rate revenue requirement increase of $76 million ($67 million related to APCo) based on a 9.25% ROE and a capital structure of 56% debt and 44% equity, (b) included recovery of $24 million of previously deferred storm costs with no carrying charges, with future securitization of these deferred storm costs as described in the “2025 West Virginia Securitization Filing” section below, (c) included a decrease in the base rate revenue requirement related to a WVPSC-ordered decrease in depreciation rates, (d) required the Companies to recover the monthly level of this base rate increase through current ENEC rates, (e) effectively terminated the Companies’ MRBC, Mitchell Base Rate and Vegetation Management surcharges upon the approved change in base rates revenue requirement with these surcharges rolled into base rates, (f) stipulated that the Companies’ proposals related to the inclusion of a stand-alone NOLC deferred tax asset in rate base will be addressed in a future proceeding upon the Companies’ receipt of a PLR from the IRS and (g) approved the Companies’ requested West Virginia jurisdictional environmental and new generation surcharge but did not approve the Companies’ proposed storm tracking mechanism, annual 3% surcharge increase and freezing of OATT revenues in the ENEC. In September 2025, the Companies filed a petition for reconsideration with the WVPSC to explain the financial consequences of the order and seek clarification on certain issues.

West Virginia Modified Rate Base Cost (MRBC) Surcharge Update Filing

In March 2024, APCo and WPCo (the Companies) submitted an annual MRBC surcharge update filing with the WVPSC requesting a $32 million annual increase in the Companies’ combined MRBC rates. The MRBC is an infrastructure investment tracker that allows limited cost recovery related to capital investments between the Companies’ West Virginia jurisdictional base rate cases. WVPSC staff and an intervening party recommended revenue requirement disallowances in written and verbal testimony and briefs for certain ratemaking issues used to develop the Companies’ proposed MRBC rates, including the West Virginia jurisdictional effect of state deferred income taxes, NOLCs and AROs.

The WVPSC’s August 2025 order on the Companies’ West Virginia base case filing, as described in the “2024 West Virginia Base Rate Case” section above, approved the termination of the MRBC and the transition of MRBC rates into base rates. The WVPSC did not rule on MRBC refunds proposed by WVPSC Staff and an intervening party related to NOLCs and other issues as these issues will be addressed in a future filing. The WVPSC’s August 2025 base case order stipulated that the Companies’ proposals related to the inclusion of a stand-alone NOLC deferred tax asset in rate base will be addressed in a future proceeding upon the Companies’ receipt of a PLR from the IRS.

If any refund liabilities are imposed by the WVPSC, it could reduce future net income and cash flows and impact financial condition.

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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 including: (a) $321 million of the Companies’ remaining 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) $118 million of West Virginia jurisdictional deferred major storm operation and maintenance costs.

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.

In September 2025, and as directed by the WVPSC in the August 2025 interim order described above, the Companies submitted an updated proposed financing order that reflected additional ENEC under-recovery balances for costs incurred in 2025 and additional storm operation and maintenance deferral balances for the impacts of Hurricane Helene and winter storms Blair, Harlow and Jett. WPCo forecasted CCR and ELG amounts below related to the Mitchell Plant are subject to change based on the fourth quarter 2025 KPSC order approving the settlement agreement on KPCo’s June 2025 CPCN filing that would allow KPCo to continue taking a 50% share of energy and capacity from the Mitchell Plant to serve KPCo customers beyond December 31, 2028. See “Mitchell Plant Filing for Certificate of Public Convenience and Necessity” section below for additional information. In February 2026, WPCo requested that the WVPSC grant any additional authorizations necessary to enable WPCo to reflect the holdings and impact of the December 2025 KPSC order or make a determination that no such authorizations are required. All amounts in the table below are subject to further review in a future final securitization financing order that the Companies expect will be issued by the WVPSC in 2026. See the summarization of the proposed securitization items in the table below:

Proposed Securitized Items	APCo		WPCo		Total
	(in millions)
Undepreciated Utility Plant Balances of Amos, Mitchell and Mountaineer (as of December 31, 2022)	$	1,145	$	559	$	1,704
ENEC Under-Recovery Regulatory Assets	167		246		413
Forecasted Undepreciated CCR and ELG Investments of Amos, Mitchell and Mountaineer (as of November 30, 2024)	88		149		237
Deferred Storm Other Operation and Maintenance Expense Regulatory Assets	155		3		158
Upfront Financing Costs	10		6		16
Total	$	1,565	$	963	$	2,528

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.

If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2025 Virginia Securitization Filing

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

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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.

ETT Rate Matters (Applies to AEP)

2025 ETT Base Rate Case

In January 2025, ETT filed a request with the PUCT for a $57 million annual base rate increase over its adjusted test year revenues which includes interim transmission rate updates. ETT’s request was based upon a proposed 10.6% ROE with a capital structure of 55% debt and 45% common equity. The rate case sought a prudence review determination on cumulative capital additions included in interim rates. In April and May 2025, respectively, intervenors and PUCT staff submitted testimony challenging components of the proposed rate increase including up to $37 million related to increased depreciation rates and $32 million related to the proposed ROE and capital structure.

In June 2025, a unanimous and unopposed settlement was filed with the PUCT along with a motion to approve interim rates, equal to the rates specified in the settlement, effective on June 20, 2025. The settlement terms included a base rate increase of approximately $20 million, based on an ROE of 9.6% and a capital structure of 59% debt and 41% equity. The settlement also included a determination that ETT’s invested capital and rate base are prudent and properly included in rates. The motion to approve interim rates was granted in June 2025. In October 2025, the PUCT issued an order approving the June 2025 settlement. The rates approved by the order are identical to the rates approved on an interim basis.

I&M Rate Matters (Applies to AEP and I&M)

Michigan Power Supply Cost Recovery (PSCR) Reconciliation

2023 PSCR Reconciliation

In March 2024, I&M submitted its 2023 PSCR Reconciliation to the MPSC. In October 2024, MPSC staff and intervenors submitted testimony recommending PSCR cost disallowances associated with the OVEC Inter-Company Power Agreement (ICPA) and the Rockport UPA with AEGCo ranging from $3 million to $15 million. In July 2025, the MPSC issued an order resulting in a combined $3 million PSCR cost disallowance related to OVEC and Rockport UPA costs. In July 2025, the IURC issued an order on I&M’s Resource Adequacy Rider update filing approving I&M’s proposed capacity resource adjustments, including prospective recovery of OVEC capacity, energy and associated costs that were previously assigned to I&M Michigan retail customers starting with the June 2025-May 2026 PJM delivery year.

2024 PSCR Reconciliation

In March 2025, I&M submitted its 2024 PSCR Reconciliation to the MPSC. In October 2025, MPSC staff and intervenors submitted testimony recommending PSCR cost disallowances associated with the OVEC ICPA and the Rockport UPA with AEGCo ranging from $259 thousand to $14 million. A hearing on I&M’s 2024 PSCR Reconciliation was held in December 2025 and an MPSC order is expected in the second quarter of 2026. Any future disallowances ordered by the MPSC on I&M’s 2024 PSCR Reconciliation could reduce future net income and cash flows and impact financial condition.

Indiana Earnings Test

I&M is required by Indiana law to submit an earnings test evaluation for the most recent one-year and five-year periods as part of I&M’s semi-annual Indiana FAC filings. These earnings test evaluations require I&M to include a credit in the FAC factor computation for periods in which I&M earned above its authorized return for both the one-year and five-year periods. The credit is determined as 50% of the lower of the one-year or five-year earnings above the authorized level. Management believes its financial statements adequately address the impact of Indiana earnings test requirements previously established by the IURC. If future IURC orders require that I&M provide credits in the FAC factor computation in excess of established earnings test requirements, it could reduce future net income and cash flows and impact financial condition.

In January 2025, I&M submitted its FAC filing and earnings test evaluation for the period ended November 2024. I&M proposed an over-earnings credit to customers for the earnings test period ending November 2024 of $21 million. In April 2025, the IURC issued an order approving the $21 million customer credit.

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In July 2025, I&M submitted its FAC filing and earnings test evaluation for the period ended May 2025. I&M proposed an over-earnings credit to customers for the earnings test period ending May 2025 of $35 million. In October 2025, the IURC issued an order approving the $35 million customer credit.

In February 2026, I&M submitted its FAC filing and earnings test evaluation for the period ended November 2025. I&M proposed an over-earnings credit to customers for the earnings test period ending November 2025 of $53 million based on requested modifications to jurisdictional cost allocations to more accurately reflect I&M’s cost to serve Indiana retail customers. An IURC order approving I&M’s proposed jurisdictional cost allocation modifications and as-filed over-earnings credit would increase future net income and cash flows and impact financial condition.

KPCo Rate Matters (Applies to AEP)

Investigation of the Service, Rates and Facilities of KPCo

In June 2023, the KPSC issued an order directing KPCo to show cause why it should not be subject to Kentucky statutory remedies, including fines and penalties, for failure to provide adequate service in its service territory. The KPSC’s show cause order did not make any determination regarding the adequacy of KPCo’s service. In July 2023, KPCo filed a response to the show cause order demonstrating that it has provided adequate service. In December 2023 and February 2024, KPCo and certain intervenors filed testimony with the KPSC. A hearing with the KPSC was previously scheduled to occur in June 2024. The hearing was postponed and has not yet been rescheduled. If any fines or penalties are levied against KPCo relating to the show cause order, it could reduce future net income and cash flows and impact financial condition.

2023 Kentucky Base Rate and Securitization Case

In June 2023, KPCo filed a request with the KPSC for a $94 million net annual increase in base rates based upon a proposed 9.9% ROE with the increase to be implemented no earlier than January 2024. In conjunction with its June 2023 filing, KPCo further requested to finance through the issuance of securitization bonds, approximately $471 million of regulatory assets. KPCo’s proposal did not address the disposition of its 50% interest in Mitchell Plant, which will be addressed in the future. See “Mitchell Plant Filing for Certificate of Public Convenience and Necessity” section below for additional information.

In November 2023, KPCo filed an uncontested settlement agreement with the KPSC, that included an annual base rate increase of $75 million, based upon a 9.75% ROE. Settlement parties agreed that the KPSC should approve KPCo’s securitization request, and that the approximate $471 million of regulatory assets requested for securitization are comprised of prudently incurred costs.

In January 2024, the KPSC issued an order modifying the November 2023 uncontested settlement agreement and approving an annual base rate increase of $60 million based upon a 9.75% ROE effective with billing cycles starting mid-January 2024. The order reduced KPCo’s base rate revenue requirement by $14 million to allow recovery of actual test year PJM transmission costs instead of KPCo’s requested annual level of costs based on PJM 2023 projected transmission revenue requirements. In February 2024, KPCo filed an appeal with the Commonwealth of Kentucky Franklin Circuit Court (Circuit Court), challenging among other aspects of the order, the $14 million base rate revenue requirement reduction. In January 2025, the Circuit Court issued an order agreeing with KPCo’s appeal and remanded this issue back to the KPSC with instructions to enter an order, within 30 days, which includes setting rates to allow KPCo to recover the $14 million of annual PJM transmission costs effective upon KPCo's January 2024 implementation of updated base rates. In March 2025, the KPSC issued a rehearing order that approved rates for the prospective collection of test year PJM transmission costs beginning in February 2025 but denied KPCo’s request to defer and recover the historical PJM transmission costs of approximately $16 million incurred from January 2024 through the February 2025 update in base rates. In April 2025, KPCo filed an appeal with the Circuit Court for a motion to enforce in response to the KPSC’s denial to recover PJM transmission costs incurred from January 2024 through the implementation of new rates. In September 2025, the Circuit Court issued an order granting KPCo’s motion to enforce. In October 2025, the KPSC issued an order approving recovery of the $16 million of PJM transmission costs, with debt and equity carrying charges starting September 15, 2025 on the remaining PJM transmission costs to be recovered, through a rider. The rider was effective with the first billing cycle in November 2025 and will be in place for 22 months.

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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Mitchell Plant Filing for Certificate of Public Convenience and Necessity

KPCo and WPCo each own a 50% undivided interest in the 1,560 MW coal-fired Mitchell Plant. In July 2021, the KPSC rejected KPCo’s ELG compliance plan for KPCo’s 50% ownership share of ELG investments at the Mitchell Plant that would allow KPCo to take capacity and energy to serve customers beyond December 31, 2028. As a result of this order, and pursuant to September 2022 resolutions under the existing Mitchell Plant Operating Agreement, WPCo funded 100% of the Mitchell Plant ELG investments that have been placed in service. In addition, WPCo also paid for a greater than 50% share of certain non-ELG capital investments made at Mitchell Plant which will continue to be used in the operation of Mitchell Plant beyond 2028.

In June 2025, KPCo filed a request with the KPSC for a CPCN to make investments necessary to reflect: (a) a 50% share of the Mitchell Plant ELG Project and (b) a 50% share of non-ELG capital investments. KPSC approval of these investments would allow KPCo to continue taking a 50% share of energy and capacity from the Mitchell Plant to serve KPCo customers beyond December 31, 2028. KPCo proposed to recover the estimated $78 million investment in the ELG Project through KPCo’s existing Environmental Surcharge and requested recovery of an estimated $60 million of Mitchell Plant non-ELG capital investments through its 2025 Kentucky Base Rate Case filing. See “2025 Kentucky Base Rate Case” section below for additional information.

In November 2025, KPCo and an intervening party submitted a settlement agreement that recommended the approval of KPCo’s proposed Mitchell Plant CPCN and use of KPCo’s Environmental Surcharge to recover Mitchell Plant ELG project costs through 2040. The settlement agreement further recommended granting KPCo authority to defer the depreciation expense and carrying costs associated with Mitchell Plant non-ELG capital investments to a regulatory asset until it can be reflected in rates. The recovery mechanism for Mitchell Plant non-ELG capital investments will be addressed in KPCo’s 2025 Kentucky Base Rate Case filing. See “2025 Kentucky Base Rate Case” section below for additional information.

In December 2025, the KPSC issued an order approving the settlement agreement, the Mitchell Plant CPCN and recovery of ELG capital investments through the Environmental Surcharge. The KPSC’s order imposes annual reporting requirements to review capital investment costs at the Mitchell Plant.

To operate in accordance with KPSC and WVPSC directives related to Mitchell Plant ELG investments, KPCo and WPCo expect to utilize existing authority under the Mitchell Plant Operating Agreement to revise billing procedures resulting in equal allocation of costs. In February 2026, WPCo requested that the WVPSC grant any additional authorizations necessary to enable WPCo to reflect the holdings and impact of the December 2025 KPSC order or make a determination that no such authorizations are required. As of December 31, 2025, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal and including CWIP and inventory, and prior to the effect of revised billing procedures expected under the Mitchell Plant Operating Agreement to comply with the KPSC’s December 2025 order, was $523 million.

2025 Kentucky Base Rate Case

In August 2025, KPCo filed a request with the KPSC for a $96 million net annual increase in base rates based upon a proposed 10% ROE and a proposed capital structure of 53.9% debt and 46.1% common equity, to be implemented no earlier than March 2026. Among other changes, the filing proposed a $10 million increase in PJM transmission costs, a $9 million increase due to load loss and a $6 million increase in depreciation rates.

The proposed annual rate increase also included a $20 million annual revenue requirement related to KPCo’s investment in the Mitchell Plant. See “Mitchell Plant Filing for Certificate of Public Convenience and Necessity” section above for additional information. As part of this filing, KPCo requested a new generation rider to recover the remaining net book value of KPCo’s non-environmental investment in the Mitchell Plant that KPCo historically recovered through base rates. If the generation rider is approved, the $20 million would be removed from the requested revenue requirement increase and would be collected through the rider. Additionally, KPCo is pursuing securitization legislation that would allow KPCo to securitize the remaining net book value of the Mitchell Plant. If the securitization of the remaining Mitchell Plant net book value is successful, collection of costs through the generation rider would cease.

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In January 2026, KPCo and certain intervening parties submitted a settlement agreement with the KPSC proposing a $77 million annual increase in Kentucky retail rates, including: (a) a $59 million annual increase in KPCo base rates based on a 9.8% authorized ROE and a capital structure of 53.9% debt and 46.1% common equity, and (b) a new generation rider with a first year revenue requirement of $18 million based on a 9.7% authorized ROE to recover non-environmental plant investments at Mitchell Plant and all incremental capital investments after May 31, 2025 at both Mitchell Plant and Big Sandy Plant. Capital and other operation and maintenance expenses related to any new generating assets also will be eligible for inclusion in the Generation Rider, subject to KPSC approval. The settlement revenue requirement will be reduced by $25 million in the first year and $15 million in the second year through a new rider that returns certain unprotected deferred tax expenses in customer rates on a temporary basis, and then beginning in the third year, collects the deferred tax expense amounts from customers over the estimated time period that taxes are due to the IRS. The settlement agreement also proposes: (a) approval to defer all storm other operation and maintenance expenses above or below the level included in base rates, and (b) approval to defer vegetation management costs above or below the level included in base rates, capped at a total of $45 million in 2026 and $52 million in 2027. Consistent with the KPSC order in KPCo’s 2023 Kentucky Base Rate Case filing, the settlement agreement also provides that KPCo’s proposal to include a stand-alone NOLC deferred tax asset in rate base will be addressed in a future proceeding upon KPCo’s receipt of a PLR or other guidance from the IRS. A hearing was held in January 2026.

In February 2026, an intervenor filed a brief recommending that the KPSC should deny the requested rate increase. The intervenor also stated that if the KPSC were to approve a rate increase, the settlement agreement should be modified to a $40 million annual increase in KPCo base rates based on an 8.9% ROE and a capital structure of 55% debt and 45% common equity. Additionally, the brief: (a) suggests increasing the amount of the first and second year revenue requirement reductions to $49 million and $28 million, respectively, relating to the new rider proposed in the settlement agreement that returns certain unprotected deferred tax expenses in customer rates on a temporary basis, (b) proposes that KPCo should be restricted from filing to recover Mitchell Plant non-ELG capital costs, expected to result from the approved settlement agreement in the 2025 Mitchell Plant CPCN proceeding, for a minimum of three years (see “Mitchell Plant Filing for Certificate of Public Convenience and Necessity” section above for additional information) and (c) recommends that the KPSC order an independent management audit to engage outside experts to determine how KPCo can improve its service and rates.

A KPSC order is expected to be issued in the first quarter of 2026 with implementation of KPCo retail rates in March 2026. If any costs included in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

OPCo Rate Matters (Applies to AEP and OPCo)

OVEC Cost Recovery Audits

In December 2021, as part of OVEC cost recovery audits pending before the PUCO, intervenors filed positions claiming that costs incurred by OPCo during the 2018-2019 audit period were imprudent and should be disallowed. In May 2022, intervenors filed for rehearing on the 2016-2017 OVEC cost recovery audit period claiming the PUCO’s April 2022 order to adopt the findings of the audit report were unjust, unlawful and unreasonable for multiple reasons, including the position that OPCo recovered imprudently incurred costs. In May 2023, as part of the OVEC cost recovery audits pending before the PUCO, intervenors filed positions claiming that costs incurred by OPCo during the 2020 audit period were imprudent and should be disallowed.

In August 2024, the PUCO issued orders pertaining to the OVEC cost recovery audits that: (a) denied intervenors’ application for rehearing on the 2016-2017 audit period, (b) determined costs incurred by OPCo during the 2018-2019 audit period were prudent, (c) determined costs incurred by OPCo during the 2020 audit period were prudent and (d) recommended no disallowances for any mentioned audit period in question. In September 2024, intervenors filed for rehearing on the 2018-2019 and 2020 OVEC cost recovery audit periods claiming the PUCO’s August 2024 orders to adopt the findings of the audit reports were unjust, unlawful and unreasonable for multiple reasons, including the position that OPCo recovered imprudently incurred costs. In October 2024, the PUCO denied the intervenors’ applications for rehearing of the 2018-2019 and 2020 audit periods. In December 2024, intervenors filed appeals with the Supreme Court of Ohio on the PUCO’s denial for rehearing. Oral arguments were conducted in December 2025 and the appeals are now fully submitted for decision.

In February and March 2025, as part of OVEC cost recovery audits pending before the PUCO, intervenors filed positions claiming that costs incurred by OPCo during the 2021-2023 audit period were imprudent and should be disallowed. Management disagrees with these claims and is unable to predict the impact of these disputes. An evidentiary hearing was held in November 2025 and post-hearing briefs were submitted in February 2026. If any costs are disallowed or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

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Ohio Legislation (HB 15)

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.

As a result of this legislation, OPCo recorded a $24 million reduction in 2025 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.

2025 Ohio Base Rate Case

In May 2025, OPCo filed a request with the PUCO for a net $97 million annual increase in distribution base rates based upon a 10.9% ROE and a proposed capital structure of 49.1% debt and 50.9% common equity. The requested net annual increase in base rates excluded $308 million of existing annual rider revenue requirements (including the DIR) that OPCo proposed to be rolled into base rates upon the anticipated 2026 change in distribution base rates in this filing. The distribution base case filing also requests a revenue cap increase for the DIR and cost cap increase for OPCo’s existing Enhanced Service Reliability Rider (ESRR).

In October 2025, the PUCO staff filed its required report recommending a net annual decrease in distribution base rates ranging from $12 million to $28 million, based upon an ROE range of 9.33% to 9.84%. The PUCO staff recommended the exclusion of $59 million of certain utility investments and $55 million of capitalized incentives from rate base, and a reduction in employee-related expenses of $23 million. In addition, the PUCO staff recommended increases to the DIR revenue cap and ESRR cost cap that were less than OPCo’s requested increases. Responses to the PUCO staff report were submitted in November 2025 and a hearing was held in January 2026.

In January 2026, OPCo, the PUCO staff, and certain intervenors filed a settlement agreement with the PUCO. After incorporating reductions to rider rates, the settlement reflects an annual net revenue increase of $11 million based upon a 9.84% ROE while also securing a reduction in customer rates through the amortization of $82 million of deferred tax regulatory liabilities over 18 months, an item not included in the original application. The resulting overall annual revenue impact is a net decrease of $59 million. The difference between OPCo’s requested annual base rate increase and the settlement is primarily due to a reduction in the requested ROE and the resolution of various rate base and operating income issues raised in the PUCO staff report. Additionally, the agreement proposes increased revenue caps for the DIR, annual cost cap increases in the ESRR and would result in no material disallowances.

If the settlement agreement is approved by the PUCO, new base rates will go into effect 14 days after such approval. If any costs included in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

PSO Rate Matters (Applies to AEP and PSO)

2024 Oklahoma Base Rate Case

In January 2024, PSO filed a request with the OCC for a $218 million annual base rate increase based upon a 10.8% ROE with a capital structure of 48.9% debt and 51.1% common equity. PSO requested an expanded transmission cost recovery rider and a mechanism to recover generation costs necessary to comply with SPP’s 2023 increased capacity planning reserve margin requirements. PSO’s request includes the 155 MW Rock Falls Wind Facility and reflects recovery of Northeastern Plant, Unit 3 through 2040.

In October 2024, PSO, the OCC and certain intervenors filed a joint stipulation and settlement agreement with the OCC that included a net annual revenue increase of $120 million based upon a 9.5% ROE with a capital structure of 48.9% debt and 51.1% common equity. The agreement also allows for Rock Falls Wind Facility to be included in base rates and the deferral of certain generation-related costs necessary to comply with SPP’s 2023 increased capacity reserve margin requirements. One

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intervenor opposed the joint stipulation and settlement agreement. In October 2024, a hearing was held at the OCC, and PSO implemented an interim annual base rate increase of $120 million, subject to refund pending a final order by the OCC.

In January 2025, the OCC issued a final order approving the joint stipulation and settlement agreement without modification. In February 2025, an Oklahoma state representative filed an appeal of the final order in PSO’s base rate case. The appeal does not contest the reasonableness of the rates established under the joint stipulation and settlement agreement approved without modification in the final order, but rather raises issues related to one OCC commissioner’s participation in voting on the order and the sufficiency of an OCC audit. If the appeal is successful and the OCC modifies the final order in a future proceeding, it could reduce future net income and cash flows and impact financial condition.

2026 Oklahoma Base Rate Case

In January 2026, PSO filed a request with the OCC for a $299 million annual base rate increase based upon a 10.5% ROE with a capital structure of 50.1% debt and 49.9% common equity, net of existing rider revenue and certain incremental renewable facility benefits expected to be provided to customers through riders. PSO also requested an expanded transmission cost recovery rider and a new vegetation management rider. Further, PSO is seeking approval of new large load special terms and conditions in the Large Power and Light tariff. If any costs included in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters (Applies to AEP and SWEPCo)

2020 Texas Base Rate Case

In October 2020, SWEPCo filed a request with the PUCT for a $105 million annual increase in Texas base rates based upon a proposed 10.35% ROE. The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $90 million primarily due to increased investments. SWEPCo subsequently filed a request with the PUCT lowering the requested annual increase in Texas base rates to $100 million which would result in an $85 million net annual base rate increase after moving the proposed riders to rate base.

In January 2022, the PUCT issued a final order approving an annual revenue increase of $39 million based upon a 9.25% ROE. The order also includes: (a) rates implemented retroactively back to March 18, 2021, (b) $5 million of the proposed increase related to vegetation management, (c) $2 million annually to establish a storm catastrophe reserve and (d) the creation of a rider to recover the Dolet Hills Power Station as if it were in rate base until its retirement at the end of 2021 and starting in 2022 the remaining net book value to be recovered as a regulatory asset through 2046. As a result of the final order, SWEPCo recorded a disallowance of $12 million in 2021 associated with the lack of return on the Dolet Hills Power Station. In February 2022, SWEPCo filed a motion for rehearing with the PUCT challenging several errors in the order, which include challenges of the approved ROE, the denial of a reasonable return or carrying costs on the Dolet Hills Power Station and the calculation of the Texas jurisdictional share of the storm catastrophe reserve. In April 2022, the PUCT denied the motion for rehearing. In May 2022, SWEPCo filed a petition for review with the Texas District Court seeking a judicial review of the several errors challenged in the PUCT’s final order.

2025 Arkansas Base Rate Case

In March 2025, SWEPCo filed a request with the APSC for a $114 million annual base rate increase based upon a 10.9% ROE with a capital structure of 52.3% debt and 47.7% common equity. The increase includes the Arkansas jurisdictional share of Diversion and Wagon Wheel wind facilities. SWEPCo is also electing to have its rates regulated under a Formula Rate Review mechanism.

In November 2025, an uncontested settlement agreement was filed with the APSC for an $85 million annual base rate increase based upon a 9.65% ROE with a capital structure of 55.7% debt and 44.3% common equity. The settlement agreement allowed SWEPCo to recover the Arkansas jurisdictional share of the remaining net book value of the Pirkey Plant over 10 years and earn a return of 3%, and the agreement also included a provision that the retirement of the Pirkey Plant was prudent. In January 2026, the APSC issued an order approving the settlement agreement as filed.

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2025 Texas Base Rate Case

In October 2025, SWEPCo filed a request with the PUCT for a $164 million annual increase in Texas base rates based upon a 10.75% ROE and a proposed capital structure of 48% debt and 52% common equity. The request would move certain revenues recovered through riders, including interim revenues on transmission and distribution investment since the 2020 Texas Base Rate Case, into base rates resulting in a net annual rate increase of $95 million. The proposed net annual increase includes recovery of the Texas jurisdictional share of the retired Pirkey Plant through depreciation expense and requests $21 million annually to recover deferred storm costs and expand the utility’s self-insurance reserve for potential losses and damages. Intervenor and staff testimony is due in March 2026 and a hearing is scheduled for April 2026. If any costs included in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

PSO and SWEPCo Rate Matters (Applies to AEP, PSO and SWEPCo)

North Central Wind Energy Facilities (NCWF)

The NCWF are subject to various regulatory performance requirements, including a Net Capacity Factor (NCF) guarantee. The NCF guarantee measures in MWhs across all facilities on a combined basis for each five year period for the first thirty full years of operation. The first NCF guarantee five year period began in April 2022. Certain wind turbines experienced performance issues that prompted PSO and SWEPCo to file a lawsuit against the manufacturer, which led to an agreement between PSO and SWEPCo and the manufacturer that addressed the performance issues. If regulatory performance requirements, such as the NCF guarantee, are not met, PSO and SWEPCo may recognize a regulatory liability associated with a refund to retail customers.

FERC Rate Matters

Independence Energy Connection Project (Applies to AEP)

In 2016, PJM approved the Independence Energy Connection Project (IEC) and included it in its Regional Transmission Expansion Plan to alleviate congestion. Transource Energy has an ownership interest in the IEC, which is located in Maryland and Pennsylvania. In June 2020, the Maryland Public Service Commission approved a CPCN to construct the portion of the IEC in Maryland. In May 2021, the Pennsylvania Public Utility Commission (PAPUC) denied the IEC certificate for siting and construction of the portion in Pennsylvania. Transource Energy appealed the PAPUC ruling in Pennsylvania state court and challenged the ruling before the United States District Court for the Middle District of Pennsylvania. In May 2022, the Pennsylvania state court issued an order affirming the PAPUC decision as to state law claims. In December 2023, the United States District Court for the Middle District of Pennsylvania granted summary judgment in favor of Transource Energy, finding that the PAPUC decision violated federal law and the United States Constitution. In January 2024, the PAPUC filed an appeal of the district court’s grant of summary judgment with the United States Court of Appeals for the Third Circuit. In September 2025, the United States Court of Appeals for the Third Circuit affirmed the December 2023 district court order in favor of Transource Energy. In October 2025, the Maryland Public Service Commission approved an extension of the construction commencement deadline to May 2026. Additional regulatory proceedings before the PAPUC are expected to resume in 2026.

In September 2021, PJM notified Transource Energy that the IEC was suspended to allow for the regulatory and related appeals process to proceed in an orderly manner without breaching milestone dates in the project agreement. At that time, PJM stated that the IEC had not been canceled and remained necessary to alleviate congestion. In July 2025, PJM removed the IEC from suspended status and indicated the project going forward will be included in PJM’s models with a modified scope. PJM continues to evaluate reliability and market efficiency in the area. As of December 31, 2025, AEP’s share of IEC capital expenditures was approximately $92 million, located in Total Property, Plant and Equipment - Net on AEP’s balance sheets. The FERC has previously granted abandonment benefits for this project, allowing the full recovery of prudently incurred costs if the project is canceled for reasons outside the control of Transource Energy. If any of the IEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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FERC 2021 PJM and SPP Transmission Formula Rate Challenge (Applies to all Registrant Subsidiaries except AEP Texas)

The Registrants transitioned to stand-alone treatment of NOLCs in their PJM and SPP transmission formula rates beginning with the 2022 projected transmission revenue requirements and 2021 true-up to actual transmission revenue requirements, and provided notice of this change in informational filings made with the FERC. The annual revenue requirement increase as a result of the transition to stand-alone treatment of NOLCs for transmission formula rates is shown in the table below:

2021		2022		2023		2024		2025		Total
(in millions)
$	78	$	68	$	61	$	52	$	49	$	308

In January 2024, the FERC issued two orders granting formal challenges by certain unaffiliated customers related to stand-alone treatment of NOLCs in the 2021 Transmission Formula Rates of the AEP transmission owning subsidiaries within PJM and SPP. The FERC directed the AEP transmission owning subsidiaries within PJM and SPP to provide refunds with interest on all amounts collected for the 2021 rate year, and for such refunds to be reflected in the annual update for the next rate year. Accordingly, AEP transmission owning subsidiaries within PJM and SPP are providing refunds for the 2021 rate year, primarily through 2025 projected transmission revenue requirements. AEP transmission owning subsidiaries within PJM and SPP have not been directed to make cash refunds related to 2022 through 2025 rate years. As a result of the January 2024 FERC orders, the Registrants’ balance sheets reflected a liability for the probable refund of all NOLC revenues included in transmission formula rates, with interest.

In February 2024, AEPSC on behalf of the AEP transmission owning subsidiaries within PJM and SPP filed requests for rehearing. In March 2024, the FERC denied AEPSC’s requests for rehearing of the January 2024 orders by operation of law and stated it may address the requests for rehearing in future orders. In March 2024, AEPSC submitted refund compliance reports to the FERC, which preserve the non-finality of the FERC’s January 2024 orders pending further proceedings on rehearing and appeal. In April 2024, AEPSC made filings with the FERC which requested that the FERC: (a) reopen the record so that the FERC may take the IRS PLRs received in April 2024 regarding the treatment of stand-alone NOLCs in ratemaking into evidence and consider them in substantive orders on rehearing and (b) stay its January 2024 orders and related compliance filings and refunds to provide time for consideration of the April 2024 IRS PLRs. In May 2024, AEPSC filed a petition for review with the United States Court of Appeals for the District of Columbia Circuit seeking review of the FERC’s January 2024 and March 2024 decisions. In July 2024, the FERC issued orders approving AEPSC’s request to reopen the record for the limited purpose of accepting into the record the IRS PLRs and establish additional briefing procedures. In August 2024, AEPSC filed briefs with the FERC requesting the commission modify or overturn its initial orders.

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. Requests for rehearing were filed by intervenors in July 2025 and were rejected by FERC on the merits in November 2025. Intervenors have filed petitions for review of the FERC’s orders in this matter with the United States Court of Appeals for the District of Columbia Circuit. The appeals have been consolidated and are pending the establishment of a procedural schedule.

As directed by the FERC in its June 2025 order, AEP transmission owning subsidiaries within PJM and SPP submitted compliance filings in August 2025 that revised the March 2024 refund compliance reports and permit the collection of excess refunds provided to customers, with interest, in the annual update for the 2025 rate year. In October 2025, intervenors filed comments in response to the compliance filings, which remain pending before the FERC.

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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. Increases in affiliated transmission expense, which correspond to affiliated transmission revenues recognized, were deferred as an increase to regulatory assets or a reduction to regulatory liabilities on the balance sheets where management expects that expense would be collected from retail customers through authorized retail jurisdiction rider mechanisms. The table below summarizes the impact to the statements of income recorded by the Registrants in the second quarter of 2025:

	AEP		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Total Revenues	$	270	$	214	$	6	$	11	$	—	$	6	$	27
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(24)		—		(17)		—		—		—		—
Other Operation	53		—		15		(6)		—		19		10
Income (Loss) Before Income Tax Expense (Benefit)	241		214		8		17		—		(13)		17
Income Tax Expense (Benefit)	(313)		(203)		(21)		(28)		—		(16)		(39)
Net Income	554		417		29		45		—		3		56
Net Income Attributable to Noncontrolling Interest	55		55		—		—		—		—		—
Earnings Attributable to Common Shareholder	$	499	$	362	$	29	$	45	$	—	$	3	$	56

Request to Update SWEPCo Generation Depreciation Rates (Applies to AEP and SWEPCo)

In October 2023, SWEPCo filed an application to revise its generation wholesale customer’s contracts to reflect an increase in the annual revenue requirement of approximately $5 million for updated depreciation rates and allow for the return on and of FERC customers jurisdictional share of regulatory assets associated with retired plants. In November 2023, certain intervenors filed a motion with the FERC protesting and recommending the rejection of SWEPCo’s filings. In December 2023, the FERC issued an order approving the proposed rates effective January 1, 2024, subject to further review and refund and established hearing and settlement proceedings. In October 2025, a settlement agreement was filed with the FERC. In November 2025, the settlement judge certified the settlement agreement to the FERC as an uncontested settlement. In January 2026, the FERC issued an order approving the settlement agreement. The order did not have a material impact on SWEPCo’s financial condition, results of operations or cash flows.

Transmission Agreement Cost Allocation Complaint (Applies to AEP, APCo, I&M and OPCo)

In March 2025, the KPSC and the Attorney General of Kentucky filed a complaint at the FERC against AEPSC and the AEP East Companies challenging the manner in which costs are allocated for local transmission projects pursuant to the TA. The complaint contends that certain costs allocated to KPCo are unjust, unreasonable and provide no benefit to KPCo customers. The relief requested in the complaint includes requiring a revision to the TA so that the costs for local transmission projects remain exclusively with the retail distribution service territory where the project is located unless a specific project is granted approval to establish a different cost allocation by the state commissions. Various parties have filed comments and motions to intervene. In May 2025, AEP filed a motion to dismiss and answered the complaint. In November 2025, the FERC issued an order denying the KPSC and Attorney General of Kentucky complaint. In December 2025, the KPSC and Attorney General of Kentucky requested a rehearing of the November order denying the complaint. In January 2026, the FERC issued a notice of denial of the request for rehearing by operation of law, providing the FERC with additional time to consider and decide on the merits of the request. In February 2026, the KPSC and Attorney General of Kentucky filed a petition for review of the FERC’s orders in this matter with the United States Court of Appeals for the Sixth Circuit. If the FERC orders a change in the way costs are allocated pursuant to the TA it could impact future net income, cash flows and financial condition.

FERC Audit (Applies to AEP and SWEPCo)

SWEPCo is currently under audit by FERC’s Division of Audits and Accounting. The audit is evaluating SWEPCo’s compliance with certain accounting and reporting requirements under various FERC regulations, including compliance with the approved terms, rates, and conditions of its SPP transmission formula rate mechanism. Management is unable to predict the outcome of the audit. If any refund liabilities are imposed by the FERC or any disallowances occur, it would reduce future net income and cash flows and impact financial condition.

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5.  EFFECTS OF REGULATION

The disclosures in this note apply to all Registrants unless indicated otherwise.

Regulated Generating Units (Applies to AEP, PSO and SWEPCo)

Compliance with extensive environmental regulations requires significant capital investment in environmental monitoring, installation of pollution control equipment, emission fees, disposal costs and permits. Management regularly evaluates cost estimates of complying with these regulations in balance with reliability and other factors, which has resulted in, and in the future may result in, a proposal to retire generating facilities earlier than their currently estimated useful lives.

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 reduce future net income and cash flows and impact financial condition.

Regulated Generating Unit that has been Retired and Related Fuel Operations

SWEPCo

In March 2023, the Pirkey Plant was retired. SWEPCo is recovering, or is seeking recovery of, the remaining net book value of Pirkey Plant non-fuel costs. As of December 31, 2025, SWEPCo’s share of the net investment in the Pirkey Plant was $206 million, including materials and supplies, net of cost of removal. Fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions.

As part of the 2021 Arkansas Base Rate Case, the APSC granted SWEPCo regulatory asset treatment of the Pirkey Plant net investment. SWEPCo requested recovery including a weighted average cost of capital carrying charge in its 2025 Arkansas Base Rate Case. In January 2026, the APSC approved a settlement agreement providing for the recovery of the Pirkey Plant net investment over 10 years with a 3% return, and the agreement also included a provision that the retirement of the Pirkey Plant was prudent. See the “2025 Arkansas Base Rate Case” section of Note 4 for additional information. As of December 31, 2025, the Arkansas jurisdictional share of the net book value of the Pirkey Plant was $41 million.

As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana jurisdictional share of the Pirkey Plant, through a separate rider, through 2032.

In July 2023, the LPSC ordered that a separate proceeding be established to review the prudence of the decision to retire the Pirkey Plant, including the costs included in fuel for years starting in 2019 and after. In April 2025, the LPSC determined the retirement of the Pirkey Plant was reasonable and prudent and authorized continued recovery of and on the remaining balance of the Pirkey Plant at SWEPCo’s weighted average cost of capital through 2032.

In July 2023, Texas ALJs issued a PFD that concluded the decision to retire the Pirkey Plant was prudent. In September 2023, the PUCT rejected this conclusion in the ALJ’s July 2023 PFD. 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 “2025 Texas Base Rate Case” section of Note 4 for additional information. As of December 31, 2025, the Texas jurisdictional share of the net book value of the Pirkey Plant was $76 million. To the extent any portion of the Texas jurisdictional share of the net book value of the Pirkey Plant is not recoverable, it could reduce future net income and cash flows and impact financial condition.

In September 2023, the PUCT approved an unopposed settlement agreement that provides recovery of $33 million of Sabine related fuel costs through 2035. In June 2024, SWEPCo filed a fuel reconciliation with the PUCT for its retail operation in Texas for the period of January 2022 through December 2023. The fuel reconciliation included approximately $535 million in Texas jurisdictional eligible fuel costs. In January 2025, intervenors filed testimony recommending a disallowance of Texas jurisdictional fuel costs ranging from $2 million to $33 million related to SWEPCo’s decision to retire the Pirkey Plant, management of fuel inventory and SWEPCo’s energy price offers in SPP. In April 2025, a settlement agreement was filed with the PUCT resolving the issues in the case and resulting in a one-time $6 million disallowance of fuel costs. In July 2025, the PUCT issued an order approving the settlement agreement.

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Regulated Generating Units to be Retired

PSO

In 2014, PSO received final approval from the Federal EPA to close Northeastern Plant, Unit 3, in 2026. The plant was originally scheduled to close in 2040. As a result of the early retirement date, PSO revised the useful life of Northeastern Plant, Unit 3, to the projected retirement date of 2026 and the incremental depreciation is being deferred as a regulatory asset. Following the 2024 Oklahoma Base Rate Case, PSO continues to recover Northeastern Plant, Unit 3 through 2040. In April 2025, PSO and the 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. The ODEQ is in the process of preparing a SIP submission for the Federal EPA’s review and approval.

SWEPCo

In November 2020, management announced that it will cease using coal at the Welsh Plant in 2028. As a result of the announcement, SWEPCo began recording a regulatory asset for accelerated depreciation. 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.

The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of December 31, 2025 of generating facilities planned for retirement:

Plant	Net Book Value		Accelerated Depreciation Regulatory Asset		Cost of Removal Regulatory Liability			Projected Retirement Date		Current Authorized Recovery Period	Annual Depreciation (a)
	(dollars in millions)
Northeastern Plant, Unit 3	$	73	$	221	$	21	(b)	2026		(c)	$	15
Welsh Plant, Units 1 and 3	269		220		56		(d)	2028	(e)	(f)	47

(a)Represents the amount of annual depreciation that has been collected from customers over the prior 12-month period.

(b)Includes Northeastern Plant, Unit 4, which was retired in 2016. Removal of Northeastern Plant, Unit 4, will be performed with the removal of Northeastern Plant, Unit 3, after retirement.

(c)Northeastern Plant, Unit 3 is currently being recovered through 2040.

(d)Includes Welsh Plant, Unit 2, which was retired in 2016. Removal of Welsh Plant, Unit 2, will be performed with the removal of Welsh Plant, Units 1 and 3, after retirement.

(e)Represents projected retirement date of coal assets.

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

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Regulatory Assets and Liabilities

Regulatory assets and liabilities are comprised of the following items:

	AEP
	December 31,				Remaining Recovery Period
	2025		2024
Current Regulatory Assets	(in millions)
Under-recovered Fuel Costs - does not earn a return	$	202	$	116	1 year
Under-recovered Fuel Costs - earns a return	140		246		1 year
Unrecovered Winter Storm Fuel Costs - earns a return (a)	84		84		1 year
Total Current Regulatory Assets	$	426	$	446
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Earning a Return
Welsh Plant, Units 1 and 3 Accelerated Depreciation	$	220	$	169
Pirkey Plant Accelerated Depreciation	93		121
Unified Tracker Mechanism Deferred Costs	56		—
Storm-Related Costs	43		51
Unrecovered Winter Storm Fuel Costs (a)	—		33
Other Regulatory Assets Pending Final Regulatory Approval	23		21
Total Regulatory Assets Currently Earning a Return	435		395
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs - Asset Retirement Obligation Costs (b)	257		357
Storm-Related Costs (c)	191		301
2024-2025 Virginia Biennial Under-Earnings (d)	172		78
NOLC Costs (e)	89		93
Other Regulatory Assets Pending Final Regulatory Approval	163		87
Total Regulatory Assets Currently Not Earning a Return	872		916
Total Regulatory Assets Pending Final Regulatory Approval	1,307		1,311
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant (f)	470		661		21 years
Long-term Under-recovered Fuel Costs - West Virginia	254		284		9 years
Storm-Related Costs	100		107		6 years
Pirkey Plant Accelerated Depreciation - Louisiana	72		66		7 years
Fuel Mine Closure Costs - Texas	65		71		10 years
Pirkey Plant Accelerated Depreciation - Arkansas	41		—		10 years
PJM/SPP Annual Formula Rate True-up	35		—		2 years
Rockport Plant Dry Sorbent Injection System and Selective Catalytic Reduction	28		37		3 years
Texas Mobile Temporary Emergency Electric Energy Facilities Rider	27		33		2 years
Environmental Control Projects	27		29		15 years
Unrecovered Winter Storm Fuel Costs (a)	22		63		2 years
Plant Retirement Costs - Asset Retirement Obligation Costs	1		111		15 years
Kentucky Deferred Purchased Power Expenses	—		45
Other Regulatory Assets Approved for Recovery	199		204		various
Total Regulatory Assets Currently Earning a Return	1,341		1,711
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status	796		974		12 years
Plant Retirement Costs - Asset Retirement Obligation Costs	459		360		17 years
Storm-Related Costs	158		67		6 years
Unamortized Loss on Reacquired Debt	85		91		23 years
Cook Plant Nuclear Refueling Outage Levelization	82		43		3 years
Unrealized Loss on Forward Commitments	69		53		7 years
Ohio Enhanced Service Reliability Plan	58		26		2 years
Plant Retirement Costs - Unrecovered Plant, Texas	45		45		21 years
Smart Grid Costs	44		34		2 years
Renewable Resource Rider	38		—		2 years
Bad Debt Rider	35		22		2 years
West Virginia Environmental Compliance Surcharge	33		26		2 years
Postemployment Benefits	28		28		2 years
Fuel and Purchased Power Adjustment Rider	4		57		2 years
OVEC Purchased Power	—		52
Other Regulatory Assets Approved for Recovery	222		229		various
Total Regulatory Assets Currently Not Earning a Return	2,156		2,107
Total Regulatory Assets Approved for Recovery	3,497		3,818
Total Noncurrent Regulatory Assets	$	4,804	$	5,129

216

(a)In February 2021, severe winter weather had a significant impact in SPP, resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. For the time period of February 9, 2021 to February 20, 2021, SWEPCo’s natural gas expenses and purchases of electricity still to be recovered from customers are $106 million, of which $22 million, $41 million and $43 million is related to Arkansas, Louisiana and Texas jurisdictions, respectively. Previously, the APSC and PUCT approved recovery with a carrying charge in their jurisdictions over a six-year and five-year period, respectively. In November 2025, the LPSC issued an order approving a recovery period of five years in Louisiana with a carrying charge at the prime rate.

(b)See “Federal EPA’s Revised CCR Rule” section of Note 6 for additional information.

(c)Includes $40 million of West Virginia jurisdictional storm operation and maintenance costs as of December 31, 2025 that are subject to a future final securitization financing order from the WVPSC.

(d)In November 2025, the Virginia SCC issued a financing order approving securitization that includes $141 million of storm operation and maintenance costs as of December 31, 2025 that are subject to a final review by the Virginia SCC after bond pricing.

(e)Approved for collection through rates, subject to refund, for the Oklahoma and SWEPCo-Texas jurisdictions.

(f)Amount includes Northeastern Plant, Unit 3 which is approved for recovery through 2040, but expected to retire in 2026. PSO records a regulatory asset for accelerated depreciation. In April 2025, PSO and the ODEQ finalized an agreement, contingent upon approval by the Federal EPA, that would allow the Northeastern Plant, Unit 3, to continue operation on natural gas through May 31, 2041. See “Regulated Generating Units to be Retired” section above for additional information.

217

	AEP
	December 31,				Remaining
	2025		2024		Refund Period
Current Regulatory Liabilities	(in millions)
Over-recovered Fuel Costs - pays a return	$	54	$	22	1 year
Over-recovered Fuel Costs - does not pay a return	10		32		1 year
Total Current Regulatory Liabilities	$	64	$	54
Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:
Regulatory Liabilities Currently Paying a Return
Income Taxes, Net (a)	$	90	$	176
Total Regulatory Liabilities Currently Paying a Return	90		176
Regulatory Liabilities Currently Not Paying a Return
FERC 2021 Transmission Formula Rate Challenge Refunds	—		131
Other Regulatory Liabilities Pending Final Regulatory Determination	29		15
Total Regulatory Liabilities Currently Not Paying a Return	29		146
Total Regulatory Liabilities Pending Final Regulatory Determination	119		322
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	4,023		3,828		(b)
Income Taxes, Net (a)	1,048		1,622		(c)
Green Country Contract Liability	59		—		30 years
Rockport Plant, Unit 2 Accelerated Depreciation for Leasehold Improvements	27		36		4 years
Other Regulatory Liabilities Approved for Payment	39		40		various
Total Regulatory Liabilities Currently Paying a Return	5,196		5,526
Regulatory Liabilities Currently Not Paying a Return
Excess Nuclear Decommissioning Funding	2,557		2,137		(d)
Deferred Investment Tax Credits	64		65		25 years
Demand Side Management	54		53		2 years
Spent Nuclear Fuel	51		50		(d)
Unrealized Gain on Forward Commitments	46		10		3 years
PJM Costs and Off-system Sales Margin Sharing - Indiana	40		2		2 years
Peak Demand Reduction/Energy Efficiency	39		33		2 years
Over-recovered Fuel Costs - Ohio	38		32		7 years
2017-2019 Virginia Triennial Revenue Provision	33		35		24 years
Other Regulatory Liabilities Approved for Payment	125		79		various
Total Regulatory Liabilities Currently Not Paying a Return	3,047		2,496
Total Regulatory Liabilities Approved for Payment	8,243		8,022
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	8,362	$	8,344

(a)Predominately pays a return due to the inclusion of Excess ADIT in rate base.

(b)Relieved as removal costs are incurred.

(c)Refunded over the period for which the related deferred income taxes reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $269 million and $192 million for the years ended December 31, 2025 and 2024, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2025 is to be refunded over 8 years.

(d)Relieved when plant is decommissioned.

218

	AEP Texas
	December 31,				Remaining Recovery Period
Regulatory Assets:	2025		2024
	(in millions)
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Earning a Return
Unified Tracker Mechanism Deferred Costs	$	56	$	—
Storm-Related Costs	41		41
System Resiliency Plan Deferred Costs	17		—
Total Regulatory Assets Currently Earning a Return	114		41
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	31		13
Deferred Pension and OPEB Costs	27		16
Other Regulatory Assets Pending Final Regulatory Approval	9		7
Total Regulatory Assets Currently Not Earning a Return	67		36
Total Regulatory Assets Pending Final Regulatory Approval	181		77
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Texas Mobile Temporary Emergency Electric Energy Facilities Rider	27		33		2 years
Meter Replacement Costs	4		6		2 years
Other Regulatory Assets Approved for Recovery	18		22		various
Total Regulatory Assets Currently Earning a Return	49		61
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status	155		178		12 years
Peak Demand Reduction/Energy Efficiency	13		9		2 years
Texas Transmission Cost Recovery Factor	—		14
Other Regulatory Assets Approved for Recovery	4		15		various
Total Regulatory Assets Currently Not Earning a Return	172		216
Total Regulatory Assets Approved for Recovery	221		277
Total Noncurrent Regulatory Assets	$	402	$	354

219

	AEP Texas
	December 31,				Remaining Refund Period
Regulatory Liabilities:	2025		2024
	(in millions)
Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	$	880	$	844	(b)
Income Taxes, Net (a)	373		409		(c)
Other Regulatory Liabilities Approved for Payment	4		5		various
Total Regulatory Liabilities Currently Paying a Return	1,257		1,258
Regulatory Liabilities Currently Not Paying a Return
Transition and Restoration Charges	17		22		4 years
Transmission Cost Recovery Factor	7		—		2 years
Other Regulatory Liabilities Approved for Payment	5		5		various
Total Regulatory Liabilities Currently Not Paying a Return	29		27
Total Regulatory Liabilities Approved for Payment	1,286		1,285
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	1,286	$	1,285

(a)Predominately pays a return due to the inclusion of Excess ADIT in rate base.

(b)Relieved as removal costs are incurred.

(c)Refunded over the period for which the related deferred income taxes reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $16 million and $22 million for the years ended December 31, 2025 and 2024, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2025 is to be refunded over 4 years.

220

	AEPTCo
	December 31,				Remaining Recovery Period
Regulatory Assets:	2025		2024
	(in millions)
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Earning a Return
Income Taxes, Net	$	9	$	—
Total Regulatory Assets Pending Final Regulatory Approval	9		—
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Income Taxes, Net	49		—		(a)
PJM/SPP Annual Formula Rate True-up	15		—		2 years
Total Regulatory Assets Approved for Recovery	64		—
Total Noncurrent Regulatory Assets	$	73	$	—

	AEPTCo
	December 31,				Remaining Refund Period
Regulatory Liabilities:	2025		2024
	(in millions)
Noncurrent Regulatory Liabilities
Regulatory liabilities pending final regulatory determination:
Regulatory Liabilities Currently Paying a Return
Income Taxes, Net (b)	$	—	$	9
Total Regulatory Liabilities Pending Final Regulatory Determination	—		9
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	708		582		(c)
Income Taxes, Net (b)	—		287		(d)
Total Regulatory Liabilities Approved for Payment	708		869
Total Noncurrent Regulatory Liabilities	$	708	$	878

(a)Recovered over the period for which the related deferred income taxes reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements was $6 million for the year ended December 31, 2025 and is to be refunded over 2 years.

(b)Predominately pays a return due to the inclusion of Excess ADIT in rate base.

(c)Relieved as removal costs are incurred.

(d)Refunded over the period for which the related deferred income taxes reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements was $9 million for the year ended December 31, 2024.

221

	APCo
	December 31,				Remaining Recovery Period
Regulatory Assets:	2025		2024
	(in millions)
Current Regulatory Assets
Under-recovered Fuel Costs, Virginia - earns a return	$	71	$	148	1 year
Under-recovered Fuel Costs, West Virginia - does not earn a return	12		—		1 year
Total Current Regulatory Assets	$	83	$	148
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval	$	2	$	1
Total Regulatory Assets Currently Earning a Return	2		1
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs - Asset Retirement Obligation Costs (a)	169		282
2024-2025 Virginia Biennial Under-Earnings (b)	172		78
Storm-Related Costs - West Virginia (c)	39		144
Pension Settlement	16		18
Virginia Corporate Alternative Minimum Tax	13		—
West Virginia Corporate Alternative Minimum Tax	11		—
Other Regulatory Assets Pending Final Regulatory Approval	18		12
Total Regulatory Assets Currently Not Earning a Return	438		534
Total Regulatory Assets Pending Final Regulatory Approval	440		535
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Long-term Under-recovered Fuel Costs - West Virginia	138		154		9 years
Plant Retirement Costs - Unrecovered Plant	64		68		18 years
Excess SO2 Allowance Inventory	16		—		14 years
Other Regulatory Assets Approved for Recovery	7		5		various
Total Regulatory Assets Currently Earning a Return	225		227
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs - Asset Retirement Obligation Costs	404		308		16 years
Storm-Related Costs - West Virginia	107		—		5 years
Pension and OPEB Funded Status	89		108		12 years
Unamortized Loss on Reacquired Debt	63		67		20 years
Virginia Retail Consumable Costs	17		—		2 years
Virginia Transmission Rate Adjustment Clause	16		3		2 years
Virginia Clean Economy Act	16		—		2 years
2020-2022 Virginia Triennial Under-Earnings	14		26		2 years
Postemployment Benefits	13		13		2 years
Vegetation Management Program - West Virginia	12		12		2 years
Peak Demand Reduction/Energy Efficiency	10		14		2 years
Virginia Generation Rate Adjustment Clause	3		12		2 years
Excess SO2 Allowance Inventory	—		11		14 years
Other Regulatory Assets Approved for Recovery	10		30		various
Total Regulatory Assets Currently Not Earning a Return	774		604
Total Regulatory Assets Approved for Recovery	999		831
Total Noncurrent Regulatory Assets	$	1,439	$	1,366

(a)See “Federal EPA’s Revised CCR Rule” section of Note 6 for additional information.

(b)In November 2025, the Virginia SCC issued a financing order approving securitization that includes $141 million of storm operation and maintenance costs as of December 31, 2025 that are subject to a final review by the Virginia SCC after bond pricing.

(c)Includes $40 million of West Virginia jurisdictional storm operation and maintenance costs as of December 31, 2025 that are subject to a future final securitization financing order from the WVPSC.

222

	APCo
	December 31,				Remaining Refund Period
Regulatory Liabilities:	2025		2024
	(in millions)
Current Regulatory Liabilities
Over-recovered Fuel Costs, West Virginia - does not pay a return	$	—	$	22	1 year
Total Current Regulatory Liabilities	$	—	$	22
Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:
Regulatory Liabilities Currently Paying a Return
Income Taxes, Net (a)	$	—	$	(6)
Total Regulatory Liabilities Currently Paying a Return	—		(6)
Regulatory Liabilities Currently Not Paying a Return
FERC 2021 Transmission Formula Rate Challenge Refunds	—		25
Other Regulatory Liabilities Pending Final Regulatory Determination	3		—
Total Regulatory Liabilities Currently Not Paying a Return	3		25
Total Regulatory Liabilities Pending Final Regulatory Determination	3		19
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	831		806		(b)
Income Taxes, Net (a)	162		219		(c)
Total Regulatory Liabilities Currently Paying a Return	993		1,025
Regulatory Liabilities Currently Not Paying a Return
Unrealized Loss on Forward Commitments	34		8		3 years
2017-2019 Virginia Triennial Revenue Provision	33		35		24 years
Virginia Environmental Rate Adjustment Clause	18		10		2 years
Energy Efficiency Rate Adjustment Clause - Virginia	16		10		2 years
West Virginia Environmental Compliance Surcharge	11		—		2 years
Other Regulatory Liabilities Approved for Payment	3		9		various
Total Regulatory Liabilities Currently Not Paying a Return	115		72
Total Regulatory Liabilities Approved for Payment	1,108		1,097
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	1,111	$	1,116

(a)Predominately pays a return due to the inclusion of Excess ADIT in rate base.

(b)Relieved as removal costs are incurred.

(c)Refunded over the period for which the related deferred income taxes reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $11 million and $12 million for the years ended December 31, 2025 and 2024, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2025 is to be refunded over 3 years.

223

	I&M
	December 31,				Remaining Recovery Period
Regulatory Assets:	2025		2024
	(in millions)
Current Regulatory Assets
Under-recovered Fuel Costs, Michigan - earns a return	$	—	$	11	1 year
Total Current Regulatory Assets	$	—	$	11
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval	$	4	$	6
Total Regulatory Assets Currently Earning a Return	4		6
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs - Asset Retirement Obligation Costs (a)	78		74
Storm-Related Costs - Indiana	29		6
NOLC Costs - Indiana (b)	—		27
Other Regulatory Assets Pending Final Regulatory Approval	7		2
Total Regulatory Assets Currently Not Earning a Return	114		109
Total Regulatory Assets Pending Final Regulatory Approval	118		115
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant	73		98		3 years
Rockport Plant Dry Sorbent Injection System and Selective Catalytic Reduction	28		37		3 years
Cook Plant Uprate Project	18		21		8 years
Deferred Cook Plant Life Cycle Management Project Costs - Michigan, FERC	9		10		9 years
Cook Plant Turbine - Indiana	7		8		13 years
Other Regulatory Assets Approved for Recovery	22		21		various
Total Regulatory Assets Currently Earning a Return	157		195
Regulatory Assets Currently Not Earning a Return
Income Taxes, Net	165		109		(c)
Cook Plant Nuclear Refueling Outage Levelization	82		43		3 years
NOLC Costs - Indiana (b)	19		—		2 years
Storm-Related Costs - Indiana	14		20		3 years
Unamortized Loss on Reacquired Debt	10		11		23 years
Excess SO2 Allowance Inventory - Indiana	9		12		3 years
Pension and OPEB Funded Status	—		15
Other Regulatory Assets Approved for Recovery	11		28		various
Total Regulatory Assets Currently Not Earning a Return	310		238
Total Regulatory Assets Approved for Recovery	467		433
Total Noncurrent Regulatory Assets	$	585	$	548

(a)See “Federal EPA’s Revised CCR Rule” section of Note 6 for additional information.

(b)In the first quarter of 2025, the IURC approved the stand-alone treatment of NOLCs.

(c)Recovered over the period for which the related deferred income taxes reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $6 million and $12 million for the years ended December 31, 2025 and 2024, respectively, and is to be refunded over 2 years.

224

	I&M
	December 31,				Remaining Refund Period
Regulatory Liabilities:	2025		2024
	(in millions)
Current Regulatory Liabilities
Over-recovered Fuel Costs, Indiana - does not pay a return	$	10	$	10	1 year
Over-recovered Fuel Costs, Michigan - pays a return	9		—		1 year
Total Current Regulatory Liabilities	$	19	$	10
Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:
Regulatory Liabilities Currently Not Paying a Return
Cook Plant PTC Deferral - Michigan	$	26	$	15
FERC 2021 Transmission Formula Rate Challenge Refunds	—		29
Other Regulatory Liabilities Pending Final Regulatory Determination	1		—
Total Regulatory Liabilities Currently Not Paying a Return	27		44
Total Regulatory Liabilities Pending Final Regulatory Determination	27		44
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	172		174		(a)
Renewable Energy Surcharge - Michigan	22		24		2 years
Other Regulatory Liabilities Approved for Payment	7		—		various
Total Regulatory Liabilities Currently Paying a Return	201		198
Regulatory Liabilities Currently Not Paying a Return
Excess Nuclear Decommissioning Funding	2,557		2,137		(b)
Spent Nuclear Fuel	51		50		(b)
PJM Costs and Off-system Sales Margin Sharing - Indiana	35		2		2 years
Demand Side Management - Indiana	31		33		2 years
Pension and OPEB Funded Status	15		—		12 years
Deferred Investment Tax Credits	13		14		25 years
Other Regulatory Liabilities Approved for Payment	8		3		various
Total Regulatory Liabilities Currently Not Paying a Return	2,710		2,239
Total Regulatory Liabilities Approved for Payment	2,911		2,437
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	2,938	$	2,481

(a)Relieved as removal costs are incurred.

(b)Relieved when plant is decommissioned.

225

	OPCo
	December 31,				Remaining Recovery Period
Regulatory Assets:	2025		2024
	(in millions)
Noncurrent Regulatory Assets
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Ohio Basic Transmission Cost Rider	$	12	$	26	2 years
Other Regulatory Assets Approved for Recovery	2		—		various
Total Regulatory Assets Currently Earning a Return	14		26
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status	111		134		12 years
Ohio Enhanced Service Reliability Plan	58		26		2 years
Smart Grid Costs	44		34		2 years
Unrealized Loss on Forward Commitments	33		48		7 years
Bad Debt Rider	27		14		2 years
Storm-Related Costs	18		29		2 years
Ohio Basic Transmission Cost Rider	14		—		2 years
OVEC Purchased Power	—		52
Ohio Distribution Investment Rider	—		11
Other Regulatory Assets Approved for Recovery	7		5		various
Total Regulatory Assets Currently Not Earning a Return	312		353
Total Regulatory Assets Approved for Recovery	326		379
Total Noncurrent Regulatory Assets	$	326	$	379

226

	OPCo
	December 31,				Remaining Refund Period
	2025		2024
Regulatory Liabilities:	(in millions)
Noncurrent Regulatory Liabilities
Regulatory liabilities pending final regulatory determination:
Regulatory Liabilities Currently Paying a Return
Income Taxes, Net (a)	$	77	$	—
Total Regulatory Liabilities Currently Paying a Return	77		—
Regulatory Liabilities Currently Not Paying a Return
FERC 2021 Transmission Formula Rate Challenge Refunds	—		73
Total Regulatory Liabilities Currently Not Paying a Return	—		73
Total Regulatory Liabilities Pending Final Regulatory Determination	77		73
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	470		480		(b)
Income Taxes, Net (a)	271		368		(c)
Other Regulatory Liabilities Approved for Payment	1		4		various
Total Regulatory Liabilities Currently Paying a Return	742		852
Regulatory Liabilities Currently Not Paying a Return
Over-recovered Fuel Costs	38		32		7 years
Peak Demand Reduction/Energy Efficiency	23		23		2 years
Other Regulatory Liabilities Approved for Payment	13		8		various
Total Regulatory Liabilities Currently Not Paying a Return	74		63
Total Regulatory Liabilities Approved for Payment	816		915
Total Noncurrent Regulatory Liabilities	$	893	$	988

(a)Predominately pays a return due to the inclusion of Excess ADIT in rate base.

(b)Relieved as removal costs are incurred.

(c)Refunded over the period for which the related deferred income taxes reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $14 million and $100 million for the years ended December 31, 2025 and 2024, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2025 is to be refunded over 2 years.

227

	PSO
	December 31,				Remaining Recovery Period
	2025		2024
Regulatory Assets:	(in millions)
Current Regulatory Assets
Under-recovered Fuel Costs - earns a return	$	37	$	65	1 year
Total Current Regulatory Assets	$	37	$	65
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	$	25	$	5
NOLC Costs (a)	23		16
Generation PBA and Delayed Retirement Deferral	13		—
Other Regulatory Assets Pending Final Regulatory Approval	23		9
Total Regulatory Assets Pending Final Regulatory Approval	84		30
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Plant Retirement Costs - Unrecovered Plant (b)	302		274		21 years
Storm-Related Costs	90		107		6 years
Environmental Control Projects	20		21		15 years
Meter Replacement Costs	6		10		2 years
Other Regulatory Assets Approved for Recovery	16		14		various
Total Regulatory Assets Currently Earning a Return	434		426
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status	41		58		12 years
Renewable Resources Rider	38		—		2 years
Unrealized Loss on Forward Commitments	28		4		2 years
Other Regulatory Assets Approved for Recovery	12		10		various
Total Regulatory Assets Currently Not Earning a Return	119		72
Total Regulatory Assets Approved for Recovery	553		498
Total Noncurrent Regulatory Assets	$	637	$	528

(a)Approved for collection through rates, subject to refund.

(b)Amount includes Northeastern Plant, Unit 3 which is approved for recovery through 2040, but expected to retire in 2026. PSO records a regulatory asset for accelerated depreciation. In April 2025, PSO and the ODEQ finalized an agreement, contingent upon approval by the Federal EPA, that would allow the Northeastern Plant, Unit 3, to continue operation on natural gas through May 31, 2041. See “Regulated Generating Units to be Retired” section above for additional information.

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	PSO
	December 31,				Remaining Refund Period
	2025		2024
Regulatory Liabilities:	(in millions)
Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:
Regulatory Liabilities Currently Not Paying a Return
FERC 2021 Transmission Formula Rate Challenge Refunds	$	—	$	2
Total Regulatory Liabilities Pending Final Regulatory Determination	—		2
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	323		324		(a)
Income Taxes, Net (b)	285		318		(c)
Green Country Contract Liability	59		—		30 years
Total Regulatory Liabilities Currently Paying a Return	667		642
Regulatory Liabilities Currently Not Paying a Return
Deferred Investment Tax Credits	47		46		11 years
Other Regulatory Liabilities Approved for Payment	3		—		various
Total Regulatory Liabilities Currently Not Paying a Return	50		46
Total Regulatory Liabilities Approved for Payment	717		688
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	717	$	690

(a)Relieved as removal costs are incurred.

(b)Predominately pays a return due to the inclusion of Excess ADIT in rate base.

(c)Refunded over the period for which the related deferred income taxes reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets. Excess ADIT that is Not Subject to Rate Normalization Requirements were $41 million and $46 million for the years ended December 31, 2025 and 2024, respectively. The remaining balance of Excess ADIT that is Not Subject to Rate Normalization Requirements as of December 31, 2025 is to be refunded over 8 years.

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	SWEPCo
	December 31,				Remaining Recovery Period
	2025		2024
Regulatory Assets:	(in millions)
Current Regulatory Assets
Unrecovered Winter Storm Fuel Costs - earns a return (a)	$	84	$	84	1 year
Under-recovered Fuel Costs - earns a return (b)	31		23		1 year
Total Current Regulatory Assets	$	115	$	107
Noncurrent Regulatory Assets
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Earning a Return
Welsh Plant, Units 1 and 3 Accelerated Depreciation	$	220	$	169
Pirkey Plant Accelerated Depreciation	93		121
Storm-Related Costs	2		10
Unrecovered Winter Storm Fuel Costs (a)	—		33
Dolet Hills Power Station Accelerated Depreciation (c)	—		12
Other Regulatory Assets Pending Final Regulatory Approval	1		1
Total Regulatory Assets Currently Earning a Return	316		346
Regulatory Assets Currently Not Earning a Return
NOLC Costs (d)	66		50
Storm-Related Costs - Louisiana, Texas	43		40
Other Regulatory Assets Pending Final Regulatory Approval	20		18
Total Regulatory Assets Currently Not Earning a Return	129		108
Total Regulatory Assets Pending Final Regulatory Approval	445		454
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return
Pirkey Plant Accelerated Depreciation - Louisiana	72		66		7 years
Fuel Mine Closure Costs - Texas	65		71		10 years
Pirkey Plant Accelerated Depreciation - Arkansas	41		—		10 years
Plant Retirement Costs - Unrecovered Plant - Arkansas, Louisiana	31		40		17 years
Unrecovered Winter Storm Fuel Costs (a)	22		63		2 years
Plant Retirement Costs - Unrecovered Plant, Dolet Hills Power Station - Louisiana	15		19		7 years
Dolet Hills Power Station Fuel Costs - Louisiana	14		22		2 years
Dolet Hills Power Station Accelerated Depreciation (c)	13		—		21 years
Storm-Related Costs - Arkansas	10		—		3 years
Other Regulatory Assets Approved for Recovery	18		12		various
Total Regulatory Assets Currently Earning a Return	301		293
Regulatory Assets Currently Not Earning a Return
Pension and OPEB Funded Status	77		93		12 years
Plant Retirement Costs - Unrecovered Plant, Texas	45		45		21 years
Plant Retirement Costs - Unrecovered Plant, Arkansas	10		13		2 years
Other Regulatory Assets Approved for Recovery	25		23		various
Total Regulatory Assets Currently Not Earning a Return	157		174
Total Regulatory Assets Approved for Recovery	458		467
Total Noncurrent Regulatory Assets	$	903	$	921

(a)In February 2021, severe winter weather had a significant impact in SPP, resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. For the time period of February 9, 2021 to February 20, 2021, SWEPCo’s natural gas expenses and purchases of electricity still to be recovered from customers are $106 million, of which $22 million, $41 million and $43 million is related to Arkansas, Louisiana and Texas jurisdictions, respectively. Previously, the APSC and PUCT approved recovery with a carrying charge in their jurisdictions over a six-year and five-year period, respectively. In November 2025, the LPSC issued an order approving a recovery period of five years in Louisiana with a carrying charge at the prime rate.

(b)2025 amount related to Arkansas and Texas jurisdictions. 2024 amount related to Arkansas, Louisiana and Texas jurisdictions.

(c)Amounts include the FERC jurisdiction.

(d)Approved for collection through rates, subject to refund, for Texas jurisdiction.

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	SWEPCo
	December 31,				Remaining Refund Period
	2025		2024
Regulatory Liabilities:	(in millions)
Current Regulatory Liabilities
Over-recovered Fuel Costs - pays a return (a)	$	45	$	22	1 year
Total Current Regulatory Liabilities	$	45	$	22
Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
Regulatory liabilities pending final regulatory determination:
Regulatory Liabilities Currently Paying a Return
Income Taxes, Net (b)	$	7	$	7
Total Regulatory Liabilities Pending Final Regulatory Determination	7		7
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Paying a Return
Asset Removal Costs	459		457		(c)
Income Taxes, Net (b)	24		128		(d)
Other Regulatory Liabilities Approved for Payment	6		7		various
Total Regulatory Liabilities Currently Paying a Return	489		592
Regulatory Liabilities Currently Not Paying a Return
Demand Side Management	11		9		2 years
Other Regulatory Liabilities Approved for Payment	24		3		various
Total Regulatory Liabilities Currently Not Paying a Return	35		12
Total Regulatory Liabilities Approved for Payment	524		604
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits	$	531	$	611

(a)2025 amount related to Louisiana and Texas jurisdictions. 2024 amount related to Texas jurisdiction.

(b)Predominately pays a return due to the inclusion of Excess ADIT in rate base.

(c)Relieved as removal costs are incurred.

(d)Refunded over the period for which the related deferred income taxes reverse, which is generally based on the expected life for the underlying assets. Excess ADIT Associated with Certain Depreciable Property is refunded over the remaining depreciable life of the underlying assets.

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6.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

The disclosures in this note apply to all Registrants unless indicated otherwise.

The Registrants are subject to certain claims and legal actions arising in the ordinary course of business.  In addition, the Registrants’ business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted.  Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates.

For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements.

COMMITMENTS (Applies to all Registrants except AEP Texas and AEPTCo)

AEP subsidiaries have substantial commitments for fuel, energy and capacity contracts as part of the normal course of business. Certain contracts contain penalty provisions for early termination.

In accordance with the accounting guidance for “Commitments”, the following tables summarize the Registrants’ actual contractual commitments as of December 31, 2025:

Contractual Commitments - AEP	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Fuel Purchase Contracts (a)	$	1,103	$	1,560	$	338	$	241	$	3,242
Energy and Capacity Purchase Contracts	153		329		292		294		1,068
Construction Contract for Capital Assets (b)	600		725		—		—		1,325
Total	$	1,856	$	2,614	$	630	$	535	$	5,635

Contractual Commitments - APCo	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Fuel Purchase Contracts (a)	$	489	$	808	$	126	$	35	$	1,458
Energy and Capacity Purchase Contracts	39		71		43		33		186
Total	$	528	$	879	$	169	$	68	$	1,644

Contractual Commitments - I&M	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Fuel Purchase Contracts (a)	$	261	$	382	$	200	$	203	$	1,046
Energy and Capacity Purchase Contracts	113		242		149		205		709
Total	$	374	$	624	$	349	$	408	$	1,755

Contractual Commitments - OPCo	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Energy and Capacity Purchase Contracts	$	31	$	66	$	60	$	43	$	200

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Contractual Commitments - PSO	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Fuel Purchase Contracts (a)	$	28	$	12	$	—	$	—	$	40
Energy and Capacity Purchase Contracts	45		71		36		13		165
Total	$	73	$	83	$	36	$	13	$	205

Contractual Commitments - SWEPCo	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Fuel Purchase Contracts (a)	$	102	$	72	$	—	$	—	$	174
Energy and Capacity Purchase Contracts	7		2		—		—		9
Total	$	109	$	74	$	—	$	—	$	183

(a)Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel.

(b)In January 2026, an unregulated AEP subsidiary entered into an agreement to acquire solid oxide fuel cells for approximately $2.65 billion. This is not included in the presented commitments as of December 31, 2025.

GUARANTEES

Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.”  There is no collateral held in relation to any guarantees.  In the event any guarantee is drawn, there is no recourse to third-parties unless specified below.

Letters of Credit (Applies to AEP)

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 service reserves.

AEP has $5 billion and $1 billion revolving credit facilities due in March 2029 and March 2027, respectively. AEP may issue up to $1.2 billion as letters of credit under these revolving credit facilities on behalf of subsidiaries. As of December 31, 2025, no letters of credit were issued under the revolving credit facility.

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. 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 were as follows:

Company	Amount		Maturity
	(in millions)
AEP	$	377	January 2026 to November 2026

Indemnifications and Other Guarantees

Contracts

The Registrants enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  As of December 31, 2025, there were no material liabilities recorded for any indemnifications.

AEPSC conducts power purchase-and-sale activity on behalf of APCo, I&M, KPCo and WPCo, who are jointly and severally liable for activity conducted on their behalf.  AEPSC also conducts power purchase-and-sale activity on behalf of PSO and SWEPCo, who are jointly and severally liable for activity conducted on their behalf.

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Lease Obligations

Certain Registrants lease equipment under master lease agreements.  See “Master Lease Agreements” section of Note 13 for additional information.

ENVIRONMENTAL CONTINGENCIES (Applies to All Registrants except AEPTCo)

Federal EPA’s Revised CCR Rule

In April 2024, the Federal EPA finalized revisions to the CCR Rule (Legacy 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). The Federal EPA is requiring that owners and operators of legacy surface impoundments comply with all of the Legacy CCR Rule requirements applicable to inactive CCR surface impoundments at active facilities, except for the location restrictions and liner design criteria. The rule establishes compliance deadlines for legacy surface impoundments to meet regulatory requirements, including a requirement to initiate closure within five years after the effective date of the final rule. The rule requires evaluations to be completed at both active facilities and inactive facilities with one or more legacy surface impoundments. Closure may be accomplished by applying an impermeable cover system over the CCR material (closure in place) or the CCR material may be excavated and placed in a compliant landfill (closure by removal). Groundwater monitoring and other analysis over the next three years will provide additional information on the planned closure method. AEP evaluated the applicability of the rule to current and former plant sites and recorded incremental ARO in the second quarter of 2024, as shown in the table below, based on initial cost estimates primarily reflecting compliance with the rule through closure in place and future groundwater monitoring requirements pursuant to the Legacy CCR Rule.

Registrant	Increase in ARO		Increase in Generation Property (a)		Increase in Regulatory Assets (b)		Charged to Operating Expenses (c)
	(in millions)
APCo	$	312	$	75	$	237	$	—
I&M	85		—		72		13
OPCo	53		—		—		53
PSO	34		34		—		—
SWEPCo	24		24		—		—
Non-Registrants	166		44		46		76
Total	$	674	$	177	$	355	$	142

(a)ARO is related to a legacy CCR surface impoundment or CCR management unit at an operating generation facility.

(b)ARO is related to a legacy CCR surface impoundment or CCR management unit at a retired generation facility and recognition of a regulatory asset in accordance with the accounting guidance for “Regulated Operations” is supported.

(c)ARO is related to a legacy CCR surface impoundment or CCR management unit and recognition of a regulatory asset in accordance with the accounting guidance for “Regulated Operations” is not yet supported.

As further groundwater monitoring and other analysis is performed, management expects to refine the assumptions and underlying cost estimates used in recording the ARO. These refinements may include, but are not limited to, changes in the expected method of closure, changes in estimated quantities of CCR at each site, the identification of new CCR management units, among other items. These future changes could have a material impact on the ARO and materially reduce future net income and cash flows and further impact financial condition.

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In January 2026, APCo received a final order from the Virginia SCC approving the recovery of $80 million of Legacy CCR Rule regulatory assets through 2041 and concurrent recovery of ongoing depreciation and accretion expenses. AEP will continue to seek cost recovery through regulated rates in other jurisdictions, including proposal of new regulatory mechanisms for cost recovery where existing mechanisms are not applicable. The rule could have an additional, material adverse impact on net income, cash flows and financial condition if AEP cannot ultimately recover these additional costs of compliance. Several parties, including AEP and one of its trade associations, have filed petitions for review of the Legacy CCR Rule with the U.S. Court of Appeals for the District of Columbia Circuit. The litigation is being held in abeyance. In December 2025, the Federal EPA informed the court that it anticipates publishing a proposed rule in January 2026 that should be finalized by October 2026, which will revise certain provisions of the Legacy CCR Rule for both legacy CCR surface impoundments and CCR management units. The Federal EPA further noted that it has been working to obtain technical information to inform its reconsideration and develop a record to support a proposal. Reconsideration of the rule will require a new round of notice-and-comment rulemaking.

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. Management cannot predict the outcome of the litigation or any further actions by the Federal EPA related to the rule.

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF.  Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized.  In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and non-hazardous materials.  The Registrants currently incur costs to dispose of these substances safely.

Superfund addresses clean-up of hazardous substances that are released to the environment.  The Federal EPA administers the clean-up programs.  Several states enacted similar laws.  As of December 31, 2025, AGR, APCo, OPCo and SWEPCo are named as a Potentially Responsible Party (PRP) for one, one, two and one sites, respectively, by the Federal EPA for which alleged liability is unresolved.  There are 11 additional sites for which APCo, I&M, KPCo, OPCo and SWEPCo received information requests which could lead to PRP designation. In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories.  Liability has been resolved for a number of sites with no significant effect on net income.

Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability.  Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often non-hazardous.  Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises.  As of December 31, 2025, management’s estimates do not anticipate material clean-up costs for identified Superfund sites.

NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M)

I&M owns and operates the two-unit 2,296 MW Cook Plant under licenses granted by the NRC.  I&M has a significant future financial obligation to dispose of SNF and to safely decommission and decontaminate the plant.  The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. 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.  The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements.  By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S.  Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

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Decommissioning and Low-Level Waste Accumulation Disposal

The costs to decommission a nuclear plant are affected by NRC regulations and the SNF disposal program.  Decommissioning costs are accrued over the service life of Cook Plant.  The most recent decommissioning cost study was performed 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. I&M recovers estimated decommissioning costs for the Cook Plant in its rates.  Decommissioning contributions received from customers are deposited in external trusts. Based on the funded status of the trusts, contributions were not collected from customers in 2025.

As of December 31, 2025 and 2024, the total decommissioning trust fund balances were $4.5 billion and $4 billion, respectively.  The increase in the trust fund balance was driven by favorable investment performance in 2025. Trust fund earnings increase the fund assets and may decrease the amount remaining to be recovered from customers. Trust fund losses decrease the fund assets and may increase the amount remaining to be recovered from customers.  The decommissioning costs (including unrealized gains and losses, interest and trust funds expenses) increase or decrease the recorded liability.

I&M continues to work with regulators and customers to establish rates designed to collect the estimated costs of decommissioning the Cook Plant.  However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning increases and cannot be recovered.

Spent Nuclear Fuel Disposal

The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal.  A fee of one-mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant was collected from customers and remitted to the DOE through May 14, 2014. In May 2014, pursuant to court order from the U.S Court of Appeals for the District of Columbia Circuit, the DOE adjusted the fee to $0. As of December 31, 2025 and 2024, fees and related interest of $330 million and $316 million, respectively, for fuel consumed prior to April 7, 1983 were recorded as Long-term Debt and funds collected from customers along with related earnings totaling $381 million and $367 million, respectively, to pay the fee, were recorded as part of Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.  I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program.

In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delay in accepting SNF for permanent storage.  Under the settlement agreement, I&M received $11 million, $12 million and $21 million in 2025, 2024 and 2023, respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2025.  The proceeds reduced costs for dry cask storage.  As of December 31, 2025 and 2024, I&M deferred $25 million and $11 million, respectively, in Prepayments and Other Current Assets and $1 million and $15 million, respectively, in Deferred Charges and Other Noncurrent Assets on the balance sheets for dry cask storage and related operation and maintenance costs for recovery under this agreement. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for additional information.

Nuclear Insurance

I&M carries nuclear property insurance of $2.7 billion to cover a nuclear incident at Cook Plant including coverage for decontamination and stabilization, as well as premature decommissioning caused by a nuclear incident.  Insurance coverage for a nonnuclear property incident at Cook Plant is $1 billion.  Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage.  I&M utilizes industry mutual insurers for the placement of this insurance coverage.  Coverage from these industry mutual insurance programs require a contingent financial obligation of up to $49 million for I&M’s current term, which is assessable if the insurer’s financial resources would be inadequate to pay for industry losses.

The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public nuclear liability arising from a nuclear incident of $16.3 billion and applies to any incident at a licensed reactor in the U.S.  Commercially available insurance, which must be carried for each licensed reactor, provides $500 million of primary coverage.  In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $332 million per nuclear incident on Cook Plant’s reactors payable in annual installments of $49 million.  The number of incidents for which payments could be required is not limited.

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In the event of an incident of a catastrophic nature, I&M is covered for public nuclear liability for the first $500 million through commercially available insurance.  The next level of liability coverage of up to $15.8 billion would be covered by deferred premium assessments made under the Price-Anderson Act. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds, I&M would seek recovery of those amounts from customers through a rate increase. If recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition.

OPERATIONAL CONTINGENCIES

Insurance and Potential Losses

The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles.  The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cybersecurity incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions.  Covered property generally includes power plants, substations, facilities and inventories.  Excluded property generally includes transmission and distribution lines, poles and towers.  The insurance programs also generally provide coverage against loss arising from certain claims made by third-parties and are in excess of retentions absorbed by the Registrants.  Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers. See “Nuclear Contingencies” section above for additional information.

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, but not limited to, liabilities relating to a cybersecurity incident, extreme weather or wildfire related liabilities or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant.  Future losses or liabilities, if they occur, which are not completely insured, unless recovered through the ratemaking process, could reduce future net income and cash flows and impact financial condition.

Claims for Indemnification Made by Owners of the Gavin Power Station (Applies to AEP)

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 July 2021, closure work was completed by AEP. In November 2022, the Federal EPA issued a final decision denying Gavin Power LLC’s requested extension to allow another pond at the Gavin Power Station, the CCR surface impoundment, to continue to receive CCR and non-CCR waste streams after April 11, 2021 until May 4, 2023 (the Gavin Denial). As part of the Gavin Denial, the Federal EPA made several assertions related to the CCR Rule, 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, including any future enforcement or litigation resulting from any determinations of noncompliance by the Federal EPA with various aspects of the CCR Rule consistent with the Gavin Denial. The owners of the Gavin Power Station have also sought indemnification for landowner claims for property damage allegedly caused by modifications to the FAR. 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. In January 2024, Gavin Power LLC filed a complaint with the United States District Court for the Southern District of Ohio, alleging various violations of the Administrative Procedure Act and asserting that the Federal EPA, through its prior inaction, has waived and is estopped from raising certain objections raised in the Gavin Denial. The complaint does not assert any claims against AEP. In August 2025, the District Court dismissed the complaint at the Federal EPA’s request. Based on the information currently available, management does not believe a loss is probable and cannot determine a range of potential losses, if any, that is reasonably possible of occurring.

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7. ACQUISITIONS, DISPOSITIONS AND IMPAIRMENTS

The disclosures in this note apply to AEP unless indicated otherwise.

ACQUISITIONS

Wagon Wheel Wind Facility (Applies to AEP and SWEPCo)

In December 2025, SWEPCo acquired 100% of the equity interests in Wagon Wheel Project, LLC, the owner of the newly constructed Wagon Wheel wind facility located across multiple counties in Oklahoma. This facility, placed in service in December 2025, serves both retail and wholesale customers in Arkansas and Louisiana. SWEPCo’s Louisiana jurisdictional share of the Wagon Wheel revenue requirement, net of PTC benefit, is recoverable through an authorized rider until the amounts are reflected in base rates. Recovery of the Arkansas portion of the Wagon Wheel revenue requirement began in February 2026 through base rates. Regulatory commission approval of the inclusion of the output from Wagon Wheel in retail rates resulted in various capital cost, performance and other guarantees for retail customers which could subject SWEPCo to future regulatory liabilities to retail customers.

The acquisition of Wagon Wheel resulted in the recognition of operating leases for easement and access rights to the land on which the facilities are located, as well as the associated ARO. In accordance with the guidance for “Business Combinations,” management determined that the acquisition represents an asset acquisition. The table below summarizes the impact at acquisition on SWEPCo’s balance sheets:

Plant Name	State	Fuel Type	Net Maximum Capacity (MWs)	Property, Plant and Equipment, Net		Operating Lease Assets		Asset Retirement Obligations
				(in millions)
Wagon Wheel	OK	Wind	598	$	1,272	$	66	$	20

Top Hat Wind Facility (Applies to AEP and APCo)

In November 2025, APCo acquired 100% of the equity interests in Top Hat Wind Energy, LLC, the owner of the newly constructed Top Hat wind facility located in Logan County, Illinois. This facility, placed in service in November 2025, serves both retail and wholesale customers in Virginia and West Virginia. Virginia and West Virginia jurisdictional shares of the Top Hat revenue requirement, net of PTC benefit, is recoverable through existing riders until the amounts are reflected in base rates. The acquisition of Top Hat resulted in the recognition of operating leases for easement and access rights to the land on which the facilities are located, as well as the associated ARO. In accordance with the guidance for “Business Combinations,” management determined the acquisition represents an asset acquisition. The table below summarizes the impact at acquisition on APCo’s balance sheets:

Plant Name	State	Fuel Type	Net Maximum Capacity (MWs)	Property, Plant and Equipment, Net		Operating Lease Assets		Asset Retirement Obligations
				(in millions)
Top Hat	IL	Wind	204	$	562	$	31	$	4

Green Country Power Plant, Pixley Solar Energy Facility, Flat Ridge IV Wind Energy Facility and Flat Ridge V Wind Energy Facility (Applies to AEP and PSO)

In May 2025, PSO acquired 100% of the equity interests in Pixley Solar Energy, LLC, the owner of the newly constructed Pixley solar energy facility in Barber County, Kansas. The Pixley facility, placed in service in May 2025, serves both retail and wholesale customers in Oklahoma. PSO’s revenue requirement is recoverable through an authorized rider until it is incorporated into base rates. Regulatory approval of Pixley’s output in retail rates included capital cost, performance and other guarantees, which may subject PSO to future regulatory liabilities. In June 2025, PSO also acquired 100% of the equity interests in Flat Ridge IV Wind, LLC, the owner of the newly constructed Flat Ridge IV Wind Energy Facility located in Kingman and Harper Counties, Kansas. This facility, also placed in service in June 2025, serves both retail and wholesale customers under similar recovery and regulatory provisions as the Pixley facility. The acquisitions of Pixley and Flat Ridge IV also resulted in the recognition of operating leases for easement and access rights to the land on which the facilities are located, as well as the associated ARO. In accordance with the guidance for “Business Combinations,” management determined the acquisitions of Pixley and Flat Ridge IV represent asset acquisitions.

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Additionally, in June 2025, PSO completed the acquisition of 100% of the equity interests in Green Country Energy, LLC, the owner of a combined-cycle natural gas facility located in Jenks, Oklahoma, following approvals from both the FERC and the OCC. The transaction included the acquisition of a previously executed capacity sales agreement between Green Country Energy, LLC, as seller, and SWEPCo, as purchaser. Since July 2025, PSO sells a portion of Green Country’s capacity to SWEPCo, and this arrangement will continue through May 2027, when the agreement ends. The acquisition also resulted in the extinguishment of a previously executed capacity sales agreement between Green Country Energy, LLC, as seller, and PSO, as purchaser. In accordance with the guidance for “Business Combinations,” management determined the acquisition of Green Country represents an asset acquisition. Asset acquisitions are accounted for using a cost accumulation model, with the cost of the acquisition allocated to the acquired assets and assumed liabilities based on their relative fair value. Upon closing of the transaction, PSO recognized Property, Plant and Equipment of $819 million, an intangible liability of $41 million for the fair value of the acquired SWEPCo capacity sales agreement and a regulatory liability of $50 million, reflective of the recognition and subsequent deferral of the gain from PSO’s extinguished capacity sales agreement. The liabilities recognized for the capacity sales agreements will reduce PSO’s revenue requirement to recover its overall investment in Green Country, which is recoverable through a rider authorized by the OCC until it is included in base rates for the depreciable life of the facility. Management elected the income approach for its nonrecurring valuation of both the intangible liability and regulatory liability. Specifically, management applied a discounted cash flow model based on a forward market price assumption.

Furthermore, in August 2025, PSO completed the acquisition of 100% of the equity interests in Flat Ridge V Wind Energy, LLC, the owner of the Flat Ridge V Wind Energy Facility located in Kingman and Harper Counties, Kansas. This facility, placed in service in August 2025, serves both retail and wholesale customers under similar recovery and regulatory provisions as the Flat Ridge IV and Pixley facilities. The acquisition of Flat Ridge V also resulted in the recognition of operating leases for easement and access rights to the land on which the facilities are located, as well as the associated ARO. In accordance with the guidance for “Business Combinations,” management determined the acquisition of Flat Ridge V represents an asset acquisition.

In 2025, PSO expanded its generation portfolio by acquiring four electric generation facilities for an aggregate purchase price of $1.7 billion. The table below summarizes the impact at acquisition on PSO’s balance sheets:

Plant Name	State	Fuel Type	Net Maximum Capacity (MWs)	Property, Plant and Equipment, Net		Operating Lease Assets		Asset Retirement Obligations		Other Liabilities
				(in millions)
Green Country	OK	Natural Gas	904	$	819	$	—	$	—	$	91	(a)
Pixley	KS	Solar	189	380		9		12		—
Flat Ridge IV	KS	Wind	135	305		7		3		—
Flat Ridge V	KS	Wind	153	338		9		4		—
Total			1,381	$	1,842	$	25	$	19	$	91

(a)$50 million included in Regulatory Liabilities and Deferred Investment Tax Credits, $21 million included in Other Current Liabilities and $20 million included in Deferred Credits and Other Noncurrent Liabilities on PSO’s balance sheets.

Diversion Wind Farm (Applies to AEP and SWEPCo)

In December 2024, SWEPCo acquired 100% of the equity interests in Diversion Wind Energy, LLC, the owner of Diversion wind farm. The Diversion wind farm is a newly constructed 201 MW wind facility located in Baylor County, Texas and was placed in service in December 2024. Output from Diversion serves both retail and wholesale customers in Arkansas and Louisiana. SWEPCo’s Louisiana jurisdictional share of the Diversion revenue requirement, net of PTC benefit, is recoverable through an authorized rider until the amounts are reflected in base rates. Recovery of the Arkansas portion of the Diversion revenue requirement is expected to begin in 2026 through base rates. Regulatory commission approval of the inclusion of the output from Diversion in retail rates resulted in various capital cost, performance and other guarantees for retail customers which could subject SWEPCo to future regulatory liabilities to retail customers.

In accordance with the guidance for “Business Combinations,” management determined that the acquisition of the Diversion project represents an asset acquisition. As of December 31, 2024, SWEPCo had approximately $423 million of gross Property, Plant and Equipment, inclusive of capital expenditures after the acquisition, on the balance sheets related to the Diversion project. The acquisition also resulted in the recognition of $20 million of operating leases that provide for easement and access rights to the land that Diversion was built upon and $6 million of ARO.

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Rock Falls Wind Facility (Applies to AEP and PSO)

In November 2022, PSO entered into an agreement to acquire the Rock Falls Wind Facility. In February 2023, the FERC approved PSO’s acquisition of the Rock Falls Wind Facility under Section 203 of the Federal Power Act. In March 2023, PSO acquired an ownership interest in the entity that owned Rock Falls during its development and construction for $146 million. In accordance with the guidance for “Business Combinations,” AEP management determined that the acquisition of the Rock Falls Wind Facility represents an asset acquisition. The lease obligations related to Rock Falls were not material at the time of acquisition.

DISPOSITIONS

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

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.

Disposition of AEP OnSite Partners (Applies to AEP)

In April 2023, AEP initiated a sales process for its ownership in AEP OnSite Partners. AEP OnSite Partners targeted opportunities in distributed solar, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other energy solutions. In May 2024, AEP signed an agreement to sell AEP OnSite Partners to a nonaffiliated third-party. In September 2024, AEP completed the sale and received cash proceeds of approximately $318 million, net of taxes and transaction costs. The proceeds were used to pay down short-term debt.

Disposition of NMRD (Applies to AEP)

In December 2023, AEP and the joint owner signed an agreement to sell NMRD to a nonaffiliated third party and the sale was completed in February 2024. AEP received cash proceeds of approximately $107 million, net of taxes and transaction costs. The transaction did not have a material impact on net income or financial condition.

Disposition of the Competitive Contracted Renewables Portfolio (Applies to AEP)

In February 2022, AEP management announced the initiation of a process to sell all or a portion of AEP Renewables’ competitive contracted renewables portfolio (the portfolio) within the Generation & Marketing segment. In late January 2023, AEP received final bids from interested parties. In February 2023, AEP’s Board of Directors approved management’s plan to sell the portfolio and AEP signed an agreement with a nonaffiliated party.

In August 2023, AEP completed the sale of the entire portfolio to the nonaffiliated party and received cash proceeds of approximately $1.2 billion, net of taxes and transaction costs. AEP recorded a pretax loss of $93 million ($73 million after-tax) for the year ended December 31, 2023 related to the sale.

IMPAIRMENTS

Internal-Use Software Impairment (Applies to all Registrants Except AEPTCo)

In the fourth quarter of 2025, as a result of evaluation of AEP’s strategy and expectations for ongoing advancements in available technologies, including the expanded use of, and potential capabilities for, AI-centric software and other agile software functionality, AEP Management determined that previously selected technology for an in-process software development project to replace a legacy enterprise system was no longer probable of being completed and placed in service. As a result, the guidance for “Internal Use Software” requires the related capitalized costs to be reported at the lower of their carrying amount or fair value, if any, less costs to sell. AEP Management concluded the previously incurred application development costs have a fair value of zero and recognized a charge of $66 million recorded in Asset Impairments and Other Related Charges on the statements of income in the fourth quarter of 2025.

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2012 Texas Base Rate Case (Applies to AEP and SWEPCo)

In December 2023, SWEPCo recorded a pretax, non-cash disallowance of $86 million in Asset Impairments and Other Related Charges on the statements of income due to regulatory disallowance of recovery of AFUDC on Turk Plant in the 2012 Texas Base Rate case.

NMRD (Applies to AEP)

In December 2023, as a result of sale negotiations AEP determined a decline in the fair value of AEP’s investment in NMRD was other than temporary. In accordance with the accounting guidance for “Investment - Equity Method and Joint Ventures”, in the fourth quarter of 2023 AEP recorded a pretax other than temporary impairment charge of $19 million which is presented in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s statement of income. AEP’s determination of fair value utilized the accounting guidance for Fair Value Measurement market approach to valuation and was based on negotiations to sell the investment to a nonaffiliated third-party. The carrying value of the investment in NMRD was not material to AEP as of December 31, 2023.

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8.  BENEFIT PLANS

The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise.

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

AEPSC sponsors a qualified pension plan and two unfunded non-qualified pension plans.  Substantially all AEP subsidiary employees are covered by the qualified plan or both the qualified and a non-qualified pension plan.  AEPSC also sponsors OPEB plans to provide health and life insurance benefits for retired employees.

Due to the Registrant Subsidiaries’ participation in AEP’s benefit plans, the assumptions used by the actuary, with the exception of the rate of compensation increase, and the accounting for the plans by each subsidiary are the same.  This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant.

The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets.  Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance.  The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery.  The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.

Actuarial Assumptions for Benefit Obligations

The weighted-average assumptions used in the measurement of the Registrants’ benefit obligations are shown in the following tables:

	Pension Plans				OPEB
	December 31,
Assumption	2025		2024		2025		2024
Discount Rate	5.50	%	5.65	%	5.50	%	5.60	%
Interest Crediting Rate	4.40	%	4.55	%	NA		NA

NA    Not applicable.

Assumption – Rate of Compensation Increase (a) - Pension Plans
	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
December 31, 2025	4.55	%	4.50	%	4.50	%	4.45	%	4.80	%	4.65	%	4.50	%
December 31, 2024	5.55	%	5.70	%	5.55	%	5.50	%	6.00	%	5.70	%	5.55	%

(a)Rates are for base pay only.  In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.

A duration-based method is used to determine the discount rate for the plans.  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 is the same for each Registrant.

For 2025, the rate of compensation increase assumed varies with the age of the employee, ranging from 3% per year to 11.5% per year, with the average increase shown in the table above.  The compensation increase rates reflect variations in each Registrants’ population participating in the pension plan.

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Actuarial Assumptions for Net Periodic Benefit Costs

The weighted-average assumptions used in the measurement of each Registrants’ benefit costs are shown in the following tables:

	Pension Plans						OPEB
	Year Ended December 31,
Assumption	2025		2024		2023		2025		2024		2023
Discount Rate	5.65	%	5.20	%	5.50	%	5.60	%	5.15	%	5.50	%
Interest Crediting Rate	4.55	%	4.05	%	4.25	%	NA		NA		NA
Expected Return on Plan Assets	7.00	%	7.30	%	7.50	%	6.50	%	6.75	%	7.25	%

NA    Not applicable.

Assumption – Rate of Compensation Increase (a) - Pension Plans
	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
December 31, 2025	5.75	%	5.90	%	5.80	%	5.60	%	6.10	%	5.90	%	5.70	%
December 31, 2024	5.10	%	5.25	%	5.10	%	5.10	%	5.50	%	5.20	%	5.10	%
December 31, 2023	5.05	%	5.20	%	4.95	%	5.05	%	5.45	%	5.20	%	5.00	%

(a)Rates are for base pay only.  In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.

The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation, third-party forecasts and current prospects for economic growth.  The expected return on plan assets is the same for each Registrant.

The health care trend rate assumptions used for OPEB plans measurement purposes are shown below:

Health Care Trend Rates	December 31, 2025		December 31, 2024
Initial	6.00	%	6.50	%
Ultimate	4.50	%	4.50	%
Year Ultimate Reached	2031		2029

Significant Concentrations of Risk within Plan Assets

In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets.  The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits.  The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment.  Management monitors the plans to control security diversification and compliance with the investment policy.  As of December 31, 2025, the assets were invested in compliance with all investment limits.  See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details.

Benefit Plan Obligations, Plan Assets, Funded Status and Amounts Recognized on the Balance Sheets

For the year ended December 31, 2025, the pension plans had an actuarial loss primarily due to a decrease in discount rates, and to a lesser extent the effect of demographic experience (updated census data on January 1, 2025). These losses were partially offset by decreasing the cash balance account interest crediting rate. For the year ended December 31, 2025, the OPEB plans had an actuarial gain primarily due to updated per capita cost assumptions (notably including guidance on Employer Group Waiver Plan subsidies as a result of Inflation Reduction Act). These gains were partially offset by updated discount and trend rates. For the year ended December 31, 2024, the pension plans had an actuarial gain primarily due to an increase in discount rates, and to a lesser extent the effect of demographic experience (updated census data on January 1, 2024). These gains were partially offset by increasing the cash balance account interest crediting rate, increasing the rate used to convert lump sums to annuities and updating the compensation increase rate to reflect the results of an experienced study conducted in 2024. For the year ended December 31, 2024, the OPEB plans had an actuarial gain primarily due to updated per capita cost assumptions and updated discount rates. These gains were partially offset by the addition of a life insurance administrative load of 5%, the effect of special termination benefits and earlier retirements due to the voluntary severance program that occurred in the second quarter of 2024 and assumption changes as a result of an experience study conducted in 2024.

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The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets, funded status and the presentation on the balance sheets. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively.

Pension Plans

2025	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Change in Benefit Obligation	(in millions)
Benefit Obligation as of January 1,	$	3,872	$	323	$	453	$	450	$	351	$	190	$	228
Service Cost	96		9		9		13		9		6		8
Interest Cost	211		17		25		25		19		10		13
Actuarial Loss	46		7		11		5		6		2		4
Benefit Payments	(382)		(29)		(43)		(45)		(39)		(18)		(20)
Benefit Obligation as of December 31,	$	3,843	$	327	$	455	$	448	$	346	$	190	$	233
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1,	$	3,666	$	288	$	488	$	507	$	381	$	200	$	189
Actual Gain on Plan Assets	372		32		53		50		39		21		22
Company Contributions (a)	103		12		—		2		—		2		9
Benefit Payments	(382)		(29)		(43)		(45)		(39)		(18)		(20)
Fair Value of Plan Assets as of December 31,	$	3,759	$	303	$	498	$	514	$	381	$	205	$	200
Funded (Underfunded) Status as of December 31,	$	(84)	$	(24)	$	43	$	66	$	35	$	15	$	(33)

2024	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Change in Benefit Obligation	(in millions)
Benefit Obligation as of January 1,	$	4,162	$	343	$	504	$	477	$	378	$	202	$	261
Service Cost	101		9		9		13		9		6		8
Interest Cost	207		17		25		24		19		10		12
Actuarial (Gain) Loss	(45)		6		(13)		(8)		(8)		—		(11)
Settlements	(329)		(35)		(42)		(33)		(23)		(18)		(33)
Benefit Payments	(224)		(17)		(30)		(23)		(24)		(10)		(9)
Benefit Obligation as of December 31,	$	3,872	$	323	$	453	$	450	$	351	$	190	$	228
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1,	$	4,118	$	333	$	550	$	551	$	419	$	223	$	227
Actual Gain on Plan Assets	87		7		10		12		9		5		4
Company Contributions (a)	14		—		—		—		—		—		—
Settlements	(329)		(35)		(42)		(33)		(23)		(18)		(33)
Benefit Payments	(224)		(17)		(30)		(23)		(24)		(10)		(9)
Fair Value of Plan Assets as of December 31,	$	3,666	$	288	$	488	$	507	$	381	$	200	$	189
Funded (Underfunded) Status as of December 31,	$	(206)	$	(35)	$	35	$	57	$	30	$	10	$	(39)

(a)Contributions to the qualified pension plan were $95 million for the year ended December 31, 2025. No contributions were made to the qualified pension plan for the year ended December 31, 2024. Contributions to the non-qualified pension plans were $8 million and $14 million for the years ended December 31, 2025 and 2024, respectively.

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OPEB

2025	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Change in Benefit Obligation	(in millions)
Benefit Obligation as of January 1,	$	647	$	50	$	102	$	73	$	63	$	33	$	41
Service Cost	4		—		1		—		—		—		—
Interest Cost	34		3		5		4		3		2		2
Actuarial (Gain) Loss	(50)		(1)		(8)		(5)		(4)		(2)		(2)
Benefit Payments	(105)		(9)		(17)		(13)		(11)		(6)		(7)
Participant Contributions	46		3		7		6		5		3		3
Benefit Obligation as of December 31,	$	576	$	46	$	90	$	65	$	56	$	30	$	37
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1,	$	1,776	$	147	$	256	$	212	$	185	$	95	$	121
Actual Gain on Plan Assets	262		27		39		32		24		17		21
Company Contributions	1		—		1		—		—		—		—
Participant Contributions	46		3		7		6		5		3		3
Benefit Payments	(105)		(9)		(17)		(13)		(11)		(6)		(7)
Fair Value of Plan Assets as of December 31,	$	1,980	$	168	$	286	$	237	$	203	$	109	$	138
Funded Status as of December 31,	$	1,404	$	122	$	196	$	172	$	147	$	79	$	101

2024	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Change in Benefit Obligation	(in millions)
Benefit Obligation as of January 1,	$	850	$	66	$	135	$	99	$	86	$	44	$	54
Service Cost	4		—		—		1		—		—		—
Interest Cost	42		3		7		5		4		2		3
Actuarial (Gain) Loss	(192)		(15)		(31)		(25)		(21)		(10)		(12)
Special/Contractual Termination Benefits	4		—		1		—		—		—		—
Benefit Payments	(106)		(8)		(17)		(13)		(11)		(6)		(7)
Participant Contributions	45		4		7		6		5		3		3
Benefit Obligation as of December 31,	$	647	$	50	$	102	$	73	$	63	$	33	$	41
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1,	$	1,673	$	137	$	243	$	205	$	177	$	90	$	111
Actual Gain on Plan Assets	160		14		22		14		14		8		14
Company Contributions	4		—		1		—		—		—		—
Participant Contributions	45		4		7		6		5		3		3
Benefit Payments	(106)		(8)		(17)		(13)		(11)		(6)		(7)
Fair Value of Plan Assets as of December 31,	$	1,776	$	147	$	256	$	212	$	185	$	95	$	121
Funded Status as of December 31,	$	1,129	$	97	$	154	$	139	$	122	$	62	$	80

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Amounts Included on the Balance Sheets Related to Funded Status

Pension Plans

December 31, 2025	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Other Noncurrent Assets - Employee Benefits and Pension Assets	$	—	$	—	$	43	$	67	$	35	$	16	$	—
Other Current Liabilities – Accrued Short-term Benefit Liability	(6)		—		—		—		—		—		—
Other Noncurrent Liabilities – Accrued Long-term Benefit Liability	(78)		(24)		—		(1)		—		(1)		(33)
Funded (Underfunded) Status	$	(84)	$	(24)	$	43	$	66	$	35	$	15	$	(33)

December 31, 2024	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Other Noncurrent Assets - Employee Benefits and Pension Assets	$	—	$	—	$	35	$	58	$	30	$	11	$	—
Other Current Liabilities – Accrued Short-term Benefit Liability	(5)		(1)		—		—		—		—		—
Other Noncurrent Liabilities – Accrued Long-term Benefit Liability	(201)		(34)		—		(1)		—		(1)		(39)
Funded (Underfunded) Status	$	(206)	$	(35)	$	35	$	57	$	30	$	10	$	(39)

OPEB

December 31, 2025	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Other Noncurrent Assets - Employee Benefits and Pension Assets	$	1,404	$	122	$	208	$	172	$	147	$	79	$	101
Other Current Liabilities – Accrued Short-term Benefit Liability	(2)		—		(1)		—		—		—		—
Other Noncurrent Liabilities – Accrued Long-term Benefit Liability	2		—		(11)		—		—		—		—
Funded Status	$	1,404	$	122	$	196	$	172	$	147	$	79	$	101

December 31, 2024	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Other Noncurrent Assets - Employee Benefits and Pension Assets	$	1,130	$	97	$	168	$	139	$	122	$	62	$	80
Other Current Liabilities – Accrued Short-term Benefit Liability	(2)		—		(1)		—		—		—		—
Other Noncurrent Liabilities – Accrued Long-term Benefit Liability	1		—		(13)		—		—		—		—
Funded Status	$	1,129	$	97	$	154	$	139	$	122	$	62	$	80

246

Amounts Included in Regulatory Assets, Deferred Income Taxes and AOCI

The following tables show the components of the plans included in Regulatory Assets, Deferred Income Taxes and AOCI and the items attributable to the change in these components:

Pension Plans

December 31, 2025	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Components	(in millions)
Net Actuarial Loss	$	1,094	$	185	$	105	$	—	$	135	$	49	$	79
Recorded as
Regulatory Assets	$	984	$	173	$	104	$	9	$	135	$	49	$	79
Deferred Income Taxes	23		2		—		(1)		—		—		—
Net of Tax AOCI	87		10		1		(8)		—		—		—

December 31, 2025	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Components	(in millions)
Actuarial Gain During the Year	$	(44)	$	(3)	$	(5)	$	(6)	$	(5)	$	(4)	$	(3)
Amortization of Actuarial Loss	(16)		(1)		(2)		(2)		(1)		(1)		(1)
Change for the Year Ended December 31,	$	(60)	$	(4)	$	(7)	$	(8)	$	(6)	$	(5)	$	(4)

December 31, 2024	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Components	(in millions)
Net Actuarial Loss	$	1,154	$	189	$	112	$	8	$	141	$	54	$	83
Recorded as
Regulatory Assets	$	1,020	$	177	$	110	$	18	$	141	$	54	$	83
Deferred Income Taxes	28		2		—		(2)		—		—		—
Net of Tax AOCI	106		10		2		(8)		—		—		—

December 31, 2024	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Components	(in millions)
Actuarial Loss During the Year	$	188	$	24	$	19	$	23	$	16	$	12	$	2
Amortization of Actuarial Loss	(5)		—		—		(1)		—		—		—
Amounts Recognized Due to Settlement	(93)		(10)		(12)		(9)		(7)		(5)		(9)
Change for the Year Ended December 31,	$	90	$	14	$	7	$	13	$	9	$	7	$	(7)

247

OPEB

December 31, 2025	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Components	(in millions)
Net Actuarial Gain	$	(241)	$	(18)	$	(40)	$	(21)	$	(23)	$	(7)	$	(15)
Prior Service Credit	(12)		(1)		(2)		(3)		(1)		(1)		(1)
Recorded as
Regulatory Assets	$	(195)	$	(18)	$	(15)	$	(24)	$	(24)	$	(8)	$	(9)
Deferred Income Taxes	(12)		—		(6)		—		—		—		(1)
Net of Tax AOCI	(46)		(1)		(21)		—		—		—		(6)

December 31, 2025	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Components	(in millions)
Actuarial Gain During the Year	$	(199)	$	(20)	$	(30)	$	(23)	$	(18)	$	(12)	$	(15)
Amortization of Prior Service Credit	3		—		—		(1)		1		—		—
Change for the Year Ended December 31,	$	(196)	$	(20)	$	(30)	$	(24)	$	(17)	$	(12)	$	(15)

December 31, 2024	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Components	(in millions)
Net Actuarial (Gain) Loss	$	(42)	$	2	$	(10)	$	2	$	(5)	$	5	$	—
Prior Service Credit	(15)		(1)		(2)		(2)		(2)		(1)		(1)
Recorded as
Regulatory Assets	$	(56)	$	1	$	(2)	$	(3)	$	(7)	$	4	$	—
Deferred Income Taxes	—		—		(2)		1		—		—		—
Net of Tax AOCI	(1)		—		(8)		2		—		—		(1)

December 31, 2024	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Components	(in millions)
Actuarial Gain During the Year	$	(240)	$	(20)	$	(37)	$	(26)	$	(23)	$	(13)	$	(18)
Amortization of Actuarial Loss	(3)		—		—		(1)		—		—		—
Amortization of Prior Service Credit	13		1		2		2		1		1		1
Change for the Year Ended December 31,	$	(230)	$	(19)	$	(35)	$	(25)	$	(22)	$	(12)	$	(17)

Determination of Pension Expense

The determination of pension expense or income is based 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.

248

Pension and OPEB Assets

The fair value tables within Pension and OPEB Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to the Registrant Subsidiaries using the percentages in the table below:

	Pension Plan				OPEB
	December 31,
Company	2025		2024		2025		2024
AEP Texas	8.1	%	7.9	%	8.5	%	8.3	%
APCo	13.2	%	13.3	%	14.4	%	14.4	%
I&M	13.7	%	13.8	%	12.0	%	11.9	%
OPCo	10.1	%	10.4	%	10.2	%	10.4	%
PSO	5.4	%	5.5	%	5.5	%	5.4	%
SWEPCo	5.3	%	5.2	%	7.0	%	6.8	%

The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2025:

Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End Allocation
	(in millions)
Equities (a):
Domestic	$	109	$	—	$	—	$	—	$	109	2.9	%
International	68		—		—		—		68		1.8	%
Common Collective Trusts (b)	228		—		—		901		1,129		30.0	%
Subtotal – Equities	405		—		—		901		1,306		34.7	%
Fixed Income (a):
United States Government and Agency Securities	—		1,060		—		—		1,060		28.2	%
Corporate Debt	—		627		—		—		627		16.7	%
Foreign Debt	—		110		—		—		110		2.9	%
State and Local Government	—		21		—		—		21		0.6	%
Other – Asset Backed	—		5		—		—		5		0.1	%
Subtotal – Fixed Income	—		1,823		—		—		1,823		48.5	%
Infrastructure (b)	—		—		—		114		114		3.0	%
Real Estate (b)	—		—		—		221		221		5.9	%
Alternative Investments (b)	—		—		—		218		218		5.8	%
Cash and Cash Equivalents (b)	—		18		—		29		47		1.3	%
Other – Pending Transactions and Accrued Income (c)	—		—		—		30		30		0.8	%
Total	$	405	$	1,841	$	—	$	1,513	$	3,759	100.0	%

(a)Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information.

(b)Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.

(c)Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

249

The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2025:

Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End Allocation
	(in millions)
Equities:
Domestic	$	643	$	—	$	—	$	—	$	643	32.5	%
International	241		—		—		—		241		12.2	%
Common Collective Trusts (a)	85		—		—		287		372		18.8	%
Subtotal – Equities	969		—		—		287		1,256		63.5	%
Fixed Income:
United States Government and Agency Securities	—		265		—		—		265		13.4	%
Corporate Debt	—		141		—		—		141		7.1	%
Foreign Debt	—		26		—		—		26		1.3	%
State and Local Government	84		4		—		—		88		4.4	%
Other – Asset Backed	—		2		—		—		2		0.1	%
Subtotal – Fixed Income	84		438		—		—		522		26.3	%
Trust Owned Life Insurance:
International Equities	—		30		—		—		30		1.5	%
United States Bonds	—		110		—		—		110		5.6	%
Subtotal – Trust Owned Life Insurance	—		140		—		—		140		7.1	%
Cash and Cash Equivalents (a)	28		—		—		—		28		1.4	%
Other – Pending Transactions and Accrued Income (b)	—		—		—		34		34		1.7	%
Total	$	1,081	$	578	$	—	$	321	$	1,980	100.0	%

(a)Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.

(b)Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

250

The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2024:

Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End Allocation
	(in millions)
Equities (a):
Domestic	$	327	$	—	$	—	$	—	$	327	8.9	%
International	290		—		—		—		290		7.9	%
Common Collective Trusts (b)	176		—		—		473		649		17.7	%
Subtotal – Equities	793		—		—		473		1,266		34.5	%
Fixed Income (a):
United States Government and Agency Securities	(2)		866		—		—		864		23.6	%
Corporate Debt	—		719		—		—		719		19.6	%
Foreign Debt	—		136		—		—		136		3.7	%
State and Local Government	—		26		—		—		26		0.7	%
Other – Asset Backed	—		1		—		—		1		—	%
Subtotal – Fixed Income	(2)		1,748		—		—		1,746		47.6	%
Infrastructure (b)	—		—		—		113		113		3.1	%
Real Estate (b)	—		—		—		228		228		6.2	%
Alternative Investments (b)	—		—		—		224		224		6.1	%
Cash and Cash Equivalents (b)	—		41		—		27		68		1.9	%
Other – Pending Transactions and Accrued Income (c)	—		—		—		21		21		0.6	%
Total	$	791	$	1,789	$	—	$	1,086	$	3,666	100.0	%

(a)Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information.

(b)Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.

(c)Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

251

The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2024:

Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End Allocation
	(in millions)
Equities:
Domestic	$	617	$	—	$	—	$	—	$	617	34.7	%
International	267		—		—		—		267		15.0	%
Common Collective Trusts (a)	64		—		—		130		194		10.9	%
Subtotal – Equities	948		—		—		130		1,078		60.6	%
Fixed Income:
Common Collective Trust – Debt (a)	—		—		—		133		133		7.5	%
United States Government and Agency Securities	(1)		158		—		—		157		8.9	%
Corporate Debt	—		132		—		—		132		7.5	%
Foreign Debt	—		27		—		—		27		1.5	%
State and Local Government	58		5		—		—		63		3.5	%
Subtotal – Fixed Income	57		322		—		133		512		28.9	%
Trust Owned Life Insurance:
International Equities	—		23		—		—		23		1.3	%
United States Bonds	—		118		—		—		118		6.7	%
Subtotal – Trust Owned Life Insurance	—		141		—		—		141		8.0	%
Cash and Cash Equivalents (a)	28		—		—		3		31		1.7	%
Other – Pending Transactions and Accrued Income (b)	—		—		—		14		14		0.8	%
Total	$	1,033	$	463	$	—	$	280	$	1,776	100.0	%

(a)Amounts in “Other” column represent investments for which fair value is measured using net asset value per-share.

(b)Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

Accumulated Benefit Obligation

The accumulated benefit obligation for the pension plans is as follows:

Accumulated Benefit Obligation	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Qualified Pension Plan	$	3,559	$	303	$	433	$	418	$	319	$	173	$	212
Nonqualified Pension Plans	45		2		—		1		—		1		1
Total as of December 31, 2025	$	3,604	$	305	$	433	$	419	$	319	$	174	$	213

Accumulated Benefit Obligation	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Qualified Pension Plan	$	3,602	$	301	$	434	$	422	$	326	$	175	$	210
Nonqualified Pension Plans	47		2		—		1		—		1		1
Total as of December 31, 2024	$	3,649	$	303	$	434	$	423	$	326	$	176	$	211

252

Obligations in Excess of Fair Values

The tables below show the underfunded pension plans that had obligations in excess of plan assets.

Projected Benefit Obligation

	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Projected Benefit Obligation	$	3,843	$	327	$	—	$	1	$	1	$	2	$	233
Fair Value of Plan Assets	3,759		303		—		—		—		—		200
Underfunded Projected Benefit Obligation as of December 31, 2025	$	(84)	$	(24)	$	—	$	(1)	$	(1)	$	(2)	$	(33)

	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Projected Benefit Obligation	$	3,872	$	323	$	1	$	1	$	—	$	1	$	228
Fair Value of Plan Assets	3,666		288		—		—		—		—		189
Underfunded Projected Benefit Obligation as of December 31, 2024	$	(206)	$	(35)	$	(1)	$	(1)	$	—	$	(1)	$	(39)

Accumulated Benefit Obligation

	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Accumulated Benefit Obligation	$	45	$	2	$	—	$	1	$	—	$	1	$	213
Fair Value of Plan Assets	—		—		—		—		—		—		200
Underfunded Accumulated Benefit Obligation as of December 31, 2025	$	(45)	$	(2)	$	—	$	(1)	$	—	$	(1)	$	(13)

	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Accumulated Benefit Obligation	$	47	$	303	$	—	$	1	$	—	$	1	$	211
Fair Value of Plan Assets	—		288		—		—		—		—		189
Underfunded Accumulated Benefit Obligation as of December 31, 2024	$	(47)	$	(15)	$	—	$	(1)	$	—	$	(1)	$	(22)

Estimated Future Benefit Payments and Contributions

The estimated pension benefit payments and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded non-qualified benefits.  For the qualified pension plan, additional discretionary contributions may also be made to maintain the funded status of the plan.   For OPEB plans, expected payments include the payment of unfunded benefits.  The following table provides the estimated contributions and payments by Registrant for 2026:

	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Pension Plans	$	83	$	11	$	—	$	1	$	—	$	—	$	8
OPEB	2		—		1		—		—		—		—

253

The tables below reflect the total benefits expected to be paid from the plan or from the Registrants’ assets.  The payments include the participants’ contributions to the plan for their share of the cost.  Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results.  The estimated payments for the pension benefits and OPEB are as follows:

Pension Plans	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
2026	$	357	$	35	$	43	$	42	$	32	$	18	$	21
2027	352		32		42		41		32		17		21
2028	352		32		41		41		31		18		21
2029	342		31		41		38		30		16		20
2030	331		29		40		38		29		16		20
Years 2031 to 2035, in Total	1,573		127		189		182		139		76		95

OPEB Benefit Payments	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
2026	$	111	$	9	$	17	$	14	$	11	$	6	$	8
2027	110		9		17		14		11		6		8
2028	108		9		17		13		11		6		8
2029	105		9		17		13		10		6		7
2030	104		8		16		13		10		6		7
Years 2031 to 2035, in Total	486		39		75		59		48		27		35

OPEB Medicare Subsidy Receipts	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
2026	$	—	$	—	$	—	$	—	$	—	$	—	$	—
2027	—		—		—		—		—		—		—
2028	—		—		—		—		—		—		—
2029	—		—		—		—		—		—		—
2030	—		—		—		—		—		—		—
Years 2031 to 2035, in Total	1		—		—		—		—		—		—

Components of Net Periodic Benefit Cost (Credit)

The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans:

Pension Plans

2025	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Service Cost	$	96	$	9	$	9	$	13	$	9	$	6	$	8
Interest Cost	211		17		25		25		19		10		13
Expected Return on Plan Assets	(281)		(23)		(38)		(39)		(28)		(15)		(15)
Amortization of Net Actuarial Loss	16		1		2		2		1		1		1
Net Periodic Benefit Cost (Credit)	42		4		(2)		1		1		2		7
Capitalized Portion	(45)		(5)		(4)		(4)		(5)		(3)		(3)
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	(3)	$	(1)	$	(6)	$	(3)	$	(4)	$	(1)	$	4

254

2024	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Service Cost	$	101	$	9	$	9	$	13	$	9	$	6	$	8
Interest Cost	207		17		25		24		19		10		12
Expected Return on Plan Assets	(320)		(25)		(43)		(42)		(33)		(17)		(17)
Amortization of Net Actuarial Loss	5		—		—		1		—		—		—
Settlements (a)	93		10		12		9		7		5		9
Net Periodic Benefit Cost	86		11		3		5		2		4		12
Capitalized Portion	(47)		(5)		(4)		(4)		(5)		(3)		(3)
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	39	$	6	$	(1)	$	1	$	(3)	$	1	$	9

(a)AEP will seek recovery for the portion of pension settlement costs related to regulated operations. These costs were deferred as a regulatory asset for AEP, AEP Texas, APCo and PSO in the fourth quarter of 2024.

2023	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Service Cost	$	94	$	8	$	9	$	12	$	8	$	5	$	8
Interest Cost	219		18		26		25		20		11		14
Expected Return on Plan Assets	(339)		(28)		(44)		(44)		(34)		(18)		(20)
Amortization of Net Actuarial Loss	2		—		—		—		—		—		—
Net Periodic Benefit Cost (Credit)	(24)		(2)		(9)		(7)		(6)		(2)		2
Capitalized Portion	(44)		(4)		(4)		(4)		(5)		(3)		(3)
Net Periodic Benefit Credit Recognized in Expense	$	(68)	$	(6)	$	(13)	$	(11)	$	(11)	$	(5)	$	(1)

OPEB

2025	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Service Cost	$	4	$	—	$	1	$	—	$	—	$	—	$	—
Interest Cost	34		3		5		4		3		2		2
Expected Return on Plan Assets	(113)		(9)		(17)		(13)		(11)		(6)		(8)
Amortization of Prior Service Credit	(3)		—		—		1		(1)		—		—
Net Periodic Benefit Credit	(78)		(6)		(11)		(8)		(9)		(4)		(6)
Capitalized Portion	(2)		—		—		—		—		—		—
Net Periodic Benefit Credit Recognized in Expense	$	(80)	$	(6)	$	(11)	$	(8)	$	(9)	$	(4)	$	(6)

255

2024	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Service Cost	$	4	$	—	$	—	$	1	$	—	$	—	$	—
Interest Cost	42		3		7		5		4		2		3
Expected Return on Plan Assets	(111)		(8)		(16)		(14)		(11)		(5)		(7)
Amortization of Prior Service Credit	(13)		(1)		(2)		(2)		(1)		(1)		(1)
Amortization of Net Actuarial Loss	3		—		—		1		—		—		—
Special/Contractual Termination Benefits	4		—		1		—		—		—		—
Net Periodic Benefit Credit	(71)		(6)		(10)		(9)		(8)		(4)		(5)
Capitalized Portion	(2)		—		—		—		—		—		—
Net Periodic Benefit Credit Recognized in Expense	$	(73)	$	(6)	$	(10)	$	(9)	$	(8)	$	(4)	$	(5)

2023	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Service Cost	$	5	$	—	$	1	$	1	$	—	$	—	$	—
Interest Cost	46		4		7		5		4		2		3
Expected Return on Plan Assets	(110)		(9)		(16)		(13)		(12)		(6)		(7)
Amortization of Prior Service Credit	(63)		(5)		(9)		(9)		(6)		(4)		(5)
Amortization of Net Actuarial Loss	15		1		2		2		2		1		1
Net Periodic Benefit Credit	(107)		(9)		(15)		(14)		(12)		(7)		(8)
Capitalized Portion	(2)		—		—		—		—		—		—
Net Periodic Benefit Credit Recognized in Expense	$	(109)	$	(9)	$	(15)	$	(14)	$	(12)	$	(7)	$	(8)

American Electric Power System Retirement Savings Plan

AEPSC sponsors the American Electric Power System Retirement Savings Plan, a defined contribution retirement savings plan for substantially all AEP subsidiary employees who are not covered by a retirement savings plan of the UMWA.  This qualified plan offers participants an opportunity to contribute a portion of their pay, includes features under Section 401(k) of the IRC and provides for company matching contributions.  The matching contributions to the plan are 100% of the first 1% of eligible employee contributions and 70% of the next 5% of contributions.

The following table provides the cost for matching contributions to the retirement savings plans by Registrant:

Year Ended December 31,	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
2025	$	84	$	7	$	8	$	11	$	8	$	6	$	6
2024	82		7		8		11		8		5		7
2023	88		7		8		11		8		5		7

256

UMWA Benefits

Health and Welfare Benefits (Applies to AEP and APCo)

AEP provides health and welfare benefits negotiated with the UMWA for certain unionized employees, retirees and their survivors who meet eligibility requirements. APCo also provides the same UMWA health and welfare benefits for certain unionized mining retirees and their survivors who meet eligibility requirements.  AEP administers the health and welfare benefits. Benefits are paid for APCo from its general assets and for AEP from a trust and its general assets.

Multiemployer Pension Benefits (Applies to AEP)

UMWA pension benefits are provided through the United Mine Workers of America 1974 Pension Plan (Employer Identification Number: 52-1050282, Plan Number 002), a multiemployer plan. The UMWA pension benefits are administered by a board of trustees appointed in equal numbers by the UMWA and the Bituminous Coal Operators’ Association (BCOA), an industry bargaining association. AEP makes contributions to the United Mine Workers of America 1974 Pension Plan based on provisions in its labor agreement and the plan documents. The UMWA pension plan is different from single-employer plans as an employer’s contributions may be used to provide benefits to employees of other participating employers.  A withdrawing employer may be subject to a withdrawal liability, which is calculated based upon that employer’s share of the plan’s unfunded benefit obligations.  If an employer fails to make required contributions or if its payments in connection with its withdrawal liability fall short of satisfying its share of the plan’s unfunded benefit obligations, the remaining employers may be allocated a greater share of the remaining unfunded plan obligations. Under the Pension Protection Act of 2006 (PPA), the UMWA pension plan is in Critical Status for the plan year beginning July 1, 2025 and was in Critical Status for the plan year beginning July 1, 2024.  As required under the PPA, the Plan adopted a Rehabilitation Plan in 2015. The Rehabilitation Plan has been updated annually, most recently April 25, 2025.

AEP affiliates contributed $471 thousand, $379 thousand and $396 thousand to the United Mine Workers of America 1974 Pension Plan for the years ended December 31, 2025, 2024 and 2023, respectively. The contributions did not include surcharges. An AEP affiliate, Cook Coal Terminal (CCT), was listed in the plan’s 2023 Form 5500 as providing more than 5 percent of the total contributions for the plan year ending June 30, 2024. The plan’s 2023 Form 5500 was filed in the second quarter of 2025.

Under the terms of the UMWA pension plan, contributions will be required to continue beyond the January 25, 2027 expiration of the current collective bargaining agreement between the CCT facility and the UMWA, whether or not the term of that agreement is extended or a subsequent agreement is entered, so long as both the UMWA pension plan remains in effect and an AEP affiliate continues to operate the facility covered by the current collective bargaining agreement. The contribution rate applicable would be determined in accordance with the terms of the UMWA pension plan by reference to the National Bituminous Coal Wage Agreement, subject to periodic revisions, between the UMWA and the BCOA. If the UMWA pension plan would terminate or an AEP affiliate would cease operation of the facility without arranging for a successor operator to assume its liability, the withdrawal liability obligation would be triggered.

AEP records a UMWA pension withdrawal liability on the balance sheet that is re-measured annually and is the estimated value of the company’s anticipated contributions toward its proportionate share of the plan’s unfunded vested liabilities. As of December 31, 2025 and 2024, the liability balance was $12 million and $12 million, respectively. AEP recovers the estimated value of its UMWA pension withdrawal liability through fuel clauses in certain regulated jurisdictions. AEP records a regulatory asset on the balance sheets when the UMWA pension withdrawal liability exceeds the cumulative billings collected and a regulatory liability on the balance sheets when the cumulative billings collected exceed the withdrawal liability. If any portion of the UMWA pension withdrawal liability is not recoverable, it could reduce future net income and cash flows and impact financial condition.

257

9.  BUSINESS SEGMENTS

The disclosures in this note apply to all Registrants unless indicated otherwise.

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.

The CODM of AEP is the President and CEO of AEP, who makes operating decisions, allocates resources to and assesses performance based on these reportable segments. The CODM uses earnings (loss) attributable to AEP common shareholders (presented on a GAAP basis) as a measure of segment profit or loss in making these decisions. Earnings (loss) attributable to AEP common shareholders includes intercompany revenues and expenses that are eliminated on the consolidated financial statements.

AEP’s reportable segments and their related business activities are outlined below:

Vertically Integrated Utilities

•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.

Transmission and Distribution Utilities

•Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.

•OPCo purchases energy and capacity to serve standard service offer customers and provides transmission and distribution services for all connected load.

AEP Transmission Holdco

•Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved ROEs.

•Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved ROEs.

Generation & Marketing

•Marketing, risk management and retail activities in ERCOT, MISO, PJM and SPP.

•Competitive generation in PJM.

The remainder of AEP’s activities are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense, income tax expense and other nonallocated costs.

The tables below present AEP’s reportable segment income statement information for the years ended December 31, 2025, 2024 and 2023 and reportable segment balance sheet information as of December 31, 2025 and 2024.  The significant expenses disclosed below align with the segment-level information that is regularly provided to the CODM.

258

	VIU		T&D		AEPTHCo		G&M		Total Reportable Segments		Corporate and Other (a)			Reconciling Adjustments			Consolidated
2025	(in millions)
Revenues from:
External Customers	$	12,556	$	6,097	$	493	$	2,697	$	21,843	$	33		$	—		$	21,876
Other Operating Segments	263		50		1,884		65		2,262		111			(2,373)		(b)	—
Total Revenues	12,819		6,147		2,377		2,762		24,105		144			(2,373)			21,876
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	4,056		943		—		2,325		7,324		—			(293)			7,031
Other Operation and Maintenance	3,884		2,318		194		83		6,479		74			(2,104)			4,449
Asset Impairments and Other Related Charges	35		31		—		—		66		—			—			66
Depreciation and Amortization	2,076		821		487		16		3,400		(20)			—			3,380
Taxes Other Than Income Taxes	532		744		328		2		1,606		1			24			1,631
Allowance for Equity Funds Used During Construction	74		77		94		—		245		—			—			245
Interest Expense	856		424		241		8		1,529		592			(95)			2,026
Income Tax Expense (Benefit)	(60)		173		42		95		250		(121)			—			129
Equity Earnings of Unconsolidated Subsidiaries	1		2		87		—		90		11			—			101
Other Segment Items (c)	(90)		(44)		105		(54)		(83)		(82)			95			(70)
Earnings (Loss) Attributable to AEP Common Shareholders	$	1,605	$	816	$	1,161	$	287	$	3,869	$	(289)		$	—		$	3,580
Gross Property Additions	$	7,333	$	2,978	$	1,615	$	12	$	11,938	$	38		$	(70)		$	11,906
Total Assets	$	61,778	$	29,272	$	19,719	$	2,003	$	112,772	$	6,733	(d)	$	(5,045)	(e)	$	114,460
Investments in Equity Method Investees	$	9	$	4	$	1,068	$	—	$	1,081	$	171		$	—		$	1,252

	VIU		T&D		AEPTHCo		G&M		Total Reportable Segments		Corporate and Other (a)			Reconciling Adjustments			Consolidated
2024	(in millions)
Revenues from:
External Customers	$	11,414	$	5,880	$	425	$	1,945	$	19,664	$	57		$	—		$	19,721
Other Operating Segments	183		28		1,526		100		1,837		126			(1,963)		(b)	—
Total Revenues	11,597		5,908		1,951		2,045		21,501		183			(1,963)			19,721
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	3,796		909		—		1,542		6,247		—			(311)			5,936
Other Operation and Maintenance	3,528		2,166		163		130		5,987		137			(1,672)			4,452
Asset Impairments and Other Related Charges	14		53		—		76		143		—			—			143
Depreciation and Amortization	1,971		880		440		21		3,312		(22)			—			3,290
Taxes Other Than Income Taxes	535		724		315		2		1,576		—			20			1,596
Allowance for Equity Funds Used During Construction	52		69		90		—		211		—			—			211
Interest Expense	724		406		222		17		1,369		613			(119)			1,863
Income Tax Expense (Benefit)	(282)		155		215		26		114		(153)			—			(39)
Equity Earnings (Loss) of Unconsolidated Subsidiaries	1		(1)		99		1		100		(6)			—			94
Other Segment Items (c)	(89)		(43)		(5)		(57)		(194)		(107)			119			(182)
Earnings (Loss) Attributable to AEP Common Shareholders	$	1,453	$	726	$	790	$	289	$	3,258	$	(291)		$	—		$	2,967
Gross Property Additions	$	3,644	$	2,344	$	1,572	$	35	$	7,595	$	467		$	(32)		$	8,030
Total Assets	$	54,997	$	26,864	$	18,012	$	1,634	$	101,507	$	5,551	(d)	$	(3,980)	(e)	$	103,078
Investments in Equity Method Investees	$	9	$	2	$	996	$	—	$	1,007	$	49		$	—		$	1,056

259

	VIU		T&D		AEPTHCo		G&M		Total Reportable Segments		Corporate and Other (a)		Reconciling Adjustments			Consolidated
2023	(in millions)
Revenues from:
External Customers	$	11,304	$	5,677	$	397	$	1,543	$	18,921	$	61	$	—		$	18,982
Other Operating Segments	146		36		1,332		89		1,603		107		(1,710)		(b)	—
Total Revenues	11,450		5,713		1,729		1,632		20,524		168		(1,710)			18,982
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	4,150		1,215		—		1,488		6,853		—		(275)			6,578
Other Operation and Maintenance	3,211		1,948		142		133		5,434		103		(1,450)			4,087
Asset Impairments and Other Related Charges	86		—		—		—		86		—		—			86
Loss on the Sale of the Competitive Contracted Renewables Portfolio	—		—		—		93		93		—		—			93
Depreciation and Amortization	1,876		785		403		43		3,107		(17)		—			3,090
Taxes Other Than Income Taxes	513		668		290		6		1,477		—		15			1,492
Allowance for Equity Funds Used During Construction	46		46		83		—		175		—		—			175
Interest Expense	765		364		203		76		1,408		594		(195)			1,807
Income Tax Expense (Benefit)	(45)		140		166		(123)		138		(83)		—			55
Equity Earnings (Loss) of Unconsolidated Subsidiaries	1		—		83		(17)		67		(8)		—			59
Other Segment Items (c)	(149)		(60)		(12)		(75)		(296)		(179)		195			(280)
Earnings (Loss) Attributable to AEP Common Shareholders	$	1,090	$	699	$	703	$	(26)	$	2,466	$	(258)	$	—		$	2,208
Gross Property Additions	$	3,487	$	2,467	$	1,529	$	13	$	7,496	$	36	$	1		$	7,533
Investments in Equity Method Investees	$	10	$	3	$	906	$	101	$	1,020	$	54	$	—		$	1,074

(a)Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense, income tax expense and other nonallocated costs.

(b)Represents inter-segment revenues.

(c)Other segment items included in segment earnings (loss) attributable to AEP common shareholders primarily includes Interest and Dividend Income, Non-Service Cost Components of Net Period Benefit Cost and Net Income (Loss) Attributable to Noncontrolling Interests.

(d)Includes elimination of AEP Parent’s investments in wholly-owned subsidiary companies.

(e)Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable.

Registrant Subsidiaries’ Reportable Segments (Applies to all Registrant Subsidiaries except AEPTCo)

The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an integrated electricity transmission and distribution business for AEP Texas and OPCo.  Other activities are insignificant.  The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. The CODM of each Registrant Subsidiary is the AEP President and CEO, who makes operating decisions, allocates resources to and assesses performance based on these reportable segments. The CODM uses net income (loss) that is reported on the Registrant Subsidiaries’ statements of income as a measure of segment profit or loss in making these decisions. Net income (loss) includes intercompany revenues and expenses that are eliminated on the consolidated financial statements. The expenses disclosed on the Registrant Subsidiaries’ statements of income align with the segment-level significant expenses that are regularly provided to the CODM. Total Assets is reported on the consolidated financial statements. Gross Property Additions for the Registrant Subsidiaries is represented by the sum of Construction Expenditures and Acquisition of Assets on the consolidated financial statements. See Registrant Subsidiaries statements of income, balance sheets and cash flows for details.

260

AEPTCo’s Reportable Segments

AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities. The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting.” The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the RTOs in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP’s wholesale and retail customers. The State Transcos are regulated for ratemaking purposes exclusively by the FERC and earn revenues through tariff rates charged for the use of their electric transmission systems.

The CODM of AEPTCo is the AEP President and CEO, who makes operating decisions, allocates resources to and assesses performance based on these operating segments. The CODM uses earnings (loss) attributable to AEPTCo common shareholders (presented on a GAAP basis) as a measure of segment profit or loss in making these decisions. Earnings (loss) attributable to AEPTCo common shareholders includes intercompany revenues and expenses that are eliminated on the consolidated financial statements. The State Transcos operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one reportable segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities.

The tables below present AEPTCo’s reportable segment income statement information for the years ended December 31, 2025, 2024 and 2023 and reportable segment balance sheet information as of December 31, 2025 and 2024. The significant expenses disclosed below align with the segment-level information that is regularly provided to the CODM.

	State Transcos		AEPTCo Parent			Reconciling Adjustments			AEPTCo Consolidated
2025	(in millions)
Revenues from:
External Customers	$	450	$	—		$	—		$	450
Sales to AEP Affiliates	1,869		—			—			1,869
Total Revenues	2,319		—			—			2,319
Other Operation and Maintenance	185		—			—			185
Depreciation and Amortization	478		—			—			478
Taxes Other Than Income Taxes	321		—			—			321
Interest Income	3		308			(306)		(a)	5
Allowance for Equity Funds Used During Construction	93		—			—			93
Interest Expense	283		257			(306)		(a)	234
Income Tax Expense	4		11			—			15
Other Segment Items (b)	—		109			—			109
Earnings Attributable to AEPTCo Common Shareholders	$	1,144	$	(69)	(c)	$	—		$	1,075
Gross Property Additions	$	1,579	$	—		$	—		$	1,579
Total Assets	$	17,983	$	6,766	(d)	$	(6,750)	(e)	$	17,999

261

	State Transcos		AEPTCo Parent			Reconciling Adjustments			AEPTCo Consolidated
2024	(in millions)
Revenues from:
External Customers	$	379	$	—		$	—		$	379
Sales to AEP Affiliates	1,512		—			—			1,512
Total Revenues	1,891		—			—			1,891
Other Operation and Maintenance	156		2			—			158
Depreciation and Amortization	431		—			—			431
Taxes Other Than Income Taxes	309		—			—			309
Interest Income	8		241			(239)		(a)	10
Allowance for Equity Funds Used During Construction	89		—			—			89
Interest Expense	214		239			(239)		(a)	214
Income Tax Expense	190		—			—			190
Earnings Attributable to AEPTCo Common Shareholders	$	688	$	—	(c)	$	—		$	688
Gross Property Additions	$	1,482	$	—		$	—		$	1,482
Total Assets	$	16,888	$	8,670	(d)	$	(9,188)	(e)	$	16,370

	State Transcos		AEPTCo Parent			Reconciling Adjustments			AEPTCo Consolidated
2023	(in millions)
Revenues from:
External Customers	$	354	$	—		$	—		$	354
Sales to AEP Affiliates	1,317		—			—			1,317
Total Revenues	1,671		—			—			1,671
Other Operation and Maintenance	129		—			—			129
Depreciation and Amortization	394		—			—			394
Taxes Other Than Income Taxes	283		—			—			283
Interest Income	4		218			(214)		(a)	8
Allowance for Equity Funds Used During Construction	83		—			—			83
Interest Expense	194		215			(214)		(a)	195
Income Tax Expense	145		2			—			147
Earnings Attributable to AEPTCo Common Shareholders	$	613	$	1	(c)	$	—		$	614
Gross Property Additions	$	1,503	$	—		$	—		$	1,503

(a)    Elimination of intercompany interest income/interest expense on affiliated debt arrangement.

(b)    Other segment items included in segment earnings (loss) attributable to AEPTCo common shareholders primarily includes Net Income (Loss) Attributable to Noncontrolling Interests.

(c)    Includes elimination of AEPTCo Parent’s equity earnings in the State Transcos.

(d)    Primarily relates to Notes Receivable from the State Transcos.

(e)    Primarily relates to elimination of Notes Receivable from the State Transcos.

262

10.  DERIVATIVES AND HEDGING

The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any derivative and hedging activity.

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

AEPSC is agent for and transacts on behalf of certain AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries.

The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets.  These risks include commodity price risks which may be subject to capacity risk, interest rate risk and credit risk.  These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates.  Management utilizes derivative instruments to manage these risks.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies.  The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities.  To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options.  Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.”  Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” 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 Board of Directors of AEP.

The following table represents the gross notional volume of the Registrants’ outstanding derivative contracts:

	Notional Volume of Derivative Instruments
	December 31, 2025														December 31, 2024
Primary Risk Exposure	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo		AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Commodity:
Power (MWhs)	327		—		23		8		2		8		6		282		—		24		8		2		5		5
Natural Gas (MMBtus)	166		—		48		—		—		44		26		153		—		42		—		—		46		15
Heating Oil and Gasoline (Gallons)	8		2		1		2		1		1		1		8		2		1		2		1		1		1
Interest Rate (USD)	$	40	$	—	$	—	$	—	$	—	$	—	$	—	$	59	$	—	$	—	$	—	$	—	$	—	$	—
Interest Rate on Long-term Debt (USD)	$	500	$	—	$	—	$	—	$	—	$	—	$	—	$	950	$	—	$	—	$	—	$	—	$	—	$	—

Fair Value Hedging Strategies (Applies to AEP)

Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt.  Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating-rate.  Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges.

263

Cash Flow Hedging Strategies

The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales.  Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases.  The Registrants do not hedge all commodity price risk.

The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure.  The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt.  The Registrants do not hedge all interest rate exposure.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value.  The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes.  If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes and other assumptions.  In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality.

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due.  Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions.  Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts.  Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles.  Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period.  This is particularly true for longer term contracts.  Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts.

According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral.  For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third-party contractual agreements and risk profiles.  AEP netted cash collateral received from third-parties against short-term and long-term risk management assets in the amounts of $83 million and $87 million as of December 31, 2025 and 2024, respectively. There was no cash collateral received from third-parties netted against short-term and long-term risk management assets for the Registrant Subsidiaries as of December 31, 2025 and 2024. The amount of cash collateral paid to third-parties netted against short-term and long-term risk management liabilities was not material for the Registrants as of December 31, 2025 and 2024.

264

Location and Fair Value of Derivative Assets and Liabilities Recognized In the Balance Sheet

The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets. The derivative instruments are disclosed as gross. They are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” Unless shown as a separate line on the balance sheets due to materiality, Current Risk Management Assets are included in Prepayments and Other Current Assets, Long-term Risk Management Assets are included in Deferred Charges and Other Noncurrent Assets, Current Risk Management Liabilities are included in Other Current Liabilities and Long-term Risk Management Liabilities are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets.

	December 31, 2025
	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Assets:	(in millions)
Current Risk Management Assets
Risk Management Contracts - Commodity	$	720	$	—	$	82	$	23	$	—	$	44	$	37
Hedging Contracts - Commodity	56		—		—		—		—		—		—
Total Current Risk Management Assets	776		—		82		23		—		44		37
Long-term Risk Management Assets
Risk Management Contracts - Commodity	518		—		2		1		—		—		—
Hedging Contracts - Commodity	63		—		—		—		—		—		—
Total Long-term Risk Management Assets	581		—		2		1		—		—		—
Total Assets	$	1,357	$	—	$	84	$	24	$	—	$	44	$	37
Liabilities:
Current Risk Management Liabilities
Risk Management Contracts - Commodity	$	500	$	—	$	5	$	13	$	5	$	29	$	11
Hedging Contracts - Commodity	16		—		—		—		—		—		—
Hedging Contracts - Interest Rate	16		—		—		—		—		—		—
Total Current Risk Management Liabilities	532		—		5		13		5		29		11
Long-term Risk Management Liabilities
Risk Management Contracts - Commodity	420		—		1		1		28		1		2
Hedging Contracts - Commodity	5		—		—		—		—		—		—
Hedging Contracts - Interest Rate	13		—		—		—		—		—		—
Total Long-term Risk Management Liabilities	438		—		1		1		28		1		2
Total Liabilities	$	970	$	—	$	6	$	14	$	33	$	30	$	13
Total MTM Derivative Contract Net Assets (Liabilities) Recognized	$	387	$	—	$	78	$	10	$	(33)	$	14	$	24

265

	December 31, 2024
	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Assets:	(in millions)
Current Risk Management Assets
Risk Management Contracts - Commodity	$	425	$	—	$	40	$	29	$	—	$	22	$	19
Hedging Contracts - Commodity	54		—		—		—		—		—		—
Total Current Risk Management Assets	479		—		40		29		—		22		19
Long-term Risk Management Assets
Risk Management Contracts - Commodity	475		—		2		1		—		2		—
Hedging Contracts - Commodity	85		—		—		—		—		—		—
Total Long-term Risk Management Assets	560		—		2		1		—		2		—
Total Assets	$	1,039	$	—	$	42	$	30	$	—	$	24	$	19
Liabilities:
Current Risk Management Liabilities
Risk Management Contracts - Commodity	$	304	$	—	$	7	$	11	$	8	$	8	$	3
Hedging Contracts - Commodity	11		—		—		—		—		—		—
Hedging Contracts - Interest Rate	36		—		—		—		—		—		—
Total Current Risk Management Liabilities	351		—		7		11		8		8		3
Long-term Risk Management Liabilities
Risk Management Contracts - Commodity	391		—		—		2		40		—		—
Hedging Contracts - Commodity	3		—		—		—		—		—		—
Hedging Contracts - Interest Rate	35		—		—		—		—		—		—
Total Long-term Risk Management Liabilities	429		—		—		2		40		—		—
Total Liabilities	$	780	$	—	$	7	$	13	$	48	$	8	$	3
Total MTM Derivative Contract Net Assets (Liabilities) Recognized	$	259	$	—	$	35	$	17	$	(48)	$	16	$	16

266

Offsetting Assets and Liabilities

The following tables show the net amounts of assets and liabilities presented on the balance sheets. The gross amounts offset include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with accounting guidance for “Derivatives and Hedging.” All derivative contracts subject to a master netting arrangement or similar agreement are offset on the balance sheets.

	December 31, 2025
	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Assets:	(in millions)
Current Risk Management Assets
Gross Amounts Recognized	$	776	$	—	$	82	$	23	$	—	$	44	$	37
Gross Amounts Offset	(424)		—		(1)		(13)		—		(2)		(2)
Net Amounts Presented	352		—		81		10		—		42		35
Long-term Risk Management Assets
Gross Amounts Recognized	581		—		2		1		—		—		—
Gross Amounts Offset	(316)		—		(1)		(1)		—		—		—
Net Amounts Presented	265		—		1		—		—		—		—
Total Assets	$	617	$	—	$	82	$	10	$	—	$	42	$	35
Liabilities:
Current Risk Management Liabilities
Gross Amounts Recognized	$	532	$	—	$	5	$	13	$	5	$	29	$	11
Gross Amounts Offset	(400)		—		(2)		(13)		—		(2)		(2)
Net Amounts Presented	132		—		3		—		5		27		9
Long-term Risk Management Liabilities
Gross Amounts Recognized	438		—		1		1		28		1		2
Gross Amounts Offset	(260)		—		(1)		(1)		—		—		—
Net Amounts Presented	178		—		—		—		28		1		2
Total Liabilities	$	310	$	—	$	3	$	—	$	33	$	28	$	11
Total MTM Derivative Contract Net Assets (Liabilities)	$	307	$	—	$	79	$	10	$	(33)	$	14	$	24

	December 31, 2024
	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Assets:	(in millions)
Current Risk Management Assets
Gross Amounts Recognized	$	479	$	—	$	40	$	29	$	—	$	22	$	19
Gross Amounts Offset	(269)		—		(4)		(11)		—		(1)		(1)
Net Amounts Presented	210		—		36		18		—		21		18
Long-term Risk Management Assets
Gross Amounts Recognized	560		—		2		1		—		2		—
Gross Amounts Offset	(271)		—		(1)		(1)		—		(1)		—
Net Amounts Presented	289		—		1		—		—		1		—
Total Assets	$	499	$	—	$	37	$	18	$	—	$	22	$	18
Liabilities:
Current Risk Management Liabilities
Gross Amounts Recognized	$	351	$	—	$	7	$	11	$	8	$	8	$	3
Gross Amounts Offset	(251)		—		(5)		(11)		(1)		(2)		(1)
Net Amounts Presented	100		—		2		—		7		6		2
Long-term Risk Management Liabilities
Gross Amounts Recognized	429		—		—		2		40		—		—
Gross Amounts Offset	(205)		—		—		(2)		—		—		—
Net Amounts Presented	224		—		—		—		40		—		—
Total Liabilities	$	324	$	—	$	2	$	—	$	47	$	6	$	2
Total MTM Derivative Contract Net Assets (Liabilities)	$	175	$	—	$	35	$	18	$	(47)	$	16	$	16

267

The tables below present the Registrants’ amount of gain (loss) recognized on risk management contracts:

Amount of Gain (Loss) Recognized on Risk Management Contracts

	Year Ended December 31, 2025
Location of Gain (Loss)	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Vertically Integrated Utilities Revenues	$	(9)	$	—	$	—	$	—	$	—	$	—	$	—
Generation & Marketing Revenues	102		—		—		—		—		—		—
Electric Generation, Transmission and Distribution Revenues	—		—		—		(10)		—		—		—
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	7		—		7		—		—		—		—
Regulatory Assets (a)	(16)		—		—		—		15		(25)		(6)
Regulatory Liabilities (a)	394		—		124		28		1		116		100
Total Gain on Risk Management Contracts	$	478	$	—	$	131	$	18	$	16	$	91	$	94

	Year Ended December 31, 2024
Location of Gain (Loss)	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Vertically Integrated Utilities Revenues	$	(24)	$	—	$	—	$	—	$	—	$	—	$	—
Generation & Marketing Revenues	(172)		—		—		—		—		—		—
Electric Generation, Transmission and Distribution Revenues	—		—		—		(24)		—		—		—
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	3		—		3		—		—		—		—
Regulatory Assets (a)	73		—		22		3		(2)		26		14
Regulatory Liabilities (a)	271		—		53		13		—		94		95
Total Gain (Loss) on Risk Management Contracts	$	151	$	—	$	78	$	(8)	$	(2)	$	120	$	109

	Year Ended December 31, 2023
Location of Gain (Loss)	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Vertically Integrated Utilities Revenues	$	25	$	—	$	—	$	—	$	—	$	—	$	—
Generation & Marketing Revenues	(424)		—		—		—		—		—		—
Electric Generation, Transmission and Distribution Revenues	—		—		—		24		—		—		—
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	3		—		2		—		—		—		—
Other Operation	(1)		—		—		—		—		—		—
Maintenance	(1)		(1)		—		—		—		—		—
Regulatory Assets (a)	(95)		—		(22)		(3)		(14)		(30)		(16)
Regulatory Liabilities (a)	170		—		1		8		—		89		71
Total Gain (Loss) on Risk Management Contracts	$	(323)	$	(1)	$	(19)	$	29	$	(14)	$	59	$	55

(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

268

Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.”  Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis.

The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship.  Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same line item on the statements of income as that of the associated risk being hedged. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”

Accounting for Fair Value Hedging Strategies (Applies to AEP)

For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts net income during the period of change.

AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income.

The following table shows the impacts recognized on the balance sheets related to the hedged items in fair value hedging relationships:

	Carrying Amount of the Hedged Liabilities				Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities
	December 31, 2025		December 31, 2024		December 31, 2025		December 31, 2024
	(in millions)
Long-term Debt (a) (b)	$	(484)	$	(899)	$	15	$	49

(a)Amounts included within Noncurrent Liabilities line item Long-term Debt on the balance sheet.

(b)Amounts include $(14) million and $(22) million as of December 31, 2025 and 2024, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued.

The pretax effects of fair value hedge accounting on income were as follows:

	Years Ended December 31,
	2025		2024		2023
	(in millions)
Gain (Loss) on Interest Rate Contracts:
Fair Value Hedging Instruments (a)	$	42	$	27	$	29
Fair Value Portion of Long-term Debt (a)	(42)		(27)		(29)

(a)Gain (Loss) is included in Interest Expense on the statements of income.

269

Accounting for Cash Flow Hedging Strategies (Applies to AEP, AEP Texas, APCo, I&M, PSO and SWEPCo)

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects net income.  

Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity, Fuel and Other Consumables Used for Electric Generation on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged.  During the years ended 2025, 2024 and 2023, AEP applied cash flow hedging to outstanding power derivatives and the Registrant Subsidiaries did not.

The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur.  During the year ended 2025, the Registrants did not apply cash flow hedging to outstanding interest rate derivatives. During the year ended 2024, AEP, AEP Texas and PSO applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not. During the year ended 2023, AEP, AEP Texas, I&M, PSO and SWEPCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not.

For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 - Comprehensive Income.

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were:

	Impact of Cash Flow Hedges on the Registrants’ Balance Sheets
	December 31, 2025								December 31, 2024
					Portion Expected to								Portion Expected to
	AOCI				be Reclassed to				AOCI				be Reclassed to
	Gain (Loss)				Net Income During				Gain (Loss)				Net Income During
	Net of Tax				the Next Twelve Months				Net of Tax				the Next Twelve Months
	Commodity		Interest Rate		Commodity		Interest Rate		Commodity		Interest Rate		Commodity		Interest Rate
	(in millions)
AEP	$	78	$	(1)	$	31	$	—	$	99	$	3	$	34	$	3
AEP Texas	—		6		—		1		—		6		—		1
APCo	—		4		—		1		—		5		—		1
I&M	—		(5)		—		—		—		(5)		—		—
PSO	—		2		—		—		—		4		—		—
SWEPCo	—		1		—		—		—		1		—		—

As of December 31, 2025 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is approximately 9 years.

The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.

270

Credit Risk

Management mitigates credit risk 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.

Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required.

Credit-Risk-Related Contingent Features

Credit Downgrade Triggers (Applies to AEP)

A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. The Registrants have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. The total exposure of AEP’s derivative contracts with collateral triggering events in a net liability position was immaterial as of December 31, 2025 and 2024. The Registrant Subsidiaries had no derivative contracts with collateral triggering events in a net liability position as of December 31, 2025 and 2024.

Cross-Acceleration Triggers (Applies to AEP)

Certain interest rate derivative contracts contain cross-acceleration provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-acceleration provisions could be triggered if there was a non-performance event by the Registrants under any of their outstanding debt of at least $50 million and the lender on that debt has accelerated the entire repayment obligation. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-acceleration provisions in contracts. AEP had derivative contracts with cross-acceleration provisions in a net liability position of $30 million and $72 million and no cash collateral posted as of December 31, 2025 and 2024, respectively. If a cross-acceleration provision would have been triggered, settlement at fair value would have been required. The Registrant Subsidiaries’ had no derivative contracts with cross-acceleration provisions outstanding as of December 31, 2025 and 2024.

Cross-Default Triggers (Applies to AEP, APCo, PSO and SWEPCo)

In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third-party obligation that is $50 million or greater.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. AEP had derivative contracts with cross-default provisions in a net liability position of $183 million and $164 million and no cash collateral posted as of December 31, 2025 and 2024, respectively, after considering contractual netting arrangements. APCo, PSO and SWEPCo had derivative contracts with cross-default provisions in a net liability position of $2 million, $27 million and $10 million, respectively, and no cash collateral posted as of December 31, 2025. APCo, PSO and SWEPCo had derivative contracts with cross-default provisions in a net liability position of $1 million, $4 million and $2 million, respectively, and no cash collateral posted as of December 31, 2024. If a cross-default provision would have been triggered, settlement at fair value would have been required. The other Registrant Subsidiaries had no derivative contracts with cross-default provisions in a net liability position as of December 31, 2025 and 2024.

271

11.  FAIR VALUE MEASUREMENTS

The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise.

Fair Value Measurements of Long-term Debt (Applies to all Registrants)

The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs.  These instruments are not marked-to-market.  The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

The book values and fair values of Long-term Debt are summarized in the following table:

	December 31,
	2025				2024
Company	Book Value		Fair Value		Book Value		Fair Value
	(in millions)
AEP	$	47,322	$	44,930	$	42,643	$	38,965
AEP Texas	7,016		6,586		6,442		5,831
AEPTCo	6,599		5,812		5,768		4,853
APCo	6,259		6,147		5,661		5,346
I&M	3,561		3,288		3,494		3,154
OPCo	3,718		3,331		3,716		3,203
PSO	3,526		3,349		2,856		2,562
SWEPCo	4,974		4,603		3,981		3,432

272

Fair Value Measurements of Other Temporary Investments (Applies to AEP)

Other Temporary Investments include marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS.  See “Other Temporary Investments” section of Note 1 for additional information.

The following is a summary of Other Temporary Investments and Restricted Cash:

	December 31, 2025
			Gross		Gross
			Unrealized		Unrealized		Fair
Other Temporary Investments and Restricted Cash	Cost		Gains		Losses		Value
	(in millions)
Restricted Cash (a)	$	71	$	—	$	—	$	71
Other Cash Deposits	13		—		—		13
Fixed Income Securities – Mutual Funds (b)	167		—		(2)		165
Equity Securities – Mutual Funds	13		29		—		42
Total Other Temporary Investments and Restricted Cash	$	264	$	29	$	(2)	$	291

	December 31, 2024
			Gross		Gross
			Unrealized		Unrealized		Fair
Other Temporary Investments and Restricted Cash	Cost		Gains		Losses		Value
	(in millions)
Restricted Cash (a)	$	43	$	—	$	—	$	43
Other Cash Deposits	13		—		—		13
Fixed Income Securities – Mutual Funds (b)	167		—		(5)		162
Equity Securities – Mutual Funds	13		27		—		40
Total Other Temporary Investments and Restricted Cash	$	236	$	27	$	(5)	$	258

(a)Primarily represents amounts held for the repayment of debt.

(b)Primarily short and intermediate maturities which may be sold and do not contain maturity dates.

The following table provides the activity for fixed income and equity securities within Other Temporary Investments:

	Years Ended December 31,
	2025		2024		2023
	(in millions)
Proceeds from Investment Sales	$	26	$	27	$	7
Purchases of Investments	22		21		19
Gross Realized Gains on Investment Sales	4		6		1
Gross Realized Losses on Investment Sales	1		1		—

273

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M)

Securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF are recorded at fair value.  See “Nuclear Trust Funds” section of Note 1 for additional information.

The following is a summary of nuclear trust fund investments:

	December 31,
	2025								2024
			Gross		Gross		Other-Than-				Gross		Gross		Other-Than-
	Fair		Unrealized		Unrealized		Temporary		Fair		Unrealized		Unrealized		Temporary
	Value		Gains		Losses		Impairments		Value		Gains		Losses		Impairments
	(in millions)
Cash and Cash Equivalents	$	29	$	—	$	—	$	—	$	24	$	—	$	—	$	—
Fixed Income Securities:
United States Government	1,351		22		(1)		(15)		1,323		8		(5)		(20)
Corporate Debt	376		6		(7)		(6)		210		1		(10)		(6)
Subtotal Fixed Income Securities	1,727		28		(8)		(21)		1,533		9		(15)		(26)
Equity Securities - Domestic	3,160		2,621		(1)		—		2,838		2,289		—		—
Spent Nuclear Fuel and Decommissioning Trusts	$	4,916	$	2,649	$	(9)	$	(21)	$	4,395	$	2,298	$	(15)	$	(26)

The following table provides the securities activity within the decommissioning and SNF trusts:

	Years Ended December 31,
	2025		2024		2023
	(in millions)
Proceeds from Investment Sales	$	2,909	$	2,851	$	2,788
Purchases of Investments	2,959		2,902		2,845
Gross Realized Gains on Investment Sales	120		126		99
Gross Realized Losses on Investment Sales	5		12		27

The base cost of fixed income securities was $1.7 billion and $1.5 billion as of December 31, 2025 and 2024, respectively.  The base cost of equity securities was $540 million and $549 million as of December 31, 2025 and 2024, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2025 was as follows:

	Fair Value of Fixed
	Income Securities
	(in millions)
Within 1 year	$	402
After 1 year through 5 years	709
After 5 years through 10 years	223
After 10 years	393
Total	$	1,727

274

Fair Value Measurements of Financial Assets and Liabilities

For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1.

The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in management’s valuation techniques.

AEP

	December 31, 2025
	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)
Other Temporary Investments and Restricted Cash
Restricted Cash	$	48	$	—	$	—	$	23	$	71
Other Cash Deposits (a)	—		—		—		13		13
Fixed Income Securities – Mutual Funds	165		—		—		—		165
Equity Securities – Mutual Funds (b)	42		—		—		—		42
Total Other Temporary Investments and Restricted Cash	255		—		—		36		291
Risk Management Assets
Risk Management Commodity Contracts (c) (d)	2		831		393		(713)		513
Cash Flow Hedges:
Commodity Hedges (c)	—		100		18		(14)		104
Total Risk Management Assets	2		931		411		(727)		617
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	14		—		—		15		29
Fixed Income Securities:
United States Government	—		1,351		—		—		1,351
Corporate Debt	—		376		—		—		376
Subtotal Fixed Income Securities	—		1,727		—		—		1,727
Equity Securities – Domestic (b)	3,160		—		—		—		3,160
Total Spent Nuclear Fuel and Decommissioning Trusts	3,174		1,727		—		15		4,916
Total Assets	$	3,431	$	2,658	$	411	$	(676)	$	5,824
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (d)	$	4	$	752	$	151	$	(633)	$	274
Cash Flow Hedges:
Commodity Hedges (c)	—		19		1		(14)		6
Fair Value Hedges	—		30		—		—		30
Total Risk Management Liabilities	$	4	$	801	$	152	$	(647)	$	310

275

	December 31, 2024
	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)
Other Temporary Investments and Restricted Cash
Restricted Cash	$	43	$	—	$	—	$	—	$	43
Other Cash Deposits (a)	—		—		—		13		13
Fixed Income Securities – Mutual Funds	162		—		—		—		162
Equity Securities – Mutual Funds (b)	40		—		—		—		40
Total Other Temporary Investments and Restricted Cash	245		—		—		13		258
Risk Management Assets
Risk Management Commodity Contracts (c) (f)	3		597		292		(518)		374
Cash Flow Hedges:
Commodity Hedges (c)	—		116		22		(13)		125
Total Risk Management Assets	3		713		314		(531)		499
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	10		—		—		14		24
Fixed Income Securities:
United States Government	—		1,323		—		—		1,323
Corporate Debt	—		210		—		—		210
Subtotal Fixed Income Securities	—		1,533		—		—		1,533
Equity Securities – Domestic (b)	2,838		—		—		—		2,838
Total Spent Nuclear Fuel and Decommissioning Trusts	2,848		1,533		—		14		4,395
Total Assets	$	3,096	$	2,246	$	314	$	(504)	$	5,152
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (f)	$	4	$	534	$	148	$	(434)	$	252
Cash Flow Hedges:
Commodity Hedges (c)	—		13		—		(13)		—
Fair Value Hedges	—		72		—		—		72
Total Risk Management Liabilities	$	4	$	619	$	148	$	(447)	$	324

276

AEP Texas

	December 31, 2025
	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)
Restricted Cash for Securitized Funding	$	14	$	—	$	—	$	—	$	14

	December 31, 2024
	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)
Restricted Cash for Securitized Funding	$	24	$	—	$	—	$	—	$	24

APCo

	December 31, 2025
	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)
Restricted Cash for Securitized Funding	$	18	$	—	$	—	$	—	$	18
Risk Management Assets
Risk Management Commodity Contracts (c)	—		3		81		(2)		82
Total Assets	$	18	$	3	$	81	$	(2)	$	100
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	6	$	—	$	(3)	$	3

	December 31, 2024
	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)
Restricted Cash for Securitized Funding	$	16	$	—	$	—	$	—	$	16
Risk Management Assets
Risk Management Commodity Contracts (c)	—		7		35		(5)		37
Total Assets	$	16	$	7	$	35	$	(5)	$	53
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	7	$	—	$	(5)	$	2

277

I&M

	December 31, 2025
	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c)	$	—	$	12	$	9	$	(11)	$	10
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	14		—		—		15		29
Fixed Income Securities:
United States Government	—		1,351		—		—		1,351
Corporate Debt	—		376		—		—		376
Subtotal Fixed Income Securities	—		1,727		—		—		1,727
Equity Securities - Domestic (b)	3,160		—		—		—		3,160
Total Spent Nuclear Fuel and Decommissioning Trusts	3,174		1,727		—		15		4,916
Total Assets	$	3,174	$	1,739	$	9	$	4	$	4,926
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	11	$	—	$	(11)	$	—

	December 31, 2024
	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c)	$	—	$	19	$	7	$	(8)	$	18
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	10		—		—		14		24
Fixed Income Securities:
United States Government	—		1,323		—		—		1,323
Corporate Debt	—		210		—		—		210
Subtotal Fixed Income Securities	—		1,533		—		—		1,533
Equity Securities - Domestic (b)	2,838		—		—		—		2,838
Total Spent Nuclear Fuel and Decommissioning Trusts	2,848		1,533		—		14		4,395
Total Assets	$	2,848	$	1,552	$	7	$	6	$	4,413
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	9	$	1	$	(10)	$	—

278

OPCo

	December 31, 2025
	Level 1		Level 2		Level 3		Other		Total
Liabilities:	(in millions)
Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	—	$	33	$	—	$	33

	December 31, 2024
	Level 1		Level 2		Level 3		Other		Total
Liabilities:	(in millions)
Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	—	$	47	$	—	$	47

PSO

	December 31, 2025
	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c)	$	—	$	1	$	43	$	(2)	$	42
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	28	$	2	$	(2)	$	28

	December 31, 2024
	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)
Risk Management Assets
Risk Management Commodity Contracts (c)	$	—	$	3	$	21	$	(2)	$	22
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	7	$	1	$	(2)	$	6

279

SWEPCo

	December 31, 2025
	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)
Restricted Cash for Securitized Funding	$	15	$	—	$	—	$	—	$	15
Risk Management Assets
Risk Management Commodity Contracts (c)	—		—		37		(2)		35
Total Assets	$	15	$	—	$	37	$	(2)	$	50
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	11	$	2	$	(2)	$	11

	December 31, 2024
	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)
Restricted Cash for Securitized Funding	$	3	$	—	$	—	$	—	$	3
Risk Management Assets
Risk Management Commodity Contracts (c)	—		1		18		(1)		18
Total Assets	$	3	$	1	$	18	$	(1)	$	21
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	2	$	1	$	(1)	$	2

(a)Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or third-parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.

(b)Amounts represent publicly-traded equity securities and equity-based mutual funds.

(c)Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”

(d)The December 31, 2025 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $(2) million in 2026; Level 2 matures $12 million in 2026, $65 million in periods 2027-2029 and $1 million in periods 2030-2031; Level 3 matures $210 million in 2026, $51 million in periods 2027-2029, $(6) million in periods 2030-2031 and $(13) million in periods 2032-2034. Risk management commodity contracts are substantially comprised of energy contracts.

(e)Amounts in “Other” column primarily represent accrued interest receivables from financial institutions.  Level 1 amounts primarily represent investments in money market funds.

(f)The December 31, 2024 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows:  Level 1 matures $(1) million in 2025; Level 2 matures $(16) million in 2025, $(43) million in periods 2026-2028 and $4 million in periods 2029-2030; Level 3 matures $106 million in 2025, $45 million in periods 2026-2028, $9 million in periods 2029-2030 and $(16) million in periods 2031-2034.  Risk management commodity contracts are substantially comprised of energy contracts.

280

The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:

Year Ended December 31, 2025	AEP		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Balance as of December 31, 2024	$	166	$	35	$	6	$	(47)	$	20	$	17
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	157		50		13		—		38		43
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)	19		—		—		—		—		—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)	16		—		—		—		—		—
Settlements	(286)		(85)		(19)		7		(58)		(59)
Transfers into Level 3 (d) (e)	1		—		—		—		—		—
Transfers out of Level 3 (e)	(2)		—		—		—		—		—
Changes in Fair Value Allocated to Regulated Jurisdictions (f)	188		81		9		7		41		34
Balance as of December 31, 2025	$	259	$	81	$	9	$	(33)	$	41	$	35

Year Ended December 31, 2024	AEP		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Balance as of December 31, 2023	$	139	$	22	$	3	$	(51)	$	19	$	11
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	90		24		7		(1)		26		24
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)	15		—		—		—		—		—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)	4		—		—		—		—		—
Settlements	(168)		(46)		(10)		8		(45)		(36)
Transfers into Level 3 (d) (e)	7		—		—		—		—		—
Transfers out of Level 3 (e)	(6)		—		—		—		—		—
Changes in Fair Value Allocated to Regulated Jurisdictions (f)	85		35		6		(3)		20		18
Balance as of December 31, 2024	$	166	$	35	$	6	$	(47)	$	20	$	17

Year Ended December 31, 2023	AEP		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Balance as of December 31, 2022	$	160	$	69	$	5	$	(40)	$	24	$	14
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	52		(12)		4		(4)		30		20
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)	71		—		—		—		—		—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)	(17)		—		—		—		—		—
Settlements	(172)		(57)		(9)		6		(53)		(34)
Transfers into Level 3 (d) (e)	(6)		—		—		—		—		—
Transfers out of Level 3 (e)	4		—		—		—		—		—
Changes in Fair Value Allocated to Regulated Jurisdictions (f)	47		22		3		(13)		18		11
Balance as of December 31, 2023	$	139	$	22	$	3	$	(51)	$	19	$	11

(a)Included in revenues on the statements of income.

(b)Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.

(c)Included in cash flow hedges on the statements of comprehensive income.

(d)Represents existing assets or liabilities that were previously categorized as Level 2.

(e)Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.

(f)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income.  These changes in fair value are recorded as regulatory liabilities for net gains and as regulatory assets for net losses or accounts payable.

281

The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions:

Significant Unobservable Inputs

December 31, 2025

							Significant	Input/Range
	Type of	Fair Value				Valuation	Unobservable					Weighted
Company	Input	Assets		Liabilities		Technique	Input (a)	Low		High		Average (b)
		(in millions)
AEP	Energy Contracts	$	224	$	144	Discounted Cash Flow	Forward Market Price	$	5.65	$	141.75	$	50.61
AEP	FTRs	187		8		Discounted Cash Flow	Forward Market Price	(32.49)		21.68		0.49
APCo	FTRs	81		—		Discounted Cash Flow	Forward Market Price	(0.26)		17.55		3.47
I&M	FTRs	9		—		Discounted Cash Flow	Forward Market Price	(0.46)		21.68		1.60
OPCo	Energy Contracts	—		33		Discounted Cash Flow	Forward Market Price	21.44		85.92		50.10
PSO	FTRs	43		2		Discounted Cash Flow	Forward Market Price	(32.49)		8.54		(5.49)
SWEPCo	FTRs	37		2		Discounted Cash Flow	Forward Market Price	(32.49)		8.54		(5.49)

December 31, 2024

							Significant	Input/Range
	Type of	Fair Value				Valuation	Unobservable					Weighted
Company	Input	Assets		Liabilities		Technique	Input (a)	Low		High		Average (b)
		(in millions)
AEP	Energy Contracts	$	221	$	145	Discounted Cash Flow	Forward Market Price	$	2.75	$	149.30	$	49.34
AEP	FTRs	93		3		Discounted Cash Flow	Forward Market Price	(29.48)		19.70		0.24
APCo	FTRs	35		—		Discounted Cash Flow	Forward Market Price	(0.25)		9.32		1.56
I&M	FTRs	7		1		Discounted Cash Flow	Forward Market Price	(4.07)		9.32		1.34
OPCo	Energy Contracts	—		47		Discounted Cash Flow	Forward Market Price	14.53		72.40		42.44
PSO	FTRs	21		1		Discounted Cash Flow	Forward Market Price	(29.48)		10.54		(3.88)
SWEPCo	FTRs	18		1		Discounted Cash Flow	Forward Market Price	(29.48)		10.54		(3.88)

(a)Represents market prices in dollars per MWh.

(b)The weighted-average is the product of the forward market price of the underlying commodity and volume weighted by term.

The following table provides the measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, FTRs and Other Investments for the Registrants as of December 31, 2025 and 2024:

Uncertainty of Fair Value Measurements

Significant Unobservable Input	Position	Change in Input	Impact on Fair Value Measurement
Forward Market Price	Buy	Increase (Decrease)	Higher (Lower)
Forward Market Price	Sell	Increase (Decrease)	Lower (Higher)

282

12. INCOME TAXES

The disclosures in this note apply to all Registrants unless indicated otherwise.

Income Tax Expense (Benefit)

The details of the Registrants’ Income Tax Expense (Benefit) as reported are as follows:

Year Ended December 31, 2025	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Federal:
Current	$	(209)	$	27	$	148	$	42	$	(3)	$	27	$	(221)	$	(180)
Deferred	298		70		(173)		43		(14)		42		149		89
Total Federal	89		97		(25)		85		(17)		69		(72)		(91)
State and Local:
Current	28		4		18		2		19		(2)		—		3
Deferred	12		—		22		(1)		(1)		5		2		(7)
Total State and Local	40		4		40		1		18		3		2		(4)
Income Tax Expense (Benefit)	$	129	$	101	$	15	$	86	$	1	$	72	$	(70)	$	(95)

Year Ended December 31, 2024	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Federal:
Current	$	(3)	$	22	$	75	$	80	$	17	$	42	$	(119)	$	(112)
Deferred	(58)		77		89		(18)		(119)		(3)		20		(86)
Total Federal	(61)		99		164		62		(102)		39		(99)		(198)
State and Local:
Current	(5)		3		6		13		7		3		—		2
Deferred	27		—		20		—		—		10		(1)		12
Total State and Local	22		3		26		13		7		13		(1)		14
Income Tax Expense (Benefit)	$	(39)	$	102	$	190	$	75	$	(95)	$	52	$	(100)	$	(184)

Year Ended December 31, 2023	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Federal:
Current	$	(117)	$	20	$	94	$	62	$	94	$	46	$	(61)	$	(88)
Deferred	116		63		52		(60)		(57)		3		3		60
Total Federal	(1)		83		146		2		37		49		(58)		(28)
State and Local:
Current	69		3		9		6		21		—		—		1
Deferred	(13)		—		(8)		6		1		5		4		(6)
Total State and Local	56		3		1		12		22		5		4		(5)
Income Tax Expense (Benefit)	$	55	$	86	$	147	$	14	$	59	$	54	$	(54)	$	(33)

283

The following are reconciliations for the Registrants between the federal income taxes computed by multiplying pretax income by the federal statutory tax rate and the income taxes reported:

	Year Ended December 31,
AEP	2025					2024					2023
	(dollars in millions)
Net Income	$	3,696				$	2,976				$	2,213
Income Tax Expense (Benefit)	129					(39)					55
Pretax Income	$	3,825				$	2,937				$	2,268
	Amount			Percent		Amount			Percent		Amount			Percent
U.S. Federal Statutory Tax Rate	$	803		21.0	%	$	617		21.0	%	$	476		21.0	%
State and Local Income Taxes, Net (a)	31			0.8	%	17			0.6	%	44			1.9	%
Tax Credits:
Production Tax Credits	(244)			(6.4)	%	(214)			(7.3)	%	(175)			(7.7)	%
Investment Tax Credits	(3)			(0.1)	%	(58)			(2.0)	%	(50)			(2.2)	%
Other Credits	(4)			(0.1)	%	(9)			(0.3)	%	(1)			—	%
Non-Taxable or Non-Deductible Items	—			—	%	(3)			(0.1)	%	1			—	%
Changes in Unrecognized Tax Benefits	3			0.1	%	7			0.2	%	(5)			(0.2)	%
Other Adjustments:
Reversal of Origination Flow-Through	18			0.5	%	22			0.7	%	24			1.1	%
Tax Reform Excess ADIT Reversal	(62)			(1.6)	%	(92)			(3.1)	%	(151)			(6.7)	%
Remeasurement of Excess ADIT	(383)			(10.0)	%	(262)			(8.9)	%	(46)			(2.0)	%
AFUDC Equity	(41)			(1.1)	%	(42)			(1.4)	%	(38)			(1.7)	%
Other	11			0.3	%	(22)			(0.7)	%	(24)			(1.1)	%
Income Tax Expense (Benefit)	$	129				$	(39)				$	55
Effective Income Tax Rate	3.4		%			(1.3)		%			2.4		%

(a)     In 2025, state taxes in West Virginia and local taxes in Ohio contributed to the majority of the tax effect. In 2024, local taxes in Ohio contributed to the majority of the tax effect. In 2023, state taxes in Indiana and West Virginia contributed to the majority of the tax effect.

	Year Ended December 31,
AEP Texas	2025					2024					2023
	(dollars in millions)
Net Income	$	488				$	420				$	370
Income Tax Expense	101					102					86
Pretax Income	$	589				$	522				$	456
	Amount			Percent		Amount			Percent		Amount			Percent
U.S. Federal Statutory Tax Rate	$	124		21.0	%	$	110		21.0	%	$	96		21.0	%
State and Local Income Taxes, Net (a)	3			0.5	%	2			0.4	%	2			0.4	%
Tax Credits	(1)			(0.2)	%	(1)			(0.2)	%	(1)			(0.2)	%
Other Adjustments:
Tax Reform Excess ADIT Reversal	(11)			(1.9)	%	(5)			(1.0)	%	(6)			(1.3)	%
Remeasurement of Excess ADIT	—			—	%	6			1.1	%	—			—	%
AFUDC Equity	(10)			(1.7)	%	(9)			(1.7)	%	(5)			(1.1)	%
Other	(4)			(0.6)	%	(1)			—	%	—			—	%
Income Tax Expense	$	101				$	102				$	86
Effective Income Tax Rate	17.1		%			19.6		%			18.8		%

(a)     State taxes in Texas contributed to the majority of the tax effect.

284

	Year Ended December 31,
AEPTCo	2025					2024					2023
	(dollars in millions)
Net Income	$	1,184				$	688				$	614
Income Tax Expense	15					190					147
Pretax Income	$	1,199				$	878				$	761
	Amount			Percent		Amount			Percent		Amount			Percent
U.S. Federal Statutory Tax Rate	$	252		21.0	%	$	185		21.0	%	$	160		21.0	%
State and Local Income Taxes, Net (a)	31			2.6	%	20			2.3	%	1			0.1	%
Other Adjustments:
Remeasurement of Excess ADIT	(256)			(21.4)	%	—			—	%	—			—	%
AFUDC Equity	(16)			(1.3)	%	(16)			(1.8)	%	(15)			(2.0)	%
Other	4			0.4	%	1			0.2	%	1			0.2	%
Income Tax Expense	$	15				$	190				$	147
Effective Income Tax Rate	1.3		%			21.7		%			19.3		%

(a)     In 2025 and 2024, state taxes in Indiana and West Virginia contributed to the majority of the tax effect. In 2023, state taxes in West Virginia contributed to the majority of the tax effect.

	Year Ended December 31,
APCo	2025					2024					2023
	(dollars in millions)
Net Income	$	457				$	422				$	294
Income Tax Expense	86					75					14
Pretax Income	$	543				$	497				$	308
	Amount			Percent		Amount			Percent		Amount			Percent
U.S. Federal Statutory Tax Rate	$	114		21.0	%	$	104		21.0	%	$	65		21.0	%
State and Local Income Taxes, Net (a)	1			0.2	%	10			2.0	%	10			3.2	%
Tax Credits	(4)			(0.7)	%	(1)			(0.2)	%	—			—	%
Other Adjustments:
Reversal of Origination Flow-Through	6			1.1	%	5			1.0	%	9			2.9	%
Tax Reform Excess ADIT Reversal	(15)			(2.8)	%	(30)			(6.0)	%	(17)			(5.5)	%
Remeasurement of Excess ADIT	(24)			(4.4)	%	—			—	%	(46)			(14.9)	%
Removal Costs	(5)			(0.9)	%	(11)			(2.2)	%	(5)			(1.6)	%
AFUDC Equity	(2)			(0.4)	%	(2)			(0.4)	%	(4)			(1.3)	%
Flow-Through of CAMT	18			3.3	%	—			—	%	—			—	%
Other	(3)			(0.6)	%	—			(0.1)	%	2			0.8	%
Income Tax Expense	$	86				$	75				$	14
Effective Income Tax Rate	15.8		%			15.1		%			4.6		%

(a)     In 2025, state taxes in Virginia and West Virginia contributed to the majority of the tax effect. In 2024 and 2023, state taxes in West Virginia contributed to the majority of the tax effect.

285

	Year Ended December 31,
I&M	2025					2024					2023
	(dollars in millions)
Net Income	$	414				$	391				$	336
Income Tax Expense (Benefit)	1					(95)					59
Pretax Income	$	415				$	296				$	395
	Amount			Percent		Amount			Percent		Amount			Percent
U.S. Federal Statutory Tax Rate	$	87		21.0	%	$	62		21.0	%	$	83		21.0	%
State and Local Income Taxes, Net (a)	14			3.4	%	6			2.0	%	18			4.6	%
Tax Credits:
Production Tax Credits	(53)			(12.8)	%	(69)			(23.3)	%	—			—	%
Other Credits	(3)			(0.7)	%	(2)			(0.7)	%	(2)			(0.5)	%
Other Adjustments:
Reversal of Origination Flow-Through	6			1.4	%	5			1.7	%	6			1.5	%
Tax Reform Excess ADIT Reversal	(10)			(2.4)	%	(16)			(5.4)	%	(33)			(8.4)	%
Remeasurement of Excess ADIT	(38)			(9.2)	%	(73)			(24.7)	%	—			—	%
Removal Costs	—			—	%	(6)			(2.0)	%	(12)			(3.0)	%
Other	(2)			(0.5)	%	(2)			(0.7)	%	(1)			(0.3)	%
Income Tax Expense (Benefit)	$	1				$	(95)				$	59
Effective Income Tax Rate	0.2		%			(32.1)		%			14.9		%

(a)     State Taxes in Indiana contributed to the majority of the tax effect.

	Year Ended December 31,
OPCo	2025					2024					2023
	(dollars in millions)
Net Income	$	328				$	306				$	328
Income Tax Expense	72					52					54
Pretax Income	$	400				$	358				$	382
	Amount			Percent		Amount			Percent		Amount			Percent
U.S. Federal Statutory Tax Rate	$	84		21.0	%	$	75		21.0	%	$	80		21.0	%
State and Local Income Taxes, Net (a)	3			0.8	%	11			3.1	%	4			1.0	%
Other Adjustments:
Tax Reform Excess ADIT Reversal	(12)			(3.0)	%	(31)			(8.7)	%	(29)			(7.6)	%
AFUDC Equity	(4)			(1.0)	%	(4)			(1.1)	%	(3)			(0.8)	%
Other	1			0.2	%	1			0.3	%	2			0.6	%
Income Tax Expense	$	72				$	52				$	54
Effective Income Tax Rate	18.0		%			14.6		%			14.2		%

(a)     Local taxes in Ohio municipalities contributed to the majority of the tax effect.

286

	Year Ended December 31,
PSO	2025					2024					2023
	(dollars in millions)
Net Income	$	252				$	249				$	209
Income Tax Expense (Benefit)	(70)					(100)					(54)
Pretax Income	$	182				$	149				$	155
	Amount			Percent		Amount			Percent		Amount			Percent
U.S. Federal Statutory Tax Rate	$	38		21.0	%	$	31		21.0	%	$	33		21.0	%
State and Local Income Taxes, Net (a)	2			1.1	%	(1)			(0.7)	%	3			1.9	%
Tax Credits:
Production Tax Credits	(88)			(48.4)	%	(74)			(49.7)	%	(64)			(41.3)	%
Other Credits	(1)			(0.5)	%	(2)			(1.3)	%	(1)			(0.6)	%
Other Adjustments:
Tax Reform Excess ADIT Reversal	(5)			(2.7)	%	(6)			(4.0)	%	(23)			(14.8)	%
Remeasurement of Excess ADIT	(14)			(7.7)	%	(49)			(32.9)	%	—			—	%
Other	(2)			(1.3)	%	1			1.1	%	(2)			(0.7)	%
Income Tax Expense (Benefit)	$	(70)				$	(100)				$	(54)
Effective Income Tax Rate	(38.5)		%			(66.5)		%			(34.5)		%

(a)     State taxes in Oklahoma contributed to the majority of the tax effect.

	Year Ended December 31,
SWEPCo	2025					2024					2023
	(dollars in millions)
Net Income	$	391				$	326				$	224
Income Tax Expense (Benefit)	(95)					(184)					(33)
Pretax Income	$	296				$	142				$	191
	Amount			Percent		Amount			Percent		Amount			Percent
U.S. Federal Statutory Tax Rate	$	62		21.0	%	$	30		21.0	%	$	40		21.0	%
State and Local Income Taxes, Net (a)	(3)			(1.0)	%	11			7.7	%	(4)			(2.1)	%
Tax Credits
Production Tax Credits	(98)			(33.1)	%	(71)			(50.0)	%	(67)			(35.1)	%
Non-Taxable or Non-Deductible Items	—			—	%	(1)			(0.7)	%	—			—	%
Other Adjustments:
Tax Reform Excess ADIT Reversal	(6)			(2.0)	%	(4)			(2.8)	%	(13)			(6.8)	%
Remeasurement of Excess ADIT	(46)			(15.5)	%	(147)			(103.5)	%	—			—	%
Disallowance Cost	—			—	%	—			—	%	12			6.3	%
Other	(4)			(1.5)	%	(2)			(1.3)	%	(1)			(0.6)	%
Income Tax Expense (Benefit)	$	(95)				$	(184)				$	(33)
Effective Income Tax Rate	(32.1)		%			(129.6)		%			(17.3)		%

(a)     State taxes in Louisiana contributed to the majority of the tax effect.

287

Income Taxes Paid

The following tables show the amount of income taxes paid or (received) on an annual basis, disaggregated by federal and state jurisdictions, for each Registrant:

Year Ended December 31, 2025	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(dollars in millions)
Federal	$	70	$	46	$	191	$	88	$	23	$	62	$	(158)	$	(91)
State and Local:
IN	$	16	$	—	$	11	$	—	$	14	$	—	$	—	$	—
MI	—		—		—		—		4		—		—		—
TX	5		4		—		—		—		—		—		1
WV	8		—		11		17		1		—		—		—
All Other	4		—		1		—		1		—		—		—
Total To/(From) Tax Authority	$	103	$	50	$	214	$	105	$	43	$	62	$	(158)	$	(90)
Transfer Credits	(187)		—		—		—		—		—		(90)		(97)
Total Cash Paid/(Received)	$	(84)	$	50	$	214	$	105	$	43	$	62	$	(248)	$	(187)

Year Ended December 31, 2024	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(dollars in millions)
Federal	$	100	$	11	$	43	$	48	$	17	$	19	$	(15)	$	(15)
State and Local:
IN	$	7	$	—	$	—	$	—	$	7	$	—	$	—	$	—
WV	9		—		—		—		—		—		—		—
All Other	17		—		—		—		—		—		—		—
Total To/(From) Tax Authority	$	133	$	11	$	43	$	48	$	24	$	19	$	(15)	$	(15)
Transfer Credits	(202)		—		—		—		—		—		(96)		(89)
Total Cash Paid/(Received)	$	(69)	$	11	$	43	$	48	$	24	$	19	$	(111)	$	(104)

Year Ended December 31, 2023	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(dollars in millions)
Federal	$	38	$	12	$	87	$	47	$	93	$	39	$	(11)	$	(41)
State and Local:
IN	$	16	$	—	$	—	$	—	$	16	$	—	$	—	$	—
OH	10		—		1		—		—		—		—		—
TX	4		—		—		—		—		—		—		—
All Other	10		—		—		—		—		—		—		—
Total To/(From) Tax Authority	$	78	$	12	$	88	$	47	$	109	$	39	$	(11)	$	(41)
Transfer Credits	(102)		—		—		—		—		—		(35)		(41)
Total Cash Paid/(Received)	$	(24)	$	12	$	88	$	47	$	109	$	39	$	(46)	$	(82)

288

Net Deferred Tax Liability

The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant:

Year Ended December 31, 2025	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(dollars in millions)
Deferred Tax Assets	$	2,786	$	131	$	170	$	411	$	1,160	$	171	$	287	$	328
Deferred Tax Liabilities	(13,737)		(1,561)		(1,651)		(2,541)		(2,379)		(1,439)		(1,400)		(1,786)
Net Deferred Tax Liabilities	$	(10,951)	$	(1,430)	$	(1,481)	$	(2,130)	$	(1,219)	$	(1,268)	$	(1,113)	$	(1,458)
Property Related Temporary Differences	$	(9,456)	$	(1,442)	$	(1,526)	$	(1,881)	$	(49)	$	(1,333)	$	(1,195)	$	(1,477)
Amounts Due to Customers for Future Income Taxes	641		105		44		109		57		92		74		74
Securitized Assets	(211)		(28)		—		(19)		—		—		—		(50)
Regulatory Assets	(902)		(73)		(4)		(308)		(46)		(48)		(60)		(119)
Accrued Nuclear Decommissioning	(1,180)		—		—		—		(1,180)		—		—		—
Net Operating Loss Carryforward	155		—		—		—		—		—		44		45
Valuation Allowance	(49)		—		—		—		—		—		—		(3)
Tax Credit Carryforward	148		10		—		33		—		43		33		—
Operating Lease Liability	166		12		1		23		14		11		32		50
Investment in Partnership	(306)		—		—		—		—		(1)		—		(1)
All Other, Net	43		(14)		4		(87)		(15)		(32)		(41)		23
Net Deferred Tax Liabilities	$	(10,951)	$	(1,430)	$	(1,481)	$	(2,130)	$	(1,219)	$	(1,268)	$	(1,113)	$	(1,458)

Year Ended December 31, 2024	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(dollars in millions)
Deferred Tax Assets	$	2,652	$	139	$	173	$	379	$	1,072	$	187	$	267	$	293
Deferred Tax Liabilities	(12,624)		(1,462)		(1,452)		(2,413)		(2,248)		(1,388)		(1,198)		(1,564)
Net Deferred Tax Liabilities	$	(9,972)	$	(1,323)	$	(1,279)	$	(2,034)	$	(1,176)	$	(1,201)	$	(931)	$	(1,271)
Property Related Temporary Differences	$	(8,940)	$	(1,364)	$	(1,417)	$	(1,785)	$	(190)	$	(1,291)	$	(1,010)	$	(1,353)
Amounts Due to Customers for Future Income Taxes	780		109		121		119		73		96		81		90
Securitized Assets	(133)		(27)		—		(26)		—		—		—		(81)
Regulatory Assets	(966)		(63)		—		(302)		(49)		(45)		(53)		(87)
Accrued Nuclear Decommissioning	(1,052)		—		—		—		(1,052)		—		—		—
Net Operating Loss Carryforward	110		—		2		—		—		3		28		36
Valuation Allowance	(35)		—		—		—		—		—		—		—
Tax Credit Carryforward	198		4		—		—		40		39		27		32
Operating Lease Liability	145		12		—		16		14		13		27		36
Investment in Partnership	(302)		—		—		—		—		(1)		—		(2)
All Other, Net	223		6		15		(56)		(12)		(15)		(31)		58
Net Deferred Tax Liabilities	$	(9,972)	$	(1,323)	$	(1,279)	$	(2,034)	$	(1,176)	$	(1,201)	$	(931)	$	(1,271)

289

Federal and State Income Tax Audit Status

AEP is not currently under IRS audit and the statute of limitations (SOL) for the IRS to examine AEP and subsidiaries originally filed federal return has expired for tax years prior to 2022. In July 2025, AEP received notification that its 2023 federal income tax return was selected for IRS examination. However, this examination has yet to begin.

AEP and subsidiaries file income tax returns in various state and local jurisdictions. AEP and subsidiaries are not currently under any state and local income tax examinations. Generally, the SOL have expired for tax years prior to 2022. In addition, management is monitoring and continues to evaluate the potential impact of federal legislation and corresponding state conformity.

Net Income Tax Operating Loss Carryforward

As of December 31, 2025, AEP, PSO and SWEPCo have state income tax net operating loss deferred tax assets as indicated in the table below:

		Future State
		Income		Years of
Company	State/Municipality	Tax Benefit		Expiration
AEP	Arkansas	$	15	2031	-	2035
AEP	Illinois	5		2039	-	2041
AEP	Kentucky	11		2030	-	2037
AEP	Louisiana	41		Indefinite
AEP	Michigan	1		2029	-	2032
AEP	Ohio Municipal	62		2026	-	2030
AEP	Oklahoma	54		2037
AEP	Tennessee	4		2032	-	2040
PSO	Oklahoma	55		2037
SWEPCo	Arkansas	15		2031	-	2035
SWEPCo	Louisiana	41		Indefinite

Tax Credit Carryforward

As of December 31, 2025, AEP and the Registrants have federal tax credit carryforwards as indicated in the table below. The federal tax credit carryforwards are entirely CAMT credits which have an indefinite carryforward period. AEP and the Registrants anticipate future federal taxable income will be sufficient to realize the tax benefits of the CAMT credits.

As of December 31, 2025, AEP and PSO have state tax credit carryforwards as indicated in the table below, which have an indefinite carryforward period.

	Total Federal		Total State
	Tax Credit		Tax Credit
Company	Carryforward		Carryforward
	(dollars in millions)
AEP	$	108	$	41
AEP Texas	10		—
APCo	28		—
OPCo	43		—
PSO	—		41

290

Valuation Allowance

AEP assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that it is more-likely-than-not that AEP will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective evidence evaluated includes whether AEP has a history of recognizing income, future reversals of existing temporary differences and tax planning strategies.

Valuation allowance activity for the years ended December 31, 2025, 2024 and 2023 were not material.

Federal 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.

291

13.  LEASES

The disclosures in this note apply to all Registrants unless indicated otherwise.

The Registrants lease property, plant and equipment including, but not limited to, fleet, information technology and real estate leases. These leases require payments of non-lease components, including related property taxes, operating and maintenance costs. AEP does not separate non-lease components from associated lease components. Many of these leases have purchase or renewal options. Leases not renewed are often replaced by other leases. Options to renew or purchase a lease are included in the measurement of lease assets and liabilities if it is reasonably certain the Registrant will exercise the option.

Lease obligations are measured using the discount rate implicit in the lease when that rate is readily determinable. AEP has visibility into the rate implicit in the lease when assets are leased from selected financial institutions under master leasing agreements. When the implicit rate is not readily determinable, the Registrants measure their lease obligation using their estimated secured incremental borrowing rate. Incremental borrowing rates are comprised of an underlying risk-free rate and a secured credit spread relative to the lessee on a matched maturity basis.

Operating lease rentals and finance lease amortization costs are generally charged to Other Operation and Maintenance expense in accordance with ratemaking treatment for regulated operations. Interest on finance lease liabilities is generally charged to Interest Expense. Lease costs associated with capital projects are included in Property, Plant and Equipment on the balance sheets. For regulated operations with finance leases, a finance lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period.  Finance leases for nonregulated property are accounted for as if the assets were owned and financed.  The components of rental costs were as follows:

Year Ended December 31, 2025	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Operating Lease Cost	$	137	$	18	$	1	$	20	$	20	$	17	$	14	$	20
Finance Lease Cost:
Amortization of Right-of-Use Assets	51		8		—		9		6		4		3		4
Interest on Lease Liabilities	10		2		—		1		2		1		1		1
Total Lease Rental Costs (a)	$	198	$	28	$	1	$	30	$	28	$	22	$	18	$	25

Year Ended December 31, 2024	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Operating Lease Cost	$	146	$	32	$	1	$	18	$	20	$	17	$	14	$	18
Finance Lease Cost:
Amortization of Right-of-Use Assets	64		8		—		9		7		5		3		13
Interest on Lease Liabilities	12		1		—		2		2		1		1		1
Total Lease Rental Costs (a)	$	222	$	41	$	1	$	29	$	29	$	23	$	18	$	32

Year Ended December 31, 2023	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Operating Lease Cost	$	150	$	34	$	1	$	19	$	20	$	17	$	14	$	18
Finance Lease Cost:
Amortization of Right-of-Use Assets	69		8		—		8		7		5		3		20
Interest on Lease Liabilities	12		1		—		2		2		1		1		1
Total Lease Rental Costs (a)	$	231	$	43	$	1	$	29	$	29	$	23	$	18	$	39

(a)Excludes variable and short-term lease costs, which were immaterial.

292

Supplemental information related to leases are shown in the tables below:

December 31, 2025	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
Weighted-Average Remaining Lease Term (years):
Operating Leases	17.33		4.33		3.29		13.03		3.73		4.04		25.59		29.02
Finance Leases	4.53		4.80		0.00		4.42		5.12		4.24		4.61		5.60
Weighted-Average Discount Rate:
Operating Leases	4.74	%	4.57	%	4.51	%	5.08	%	4.61	%	4.36	%	4.48	%	4.96	%
Finance Leases	6.36	%	5.99	%	—	%	5.73	%	9.04	%	5.74	%	5.71	%	5.90	%

December 31, 2024	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
Weighted-Average Remaining Lease Term (years):
Operating Leases	12.80		4.45		2.29		5.39		4.43		4.64		23.68		21.97
Finance Leases	4.81		5.04		0.00		4.09		4.83		4.58		5.44		6.14
Weighted-Average Discount Rate:
Operating Leases	3.89	%	4.29	%	4.55	%	4.20	%	4.11	%	4.17	%	3.76	%	3.60	%
Finance Leases	6.43	%	5.73	%	—	%	6.69	%	9.07	%	5.59	%	5.48	%	5.73	%

Year Ended December 31, 2025	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating Cash Flows Used for Operating Leases	$	135	$	18	$	1	$	20	$	20	$	17	$	13	$	20
Operating Cash Flows Used for Finance Leases	10		1		—		1		2		1		1		1
Financing Cash Flows Used for Finance Leases	51		8		—		9		6		4		3		4
Non-cash Acquisitions Under Operating Leases	$	190	$	12	$	1	$	44	$	17	$	4	$	28	$	70

Year Ended December 31, 2024	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating Cash Flows Used for Operating Leases	$	144	$	32	$	1	$	18	$	20	$	17	$	13	$	17
Operating Cash Flows Used for Finance Leases	12		1		—		2		2		1		1		2
Financing Cash Flows Used for Finance Leases	65		8		—		9		7		5		3		14
Non-cash Acquisitions Under Operating Leases	$	82	$	6	$	1	$	9	$	15	$	5	$	3	$	27

293

The following tables show property, plant and equipment under finance leases and noncurrent assets under operating leases and related obligations recorded on the balance sheets.  Unless shown as a separate line on the balance sheets due to materiality, net operating lease assets are included in Deferred Charges and Other Noncurrent Assets, current finance lease obligations are included in Other Current Liabilities and long-term finance lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets. Lease obligations are not recognized on the balance sheets for lease agreements with a lease term of less than twelve months.

December 31, 2025	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Property, Plant and Equipment Under Finance Leases:
Generation	$	48	$	—	$	—	$	40	$	5	$	—	$	1	$	2
Other Property, Plant and Equipment	291		53		—		19		38		28		23		29
Total Property, Plant and Equipment	339		53		—		59		43		28		24		31
Accumulated Amortization	184		29		—		44		25		15		13		14
Net Property, Plant and Equipment Under Finance Leases	$	155	$	24	$	—	$	15	$	18	$	13	$	11	$	17
Obligations Under Finance Leases:
Noncurrent Liability	$	112	$	17	$	—	$	10	$	13	$	8	$	8	$	13
Liability Due Within One Year	43		7		—		4		4		4		3		4
Total Obligations Under Finance Leases	$	155	$	24	$	—	$	14	$	17	$	12	$	11	$	17

December 31, 2024	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Property, Plant and Equipment Under Finance Leases:
Generation	$	74	$	—	$	—	$	42	$	17	$	—	$	1	$	2
Other Property, Plant and Equipment	284		53		—		19		38		30		23		30
Total Property, Plant and Equipment	358		53		—		61		55		30		24		32
Accumulated Amortization	194		28		—		42		33		16		12		13
Net Property, Plant and Equipment Under Finance Leases	$	164	$	25	$	—	$	19	$	22	$	14	$	12	$	19
Obligations Under Finance Leases:
Noncurrent Liability	$	117	$	18	$	—	$	11	$	16	$	10	$	9	$	15
Liability Due Within One Year	47		7		—		8		6		4		3		4
Total Obligations Under Finance Leases	$	164	$	25	$	—	$	19	$	22	$	14	$	12	$	19

December 31, 2025	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Operating Lease Assets	$	661	$	52	$	3	$	95	$	52	$	50	$	126	$	198
Obligations Under Operating Leases:
Noncurrent Liability	$	578	$	40	$	2	$	81	$	37	$	37	$	122	$	195
Liability Due Within One Year	100		14		1		15		17		13		11		7
Total Obligations Under Operating Leases	$	678	$	54	$	3	$	96	$	54	$	50	$	133	$	202

294

December 31, 2024	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Operating Lease Assets	$	580	$	54	$	2	$	67	$	52	$	60	$	106	$	141
Obligations Under Operating Leases:
Noncurrent Liability	$	504	$	43	$	1	$	54	$	40	$	48	$	102	$	138
Liability Due Within One Year	92		13		1		14		12		12		10		8
Total Obligations Under Operating Leases	$	596	$	56	$	2	$	68	$	52	$	60	$	112	$	146

Future minimum lease payments consisted of the following as of December 31, 2025:

Finance Leases	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
2026	$	52	$	8	$	—	$	5	$	5	$	4	$	4	$	5
2027	41		6		—		3		5		3		3		4
2028	30		4		—		2		4		2		2		3
2029	21		3		—		2		3		1		1		3
2030	15		2		—		1		2		1		1		2
After 2030	21		5		—		2		3		1		2		4
Total Future Minimum Lease Payments	180		28		—		15		22		12		13		21
Less: Imputed Interest	25		4		—		1		5		—		2		4
Estimated Present Value of Future Minimum Lease Payments	$	155	$	24	$	—	$	14	$	17	$	12	$	11	$	17

Operating Leases	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
2026	$	133	$	17	$	1	$	20	$	19	$	16	$	13	$	21
2027	114		14		1		19		15		14		12		19
2028	99		11		1		16		13		12		11		17
2029	71		7		—		12		8		7		9		14
2030	47		5		—		8		2		3		7		12
After 2030	607		7		—		68		2		3		178		339
Total Future Minimum Lease Payments	1,071		61		3		143		59		55		230		422
Less: Imputed Interest	393		7		—		47		5		5		97		220
Estimated Present Value of Future Minimum Lease Payments	$	678	$	54	$	3	$	96	$	54	$	50	$	133	$	202

295

Master Lease Agreements (Applies to all Registrants except AEPTCo)

The Registrants lease certain equipment under master lease agreements.  Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee.  Historically, at the end of the lease term the fair value has been in excess of the amount guaranteed.  As of December 31, 2025, the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:

Company	Maximum Potential Loss
	(in millions)
AEP	$	38
AEP Texas	9
APCo	5
I&M	4
OPCo	6
PSO	4
SWEPCo	4

Lessor Activity

The Registrants’ lessor activity was immaterial as of and for the years ended December 31, 2025 and December 31, 2024, respectively.

296

14. VOLUNTARY SEVERANCE PROGRAM

In April 2024, management announced a voluntary severance program designed to achieve a reduction in the size of AEP’s workforce. Approximately 7,400 of AEP’s 16,800 employees were eligible to participate in the program. Approximately 1,000 employees chose to take the voluntary severance package and substantially all terminated employment in July 2024. The severance program provides two weeks of base pay for every year of service with a minimum of four weeks and a maximum of 52 weeks of base pay. Certain positions impacted by the voluntary severance program were refilled to maintain safe, effective and efficient operations. The program was completed to help offset increasing operating expenses and high interest costs.

AEP recorded a charge to expense in the second quarter of 2024 related to this voluntary severance program.

	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Severance Expense Incurred	$	122	$	20	$	11	$	26	$	15	$	15	$	10	$	17

These expenses were primarily included in Other Operation and Maintenance on the statements of income and Other Current Liabilities on the balance sheets. Settlement accounting was triggered for the qualified pension plan in November 2024 under the accounting guidance for “Compensation - Retirement Benefits” and a settlement charge of $90 million was recorded. As of December 31, 2025, all incurred expenses have been settled. AEP will seek approval for the pension expense related to regulated operations. See Note 8 - Benefit Plans for additional information associated with the plan.

297

15.  FINANCING ACTIVITIES

The disclosures in this note apply to all Registrants, unless indicated otherwise.

Common Stock (Applies to AEP)

The following table is a reconciliation of common stock share activity:

Shares of AEP Common Stock	Issued	Held in Treasury
Balance, December 31, 2022	525,099,321	11,233,240
Issued	2,269,836	—
Treasury Stock Reissued	—	(10,048,668)	(a)
Balance, December 31, 2023	527,369,157	1,184,572
Issued	6,725,373	—
Treasury Stock Reacquired	—	2,243
Balance, December 31, 2024	534,094,530	1,186,815
Issued	7,953,758	—
Balance, December 31, 2025	542,048,288	1,186,815

(a)Reissued Treasury Stock used to fulfill share commitments related to AEP’s Equity Units.

ATM Program

In November 2025, AEP filed a prospectus supplement and executed an Equity Distribution Agreement, pursuant to which AEP may sell, from time to time, up to an aggregate of $3.5 billion of its common stock through an ATM offering program, including an equity forward sales component. The compensation paid to the selling agents by AEP may be up to 2% of the gross offering proceeds of the shares. For the year ended 2025, AEP issued 176,402 shares of common stock and received net cash proceeds of $21 million under the ATM program. As of December 31, 2025, approximately $3.5 billion of equity is available for issuance under the ATM program.

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, which may include capital contributions to utility subsidiaries, 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.

298

Long-term Debt

The following table details long-term debt outstanding:

		Weighted-Average	Interest Rate Ranges as of		Outstanding as of
		Interest Rate as of	December 31,		December 31,
Company	Maturity	December 31, 2025	2025	2024	2025		2024
AEP					(in millions)
Senior Unsecured Notes	2026-2055	4.45%	1.63%-8.13%	1.00%-8.13%	$	37,190	$	36,411
Pollution Control Bonds (a)	2026-2038 (b)	3.62%	2.40%-4.70%	0.63%-4.70%	1,637		1,771
Notes Payable – Nonaffiliated (c)	2026-2034	5.97%	2.43%-6.89%	0.93%-6.89%	683		610
Securitization Bonds	2028-2045 (d)	4.71%	2.29%-5.30%	2.06%-4.88%	984		578
Spent Nuclear Fuel Obligation (e)					330		316
Junior Subordinated Notes	2027-2054	5.83%	3.88%-7.05%	3.88%-7.05%	4,681		2,579
Other Long-term Debt	2026-2059	4.88%	3.00%-13.72%	3.00%-13.72%	1,817		378
Total Long-term Debt Outstanding					$	47,322	$	42,643
AEP Texas
Senior Unsecured Notes	2026-2055	4.62%	2.10%-6.76%	2.10%-6.76%	$	6,472	$	5,874
Pollution Control Bonds (a)	2029-2030 (b)	3.88%	2.60%-4.55%	2.60%-4.55%	441		440
Securitization Bonds	2029 (d)	2.29%	2.29%	2.06%-2.29%	102		127
Other Long-term Debt	2059	4.50%	4.50%	4.50%	1		1
Total Long-term Debt Outstanding					$	7,016	$	6,442
AEPTCo
Senior Unsecured Notes	2026-2053	4.21%	2.75%-5.52%	2.75%-5.52%	$	6,100	$	5,768
Other Long-term Debt	2028	4.83%	4.83%	—%	499		—
Total Long-term Debt Outstanding					$	6,599	$	5,768
APCo
Senior Unsecured Notes	2027-2050	4.84%	2.70%-7.00%	2.70%-7.00%	$	4,688	$	4,984
Pollution Control Bonds (a)	2028-2038 (b)	3.92%	3.30%-3.70%	0.63%-4.22%	379		430
Securitization Bonds	2028 (d)	3.77%	3.77%	3.77%	92		120
Other Long-term Debt	2026-2028	4.89%	4.83%-13.72%	5.75%-13.72%	1,100		127
Total Long-term Debt Outstanding					$	6,259	$	5,661
I&M
Senior Unsecured Notes	2028-2053	4.52%	3.25%-6.05%	3.25%-6.05%	$	2,847	$	2,845
Pollution Control Bonds (a)	2029 (b)	3.70%	3.70%	0.75%-3.05%	149		190
Notes Payable – Nonaffiliated (c)	2026-2030	5.24%	3.44%-6.41%	0.93%-6.41%	235		143
Spent Nuclear Fuel Obligation (e)					330		316
Total Long-term Debt Outstanding					$	3,561	$	3,494
OPCo
Senior Unsecured Notes	2030-2051	4.16%	1.63%-6.60%	1.63%-6.60%	$	3,718	$	3,716
Total Long-term Debt Outstanding					$	3,718	$	3,716
PSO
Senior Unsecured Notes	2026-2051	4.59%	2.20%-6.63%	2.20%-6.63%	$	3,525	$	2,854
Other Long-term Debt	2027	3.00%	3.00%	3.00%	1		2
Total Long-term Debt Outstanding					$	3,526	$	2,856
SWEPCo
Senior Unsecured Notes	2026-2051	3.73%	1.65%-6.20%	1.65%-6.20%	$	3,653	$	3,650
Notes Payable – Affiliated	2028	4.24%	4.24%	—%	1,000		—
Securitization Bonds	2039 (d)	4.88%	4.88%	4.88%	321		331
Total Long-term Debt Outstanding					$	4,974	$	3,981

(a)For certain series of Pollution Control Bonds, interest rates are subject to periodic adjustment.  Certain series may be purchased on demand at periodic interest adjustment dates.  Letters of credit from banks and insurance policies support certain series. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets.

(b)Certain Pollution Control Bonds are subject to redemption earlier than the maturity date.

(c)Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates.

(d)Dates represent the scheduled final payment dates for the securitization bonds. The legal maturity date is one to two years later. These bonds have been classified for maturity and repayment purposes based on the scheduled final payment date.

(e)Spent Nuclear Fuel Obligation consists of a liability along with accrued interest for disposal of SNF. See “Spent Nuclear Fuel Disposal” section of Note 6 for additional information.

299

As of December 31, 2025, outstanding long-term debt was payable as follows:

	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
2026	$	3,194	$	75	$	425	$	1,131	$	117	$	—	$	51	$	917
2027	2,453		26		—		356		68		—		—		17
2028	3,468		526		559		413		388		—		—		1,593
2029	2,887		627		55		—		162		—		100		19
2030	1,809		942		60		—		1		350		—		20
After 2030	33,896		4,871		5,566		4,400		2,855		3,400		3,400		2,434
Principal Amount	47,707		7,067		6,665		6,300		3,591		3,750		3,551		5,000
Unamortized Discount, Net and Debt Issuance Costs	(385)		(51)		(66)		(41)		(30)		(32)		(25)		(26)
Total Long-term Debt Outstanding	$	47,322	$	7,016	$	6,599	$	6,259	$	3,561	$	3,718	$	3,526	$	4,974

Financing Activities Subsequent Events

In January 2026, AEPTCo issued $114 million of variable rate Other Long-term Debt due in 2028.

In January 2026, I&M retired $11 million of Notes Payable related to DCC Fuel.

In January 2026, Transource Energy issued $14 million of variable rate Other Long-term Debt due in 2028.

In February 2026, AEP made capital contributions of $81 million, $38 million and $128 million to APCo, OPCo and SWEPCo, respectively.

In February 2026, AEP Texas retired $12 million of Securitization Bonds.

In February 2026, APCo retired $14 million of Securitization Bonds.

Debt Covenants (Applies to AEP and AEPTCo)

Covenants in AEPTCo’s note purchase agreements and indenture limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. AEPTCo’s contractually-defined priority debt was 0.9% of consolidated tangible net assets as of December 31, 2025. The method for calculating the consolidated tangible net assets is contractually-defined in the note purchase agreements.

Dividend Restrictions

Subsidiary Restrictions

Parent depends on its subsidiaries to pay dividends to shareholders. AEP’s subsidiaries pay dividends to Parent provided funds are legally available. 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.

All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act requirement that prohibits the payment of dividends out of capital accounts in certain circumstances; payment of dividends is generally allowed out of retained earnings. The Federal Power Act also creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to APCo and I&M.

Certain AEP subsidiaries have credit agreements that contain covenants that limit their debt-to-capitalization ratio to 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements.

The most restrictive dividend limitation for certain AEP subsidiaries is through the Federal Power Act restriction, while for other AEP subsidiaries the most restrictive dividend limitation is through the credit agreements. As of December 31, 2025, the maximum amount of restricted net assets of AEP’s subsidiaries that may not be distributed to the Parent in the form of a loan, advance or dividend was $20.5 billion.

300

The Federal Power Act restriction limits the ability of the AEP subsidiaries owning hydroelectric generation to pay dividends out of retained earnings. Additionally, the credit agreement covenant restrictions can limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. As of December 31, 2025, the amount of any such restrictions were as follows:

	AEP			AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Restricted Retained Earnings	$	2,690	(a)	$	904	$	—	$	901	$	663	$	—	$	17	$	—

(a)    Includes the restrictions of consolidated and non-consolidated subsidiaries.

Parent Restrictions (Applies to AEP)

The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends.  Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries.

Pursuant to the leverage restrictions in credit agreements, AEP must 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 the credit agreements.  AEP may not declare or pay any cash dividend or distribution on its common stock during any period when AEP defers interest on its junior subordinated notes. As of December 31, 2025, AEP had $15.1 billion of available retained earnings to pay dividends to common shareholders. AEP paid $2.0 billion, $1.9 billion and $1.8 billion of dividends to common shareholders for the years ended December 31, 2025, 2024 and 2023, respectively.

Lines of Credit and Short-term Debt (Applies to AEP and SWEPCo)

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.  As of December 31, 2025, AEP had $6 billion in revolving credit facilities to support its commercial paper program.  

Securitized Debt for Receivables, for the year ended 2025, had a weighted-average interest rate of 4.46% and a maximum amount outstanding of $900 million. The commercial paper program, for the year ended 2025, had a weighted-average yield of 4.47% and a maximum amount outstanding of $2.9 billion. AEP’s outstanding short-term debt was as follows:

		December 31,
		2025				2024
Company	Type of Debt	Outstanding Amount		Interest Rate (a)		Outstanding Amount		Interest Rate (a)
		(in millions)				(in millions)
AEP	Securitized Debt for Receivables (b)	$	900	4.00	%	$	900	4.73	%
AEP	Commercial Paper	605		3.92	%	1,618		4.70	%
SWEPCo	Notes Payable	3		6.30	%	6		6.69	%
	Total Short-term Debt	$	1,508			$	2,524

(a)    Weighted-average rate of all borrowings outstanding as of December 31, 2025 and 2024, respectively.

(b)    Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

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Corporate Borrowing Program (Applies to Registrant Subsidiaries)

AEP subsidiaries use a corporate borrowing program to meet their short-term borrowing needs.  The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and direct borrowing from AEP.  The AEP Utility Money Pool operates in accordance with the terms and conditions of its agreement filed with the FERC.  The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of December 31, 2025 and 2024 are included in Advances to Affiliates and Advances from Affiliates, respectively, on the Registrant Subsidiaries’ balance sheets.  The Utility Money Pool participants’ money pool activity and corresponding authorized borrowing limits are described in the following tables:

Year Ended December 31, 2025:

	Maximum				Average				Net Loans to
	Borrowings		Maximum		Borrowings		Average		(Borrowings from)		Authorized
	from the		Loans to the		from the		Loans to the		the Utility Money		Short-term
	Utility		Utility		Utility		Utility		Pool as of		Borrowing
Company	Money Pool		Money Pool		Money Pool		Money Pool		December 31, 2025		Limit
	(in millions)
AEP Texas	$	468	$	486	$	159	$	94	$	(188)	$	750
AEPTCo	404		312		176		50		(140)		1,070		(a)
APCo	264		464		126		25		(192)		750
I&M	145		290		71		132		192		750
OPCo	271		166		120		82		(79)		600
PSO	505		391		183		166		(171)		750
SWEPCo	472		1,117		254		110		23		750

Year Ended December 31, 2024:

	Maximum				Average				Net Loans to
	Borrowings		Maximum		Borrowings		Average		(Borrowings from)		Authorized
	from the		Loans to the		from the		Loans to the		the Utility Money		Short-term
	Utility		Utility		Utility		Utility		Pool as of		Borrowing
Company	Money Pool		Money Pool		Money Pool		Money Pool		December 31, 2024		Limit
	(in millions)
AEP Texas	$	375	$	274	$	234	$	165	$	(285)	$	600
AEPTCo	313		332		72		138		(73)		820		(a)
APCo	400		132		103		30		(77)		750
I&M	136		8		59		4		(127)		500
OPCo	310		183		181		94		115		600
PSO	309		315		171		288		232		750
SWEPCo	362		59		250		57		(275)		750

(a)    Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.

The activity in the above tables does not include short-term lending activity of certain AEP nonutility subsidiaries. AEP Texas’ wholly-owned subsidiary, AEP Texas North Generation Company, LLC and SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC participate in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of December 31, 2025 and 2024 are included in Advances to Affiliates on each subsidiaries’ balance sheets. The Nonutility Money Pool participants’ money pool activity is described in the following tables:

Year Ended December 31, 2025:

	Maximum Loans		Average Loans		Loans to the Nonutility
	to the Nonutility		to the Nonutility		Money Pool as of
Company	Money Pool		Money Pool		December 31, 2025
	(in millions)
AEP Texas	$	7	$	7	$	7
SWEPCo	2		2		—

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Year Ended December 31, 2024:

	Maximum Loans		Average Loans		Loans to the Nonutility
	to the Nonutility		to the Nonutility		Money Pool as of
Company	Money Pool		Money Pool		December 31, 2024
	(in millions)
AEP Texas	$	7	$	7	$	7
SWEPCo	3		3		2

AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to and borrowings from AEP as of December 31, 2025 and 2024 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct financing activities with AEP and corresponding authorized borrowing limits are described in the following tables:

Year Ended December 31, 2025:

									Borrowings				Authorized
	Maximum		Maximum		Average		Average		from AEP		Loans to		Short-term
	Borrowings		Loans		Borrowings		Loans		as of		AEP as of		Borrowing
Company	from AEP		to AEP		from AEP		to AEP		December 31, 2025		December 31, 2025		Limit (a)
	(in millions)
AEPTCo Parent	$	107	$	153	$	18	$	54	$	—	$	70	$	—
SWTCo	2		—		2		—		2		—		50
Midwest Transmission Holdings	—		36		—		4		—		—		—

Year Ended December 31, 2024:

									Borrowings				Authorized
	Maximum		Maximum		Average		Average		from AEP		Loans to		Short-term
	Borrowings		Loans		Borrowings		Loans		as of		AEP as of		Borrowing
Company	from AEP		to AEP		from AEP		to AEP		December 31, 2024		December 31, 2024		Limit (a)
	(in millions)
AEPTCo Parent	$	49	$	149	$	15	$	57	$	—	$	20	$	—
SWTCo	2		—		2		—		2		—		50

(a)    Amount represents the authorized short-term borrowing limit from FERC or state regulatory agencies not otherwise included in the utility money pool above.

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool are summarized in the following table:

	Years Ended December 31,
	2025		2024		2023
Maximum Interest Rate	4.83	%	5.79	%	5.81	%
Minimum Interest Rate	3.40	%	4.74	%	4.66	%

The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized in the following table:

	Average Interest Rate for Funds Borrowed from the Utility Money Pool for the Years Ended December 31,						Average Interest Rate for Funds Loaned to the Utility Money Pool for the Years Ended December 31,
Company	2025		2024		2023		2025		2024		2023
AEP Texas	4.60	%	5.48	%	5.46	%	4.19	%	5.45	%	5.71	%
AEPTCo	4.48	%	5.51	%	5.41	%	4.44	%	5.50	%	5.56	%
APCo	4.50	%	5.51	%	5.54	%	4.46	%	5.41	%	5.54	%
I&M	4.69	%	5.40	%	5.14	%	4.12	%	5.44	%	5.57	%
OPCo	4.43	%	5.70	%	5.43	%	4.70	%	5.20	%	5.60	%
PSO	4.51	%	5.50	%	5.51	%	4.68	%	4.79	%	5.35	%
SWEPCo	4.67	%	5.41	%	5.34	%	4.29	%	4.78	%	5.72	%

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Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized in the following table:

		Maximum Interest Rate		Minimum Interest Rate		Average Interest Rate
Year Ended		for Funds Loaned to		for Funds Loaned to		for Funds Loaned to
December 31,	Company	the Nonutility Money Pool		the Nonutility Money Pool		the Nonutility Money Pool
2025	AEP Texas	4.76	%	3.89	%	4.52	%
2025	SWEPCo	4.76	%	4.62	%	4.69	%
2024	AEP Texas	5.79	%	4.74	%	5.46	%
2024	SWEPCo	5.79	%	4.74	%	5.45	%
2023	AEP Texas	5.81	%	4.66	%	5.54	%
2023	SWEPCo	5.81	%	4.66	%	5.56	%

AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table:

	Maximum		Minimum		Maximum		Minimum		Average		Average
	Interest Rate		Interest Rate		Interest Rate		Interest Rate		Interest Rate		Interest Rate
	for Funds		for Funds		for Funds		for Funds		for Funds		for Funds
Year Ended	Borrowed from		Borrowed from		Loaned to		Loaned to		Borrowed from		Loaned to
December 31,	AEP		AEP		AEP		AEP		AEP		AEP
2025	4.76	%	3.89	%	4.76	%	3.89	%	4.55	%	4.43	%
2024	5.79	%	4.66	%	5.79	%	4.66	%	5.53	%	5.56	%
2023	5.81	%	4.53	%	5.81	%	4.53	%	5.56	%	5.51	%

Interest expense related to short-term borrowing activities with the Utility Money Pool, Nonutility Money Pool and direct borrowing financing relationship are included in Interest Expense on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries incurred interest expense for all short-term borrowing activities as follows:

	Years Ended December 31,
Company	2025		2024		2023
	(in millions)
AEP Texas	$	5	$	7	$	11
AEPTCo	8		4		8
APCo	7		6		17
I&M	2		4		3
OPCo	4		4		10
PSO	6		9		2
SWEPCo	6		14		8

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Interest income related to short-term lending activities with the Utility Money Pool, Nonutility Money Pool and direct borrowing financing relationship are included in Interest Income, unless shown as Other Income due to materiality, on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries earned interest income for all short-term lending activities as follows:

	Years Ended December 31,
Company	2025		2024		2023
	(in millions)
AEP Texas	$	1	$	4	$	—
AEPTCo	4		11		7
APCo	1		2		1
I&M	3		—		2
OPCo	1		3		—
PSO	2		1		2
SWEPCo	3		—		—

Credit Facilities

See “Letters of Credit” section of Note 6 for additional information.

Securitized Accounts Receivables – AEP Credit (Applies to AEP)

AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries.  These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections.

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.

Accounts receivable information for AEP Credit was as follows:

	Years Ended December 31,
	2025			2024			2023
	(dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable	4.46		%	5.39		%	5.33		%
Net Uncollectible Accounts Receivable Written Off	$	34		$	29		$	31

	December 31,
	2025		2024
	(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts	$	1,230	$	1,117
Short-term – Securitized Debt of Receivables	900		900
Delinquent Securitized Accounts Receivable	66		56
Bad Debt Reserves Related to Securitization	42		45
Unbilled Receivables Related to Securitization	368		336

AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due.

Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries, except AEP Texas and AEPTCo)

Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable.  The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder.

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The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement were:

	December 31,
Company	2025		2024
	(in millions)
APCo	$	203	$	193
I&M	175		161
OPCo	501		471
PSO	140		111
SWEPCo	169		154

The fees paid to AEP Credit for customer accounts receivable sold were:

	Years Ended December 31,
Company	2025		2024		2023
	(in millions)
APCo	$	14	$	16	$	17
I&M	15		15		16
OPCo	30		30		30
PSO	13		14		15
SWEPCo	15		18		19

The proceeds on the sale of receivables to AEP Credit were:

	Years Ended December 31,
Company	2025		2024		2023
	(in millions)
APCo	$	1,992	$	1,954	$	1,820
I&M	2,415		2,105		2,055
OPCo	3,332		3,198		3,339
PSO	1,926		1,781		1,945
SWEPCo	1,853		1,838		1,866

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16.  STOCK-BASED COMPENSATION

The disclosures in this note apply to AEP only. The impact of AEP’s share-based compensation plans is insignificant to the financial statements of the Registrant Subsidiaries.

AEP’s long-term incentive plan available for eligible employees and directors, the American Electric Power System 2015 Long-Term Incentive Plan (2015 LTIP), was replaced prospectively for new grants by the American Electric Power System 2024 Long-Term Incentive Plan (2024 LTIP) effective in April 2024. The 2024 LTIP provides for a maximum of 10 million AEP common shares to be available for grant to eligible employees and directors. As of December 31, 2025, 8,909,934 shares remained available for issuance under the 2024 LTIP. No new awards may be granted under the 2015 LTIP. To the extent the issuance of a share is subject to an outstanding award under the 2015 LTIP, the issuance of that share will take place under the 2015 LTIP. Awards granted under the 2024 LTIP may be made in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards. All types of shares issued under the 2024 LTIP including stock options, stock appreciation rights, restricted stock units and performance shares reduce the shares remaining available for grants at a rate of 1 to 1. Cash settled awards do not reduce the number of shares remaining available under the 2024 LTIP. The following sections provide further information regarding each type of stock-based compensation award granted under these plans.

Performance Shares

Performance shares are settled in AEP common stock and reduce the aggregate share authorization. The number of performance shares held at the end of the three-year performance period is multiplied by the performance score for such period to determine the actual number of performance shares that participants realize. The performance score can range from 0% to 200% and is determined at the end of the performance period based on performance measures, which include both performance and market conditions, established for each grant at the beginning of the performance period by the Human Resources Committee of AEP’s Board of Directors (HR Committee).

Certain employees must satisfy a minimum stock ownership requirement. If those employees have not met their stock ownership requirement, their performance shares are mandatorily deferred upon vesting into AEP career shares to the extent needed to meet their stock ownership requirement.  AEP career shares are a form of non-qualified deferred compensation that has a value equivalent to a share of AEP common stock but cannot be sold or transferred and do not have voting rights.  AEP career shares are settled in AEP common stock after the participant’s termination of employment.

AEP career shares are recorded in Paid-in Capital on the balance sheets. Amounts equivalent to cash dividends on both performance shares and AEP career shares accrue as additional shares.  Management records compensation cost for performance shares over an approximately three-year vesting period. Performance shares are recorded as temporary equity on the balance sheets until the vesting date and compensation cost is calculated at fair value based on the performance metrics for each grant. Performance shares granted in 2025 have two performance metrics: (a) three-year cumulative operating earnings per-share with a 50% weight and (b) relative total shareholder return with a 50% weight. Performance shares granted in 2024 and 2023 have three performance metrics: (a) three-year cumulative operating earnings per-share with a 50% weight, (b) relative total shareholder return with a 40% weight and (c) generation capacity additions, which focused on additions that maintain reliability for 2024 grants, and renewable generation additions for 2023 grants. The three-year cumulative operating earnings per-share and generation capacity additions metrics are adjusted quarterly for changes in performance relative to the metric approved by the HR Committee. The total shareholder return metric is measured relative to a peer group of similar companies and is based on a third-party Monte Carlo valuation. The value related to this metric does not change over the three-year vesting period.

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The HR Committee awarded performance shares and reinvested dividends on outstanding performance shares and AEP career shares as follows:

	Years Ended December 31,
Performance Shares	2025		2024		2023
Awarded Shares (in thousands)	498		441		487
Weighted-Average Share Fair Value at Grant Date	$	123.42	$	99.76	$	98.63
Vesting Period (in years)	3		3		3

Performance Shares and AEP Career Shares (Reinvested Dividends Portion)	Years Ended December 31,
	2025		2024		2023
Awarded Shares (in thousands)	53		66		81
Weighted-Average Fair Value at Grant Date	$	107.71	$	91.75	$	82.02
Vesting Period (in years)	(a)		(a)		(a)

(a)The vesting period for the reinvested dividends on performance shares is equal to the remaining life of the related performance shares.  Dividends on AEP career shares vest immediately when the dividend is awarded but are not settled in AEP common stock until after the participant’s AEP employment ends.

Performance scores and final awards are determined and approved by the HR Committee in accordance with the pre-established performance measures within approximately two months after the end of the performance period.

The performance scores and shares earned for the three-year periods were as follows:

	Years Ended December 31,
Performance Shares	2025 (b)		2024		2023
Performance Score	137.1	%	109.8	%	106.1	%
Performance Shares Earned	477,932		477,487		540,863
Performance Shares Mandatorily Deferred as AEP Career Shares	12,337		39,172		70,377
Performance Shares Voluntarily Deferred into the Incentive Compensation Deferral Program	19,503		21,245		22,716
Performance Shares to be Settled (a)	446,092		417,070		447,770

(a)Performance shares settled in AEP common stock in the quarter following the end of the year shown.

(b)Performance shares earned, deferred and settled were calculated based on the estimated performance score.

The settlements were as follows:

	Years Ended December 31,
Performance Shares and AEP Career Shares	2025		2024		2023
	(in millions)
AEP Common Stock Settlements for Performance Shares	$	45	$	38	$	42
AEP Common Stock Settlements for Career Share Distributions	13		8		8

A summary of the status of AEP’s nonvested Performance Shares as of December 31, 2025 and changes during the year ended December 31, 2025 were as follows:

Nonvested Performance Shares	Shares	Weighted Average Grant Date Fair Value
	(in thousands)
Nonvested as of January 1, 2025	778	$	100.97
Awarded	498	123.42
Dividends	41	107.80
Vested (a)	(353)	100.41
Forfeited	(157)	106.44
Nonvested as of December 31, 2025	807	114.36

(a)The vested Performance Shares will be converted to an estimated 446 thousand shares based on the closing share price on the day before settlement.

308

Monte Carlo Valuation

AEP engages a third-party for a Monte Carlo valuation to calculate the fair value of the total shareholder return metric for the performance shares awarded during and after 2017. The valuations use a lattice model and the expected volatility assumptions used were the historical volatilities for AEP and the members of their peer group. The assumptions used in the Monte Carlo valuations were as follows:

	Years Ended December 31,
Assumptions	2025		2024		2023
Valuation Period (in years) (a)	2.86		2.85		2.87
Expected Volatility Minimum	18.86	%	18.79	%	21.23	%
Expected Volatility Maximum	46.96	%	33.29	%	39.00	%
Expected Volatility Average	23.26	%	22.34	%	25.35	%
Dividend Rate (b)	—	%	—	%	—	%
Risk Free Rate	4.28	%	4.43	%	4.32	%

(a)Period from award date to vesting date.

(b)Equivalent to reinvesting dividends.

Restricted Stock Units and Unrestricted Shares

The HR Committee grants restricted stock units (RSUs), which generally vest, subject to the participant’s continued AEP employment, over at least three years in approximately equal annual increments.  The RSUs accrue dividends as additional RSUs. The additional RSUs granted as dividends vest on the same date, subject to the participant’s continued AEP employment, as the underlying RSUs. RSUs are converted into shares of AEP common stock upon vesting. The RSU compensation cost is measured at fair value on the grant date and recorded over the vesting period.  Fair value is determined by multiplying the number of RSUs granted by the grant date market closing price.  The maximum contractual term of outstanding RSUs is approximately 60 months from the grant date. The HR Committee also occasionally grants unrestricted shares that are immediately vested and paid.

The HR Committee awarded RSUs, including additional units awarded as dividends, and unrestricted shares as follows:

	Years Ended December 31,
RSUs and Unrestricted Shares	2025		2024		2023
Awarded RSUs and Granted Unrestricted Shares (in thousands)	440		417		268
Weighted-Average Grant Date Fair Value	$	105.04	$	87.85	$	88.52

The total fair value and total intrinsic value of RSUs vested and unrestricted shares granted were as follows:

	Years Ended December 31,
RSUs and Unrestricted Shares	2025		2024		2023
	(in millions)
Fair Value of RSUs Vested and Unrestricted Shares Granted	$	22	$	26	$	19
Intrinsic Value of RSUs Vested and Unrestricted Shares Granted (a)	26		27		19

(a)Intrinsic value is calculated as market price at the vesting date or, for unrestricted shares, the grant date.

A summary of the status of AEP’s nonvested RSUs as of December 31, 2025 and changes during the year ended December 31, 2025 were as follows:

Nonvested RSUs	Shares/Units	Weighted Average Grant Date Fair Value
	(in thousands)
Nonvested as of January 1, 2025	477	$	88.37
Awarded, Including Unrestricted Shares	440	105.04
Vested, Including Unrestricted Shares	(243)	89.63
Forfeited	(76)	90.10
Nonvested as of December 31, 2025	598	100.13

The total aggregate intrinsic value of nonvested RSUs as of December 31, 2025 was $69 million and the weighted-average remaining contractual life was 2.1 years.

309

Other Stock-Based Plans

AEP also has a Stock Unit Accumulation Plan (SUAP) for Non-Employee Directors providing each non-employee director with AEP stock units as a substantial portion of the compensation for their services as a director.  The number of stock units provided is based on the closing price of AEP common stock on the last trading day of the quarter for which the stock units were earned.  Amounts equivalent to cash dividends on the stock units accrue as additional AEP stock units.  The stock units granted to non-employee directors are fully vested on their grant date.  Stock units are paid to directors upon termination of their board service or up to 10 years later if the participant so elects.

Management records compensation costs for stock units when the units are awarded.

After five years of service on the Board of Directors, non-employee directors receive subsequent AEP stock units as contributions to an AEP stock fund under the Stock Unit Accumulation Plan. Such amounts may be exchanged into other market-based investment options available to employees that participate in AEP’s Incentive Compensation Deferral Plan. These balances are paid in cash upon termination of board service or up to 10 years later if the participant so elects.

AEP common stock provided for stock unit distributions were immaterial for the years ended December 31, 2025, 2024 and 2023.

The Board of Directors awarded stock units, including units awarded for dividends, as follows:

	Years Ended December 31,
Stock Unit Accumulation Plan for Non-Employee Directors	2025		2024		2023
Awarded Units (in thousands)	16		19		20
Weighted-Average Grant Date Fair Value	$	109.25	$	91.42	$	82.14

Share-based Compensation Plans

The compensation cost for share-based payment arrangements, the actual tax benefit from the tax deductions for compensation cost recognized in income and the total compensation cost capitalized were as follows:

	Years Ended December 31,
Share-based Compensation Plans	2025		2024		2023
	(in millions)
Compensation Cost for Share-based Payment Arrangements (a)	$	53	$	53	$	51
Actual Tax Benefit	8		7		6
Total Compensation Cost Capitalized	17		14		15

(a)Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on the statements of income.

As of December 31, 2025, there was $95 million of total unrecognized compensation cost related to unvested share-based compensation arrangements granted under the 2015 LTIP and the 2024 LTIP. Unrecognized compensation cost related to unvested share-based arrangements will change as the fair value of performance shares is adjusted each period and as forfeitures for all award types are realized.  AEP’s unrecognized compensation cost will be recognized over a weighted-average period of 1.6 years.

Under the 2015 LTIP and 2024 LTIP, AEP is permitted to use authorized but unissued shares, treasury shares, shares acquired in the open market specifically for distribution under these plans, or any combination thereof to fulfill share commitments. AEP’s current practice is generally to use authorized but unissued shares to fulfill share commitments. The number of shares used to fulfill share commitments is generally reduced to offset tax withholding obligations.

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17.  RELATED PARTY TRANSACTIONS

The disclosures in this note apply to all Registrant Subsidiaries unless indicated otherwise.

For other related party transactions, also see “Income Taxes and Investment and Production Tax Credits” section of Note 1, “Corporate Borrowing Program” and “Securitized Accounts Receivables – AEP Credit” sections of Note 15 and “Gigawatt AI” section of Note 18.

Intercompany Billings

The Registrant Subsidiaries and other AEP subsidiaries perform certain utility services for each other when necessary or practical.  The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies.  The billings for services are made at cost and include no compensation for the use of equity capital.

Power Coordination Agreement (Applies to all Registrant Subsidiaries except AEP Texas and AEPTCo)

Effective January 1, 2014, the FERC approved the PCA. Under the PCA, APCo, I&M, KPCo and WPCo are individually responsible for planning their respective capacity obligations. The PCA allows, but does not obligate, APCo, I&M, KPCo and WPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective Off-system Sales and purchase activities.

AEPSC conducts power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M, KPCo, PSO, SWEPCo and WPCo. Certain power and natural gas risk management activities for APCo, I&M, KPCo and WPCo are allocated based on the four member companies’ respective equity positions, while power and natural gas risk management activities for PSO and SWEPCo are allocated based on the Operating Agreement. AEPSC conducts only gasoline, diesel fuel, energy procurement and risk management activities on OPCo’s behalf.

Joint License Agreement (Applies to all Registrant Subsidiaries except AEP Texas and SWEPCo)

AEPTCo entered into a 50-year joint license agreement with APCo, I&M, KPCo, OPCo and PSO, respectively, allowing either party to occupy the granting party’s facilities or real property. In addition, AEPTCo entered into a 5-year joint license agreement with APCo and WPCo. After the expiration of these agreements, the term shall automatically renew for successive one-year terms unless either party provides notice. The joint license billing provides compensation to the granting party for the cost of carrying assets, including depreciation expense, property taxes, interest expense, return on equity and income taxes. AEPTCo recorded the costs related to these agreements in Other Operation expense on the statements of income. APCo, I&M, KPCo, OPCo, PSO and WPCo recorded income related to these agreements in Sales to AEP Affiliates on the statements of income. The impact of the joint license agreement for the years ended December 31, 2025, 2024 and 2023 was not material.

Unit Power Agreements (Applies to 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 as a demand charge for the right to receive such power (and as 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). I&M’s direct purchases from AEGCo were $268 million, $209 million and $181 million for the years ended December 31, 2025, 2024 and 2023, respectively. These direct purchases are presented as Purchased Electricity from AEP Affiliates on I&M’s statements of income.

Ohio Auctions (Applies to OPCo)

In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015. AEP Energy and AEPEP participate in the auction process and have been awarded tranches of OPCo’s SSO load. OPCo’s auction purchases were $65 million, $98 million and $87 million for the years ended December 31, 2025, 2024 and 2023, respectively. These direct purchases are presented as Purchased Electricity from AEP Affiliates on OPCo’s statements of income.

311

Sales and Purchases of Property

Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property.  There were no gains or losses recorded on the transactions and the net book value of all sales and purchases for the years ended December 31, 2025, 2024 and 2023 were not material. These sales and purchases are recorded in Property, Plant and Equipment on the balance sheets.

Charitable Contributions to AEP Foundation

The AEP Foundation is funded by AEP and its utility operating units. The AEP Foundation provides a permanent, ongoing resource for charitable initiatives and multi-year commitments in the communities served by AEP and initiatives outside of AEP’s 11-state service area. The AEP Foundation is not consolidated by AEP. Charitable contributions to the AEP Foundation were not made in 2024 or 2023. Charitable contributions were recorded in Other Operation expenses on the statements of income as follows for the year ended December 31, 2025:

	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Contributions to AEP Foundation	$	10	$	1	$	2	$	2	$	1	$	1	$	1	$	1

Other Related Party Contributions

For the year ended December 31, 2023, AEP made contributions of $80 thousand to Clean Affordable Reliable Coalition (CARE), a 501(c)(6) organization established to encourage communication, discussion and concerted action related to tax policy associated with clean, affordable and reliable power initiatives. These contributions were made in the ordinary course of business. AEP was a member of CARE and provided the organization its primary financial support. In addition, an employee of AEP served as a board member of the organization during 2023. AEP management has determined these contributions are Related Party transactions under ASC 850 based on AEP’s ability to significantly influence the management and operating policies of CARE. AEP made no contributions to CARE in 2024 or 2025.

Beginning in August 2024, an officer of AEP also served as a member of the board of directors of a company that is a vendor of certain AEP subsidiaries. From August 2024 through December 2024, AEP purchased $44 million of distribution and transmission infrastructure services from the related party vendor in the ordinary course of business. Of this amount, $25 million was incurred by AEP Texas and $13 million was incurred by PSO. The amounts incurred by the remaining Registrant Subsidiaries were not significant. No amounts were incurred in 2025.

I&M Barging, Urea Transloading and Other Services (Applies to APCo and I&M)

I&M provides barging, urea transloading and other transportation services to affiliates.  Urea is a chemical used to control NOx emissions at certain generation plants in the AEP System.  I&M recorded revenues from barging, transloading and other services in Other Revenues – Affiliated on the statements of income.  The affiliated companies recorded these costs paid to I&M as fuel expenses or other operation expenses.  The amounts of affiliated expenses were:

	Years Ended December 31,
Company	2025		2024		2023
	(in millions)
AEGCo	$	15	$	10	$	9
APCo	36		47		39
WPCo	7		8		11

312

Competitive Contracted Renewables PPAs (Applies to I&M, OPCo and SWEPCo)

Prior to acquisition, Fowler Ridge 2 had PPAs with I&M and OPCo and Flat Ridge 2 had a PPA with SWEPCo for a portion of their energy production. The amounts of purchased electricity by I&M and OPCo were $8 million and $16 million, respectively, in 2023. See Note 7 - Acquisitions, Dispositions and Impairments for additional information related to the disposal of the 50% interests in Fowler Ridge 2 which was included in the August 2023 sale of the Competitive Contracted Renewables Portfolio.

Transmission Service Charges

The AEP East Companies are parties to the TA, which defines how transmission costs through the PJM OATT are allocated among the AEP East Companies on a 12-month average coincident peak basis. Additional costs for transmission services provided by AEPTCo and other transmission affiliates are billed to AEP East Companies through the PJM OATT. PSO, SWEPCo and AEPSC are parties to the TCA in connection with the operation of the transmission assets of PSO and SWEPCo.  Under the TCA, AEPSC is responsible for monitoring the reliability of their transmission systems and administering the OATT.  Additional costs for transmission services provided by AEPTCo and other transmission affiliates are billed to PSO and SWEPCo through the SPP OATT. Pursuant to an order from the PUCT, ETT bills AEP Texas for its ERCOT wholesale transmission services.

The charges discussed above are recorded in Other Operation expenses on the statements of income. AEPTCo recorded affiliated transmission revenues in Sales to AEP Affiliates on the statements of income. Refer to the Affiliated Revenues section below for amounts related to these transactions.

The following table shows the net transmission service charges recorded by the Registrant Subsidiaries:

	Years Ended December 31,
Company	2025		2024		2023
	(in millions)
AEP Texas	$	31	$	31	$	29
APCo	440		381		365
I&M	269		253		226
OPCo	789		696		665
PSO	171		127		100
SWEPCo	84		65		49

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Affiliated Revenues

The tables below represent revenues from affiliates, net of respective provisions for refund, by type of revenue for the Registrant Subsidiaries. Related party revenues are shown in Sales to AEP Affiliates, Provision for Refund - Affiliated and Other Revenues - Affiliated, respectively, on the Registrant Subsidiaries’ statements of income. 

Related Party Revenues	AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Year Ended December 31, 2025
Direct Sales to East Affiliates	$	—	$	—	$	165	$	—	$	—	$	—	$	—
Direct Sales to West Affiliates	—		—		—		—		—		4		—
Transmission Revenues	—		1,848		99		(1)		13		—		81
Other Revenues	5		21		15		70		32		5		2
Total Affiliated Revenues	$	5	$	1,869	$	279	$	69	$	45	$	9	$	83

Related Party Revenues	AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Year Ended December 31, 2024
Direct Sales to East Affiliates	$	—	$	—	$	159	$	—	$	—	$	—	$	—
Transmission Revenues	—		1,491		79		(9)		(7)		—		61
Other Revenues	5		21		10		75		30		7		1
Total Affiliated Revenues	$	5	$	1,512	$	248	$	66	$	23	$	7	$	62

Related Party Revenues	AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Year Ended December 31, 2023
Direct Sales to East Affiliates	$	—	$	—	$	159	$	—	$	—	$	—	$	—
Transmission Revenues	—		1,304		71		(11)		3		—		45
Barging, Urea Transloading and Other Transportation Services	—		—		—		59		—		—		—
Other Revenues	5		13		9		9		28		1		2
Total Affiliated Revenues	$	5	$	1,317	$	239	$	57	$	31	$	1	$	47

314

18.  VARIABLE INTEREST ENTITIES AND EQUITY METHOD INVESTMENTS

The disclosures in this note apply to all Registrants unless indicated otherwise.

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a variable interest in a VIE.  A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently. 

AEP holds ownership interests in businesses with varying ownership structures. Partnership interests and other variable interests are evaluated to determine if each entity is a VIE, and if so, whether or not the VIE should be consolidated into AEP’s financial statements. AEP has not provided material financial or other support that was not previously contractually required to any of its consolidated VIEs. AEP’s interests in nonconsolidated VIEs are accounted for under the equity method of accounting.

Consolidated Variable Interests Entities

Sabine (Applies to AEP and SWEPCo)

Sabine is a mining operator whose purpose was to provide mining services to SWEPCo’s Pirkey Plant until its retirement in March 2023. Sabine’s post-production operations primarily consist of reclamation and other land-related activities. The terms of these services are governed by a lignite mining agreement between SWEPCo and Sabine.  SWEPCo has no equity investment in Sabine but is Sabine’s only customer.  SWEPCo guarantees the debt obligations and lease obligations of Sabine.  Under the terms of the note agreements with Sabine’s creditors, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo.  The creditors of Sabine have no recourse to any AEP entity other than SWEPCo.  Under the provisions of the lignite mining agreement, SWEPCo is required to pay an amount equal to Sabine’s operating costs plus a management fee and SWEPCo holds an option agreement to purchase Sabine, which SWEPCo exercised in 2023. As a result, SWEPCo will take direct control over reclamation activities in October 2026. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine.  See the tables below for the classification of Sabine’s assets and liabilities on SWEPCo’s balance sheets.

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $155 million.  Since SWEPCo uses self-bonding, the guarantee commits SWEPCo to complete the reclamation, in the event, Sabine does not complete the work.  This guarantee ends upon completion of reclamation activities expected by 2037 with an estimated cost of $68 million.  Actual costs may vary due to inflation and changes in reclamation scope.  SWEPCo recovers these costs through its fuel clauses. As of December 31, 2025, SWEPCo has recorded an ARO of $66 million and has paid or accrued $113 million for reclamation costs billed by Sabine. To date, SWEPCo has collected $102 million from customers for reclamation costs and expects to collect an additional $77 million recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets.

DCC Fuel (Applies to AEP and I&M)

I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.  DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions.  Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt.  Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M.  Payments on the leases for the years ended December 31, 2025, 2024 and 2023 were $119 million, $111 million and $97 million, respectively.  The leases qualify as finance leases because title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months.  Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel.  The finance leases are eliminated upon consolidation. See the tables below for the classification of DCC Fuel’s assets and liabilities on I&M’s balance sheets.

315

Restoration Funding (Applies to AEP and AEP Texas)

Restoration Funding was formed for the sole purpose of issuing and servicing securitization bonds related to storm restoration of AEP Texas’ distribution system primarily due to damage caused by Hurricane Harvey. Management concluded that AEP Texas is the primary beneficiary of Restoration Funding because AEP Texas has the power to direct the most significant activities of the VIE and AEP Texas’ equity interest could potentially be significant. Therefore, AEP Texas is required to consolidate Restoration Funding. As of December 31, 2025 and 2024, $25 million and $24 million of the securitized bonds were included in Long-term Debt Due Within One Year - Nonaffiliated, respectively, and $78 million and $102 million were included in Long-term Debt - Nonaffiliated, respectively, on the balance sheets. Restoration Funding’s securitized assets were $94 million and $117 million as of December 31, 2025 and 2024, respectively, which are presented separately on the face of the balance sheets.

The securitized restoration assets represent the right to impose and collect Texas storm restoration costs from customers receiving electric transmission or distribution service from AEP Texas under-recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to AEP Texas or any other AEP entity. AEP Texas acts as the servicer for Restoration Funding’s securitized assets and remits all related amounts collected from customers to Restoration Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Restoration Funding’s assets and liabilities on the balance sheets.

Appalachian Consumer Rate Relief Funding (Applies to AEP and APCo)

Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo’s under-recovered ENEC deferral balance.  Management concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo’s equity interest could potentially be significant.  Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding.  As of December 31, 2025 and 2024, $30 million and $28 million of the securitized bonds were included in Long-term Debt Due Within One Year - Nonaffiliated, respectively, and $62 million and $91 million were included in Long-term Debt - Nonaffiliated, respectively, on the balance sheets.  Appalachian Consumer Rate Relief Funding’s securitized assets were $78 million and $106 million as of December 31, 2025 and 2024, respectively, which are presented separately on the face of the balance sheets.

The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC.  In November 2013, securitization bonds were issued.  The securitization bonds are payable only from and secured by the securitized assets.  The bondholders have no recourse to APCo or any other AEP entity.  APCo acts as the servicer for Appalachian Consumer Rate Relief Funding’s securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s balance sheets.

Storm Recovery Funding (Applies to AEP and SWEPCo)

Storm Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to storm recovery primarily related to SWEPCo’s distribution system. Management concluded that SWEPCo is the primary beneficiary of Storm Recovery Funding because SWEPCo has the power to direct the most significant activities of the VIE and SWEPCo’s equity interest could potentially be significant. Therefore, SWEPCo is required to consolidate Storm Recovery Funding. As of December 31, 2025 and 2024, $17 million and $23 million of the securitized bonds were included in Long-term Debt Due Within One Year - Nonaffiliated, respectively, and $304 million and $309 million were included in Long-term Debt - Nonaffiliated, respectively, on the balance sheets. Storm Recovery Funding’s securitized assets were $315 million and $331 million as of December 31, 2025 and 2024, respectively, which are presented separately on the face of the balance sheets.

The securitized assets represent the right to impose and collect SWEPCo storm recovery charges from SWEPCo’s Louisiana jurisdictional customers. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to SWEPCo or any other AEP entity. SWEPCo acts as the servicer for Storm Recovery Funding’s securitized assets and remits all related amounts collected from customers to Storm Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Storm Recovery Funding’s assets and liabilities on the balance sheets.

316

Cost Recovery Funding (Applies to AEP)

In June 2025, Cost Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to plant retirement costs, deferred storm costs related to 2020, 2021, 2022 and 2023 major storms, deferred purchased power expenses, under-recovered purchased power rider costs and issuance-related expenses, including KPSC advisor expenses. Management concluded that KPCo is the primary beneficiary of Cost Recovery Funding because KPCo has the power to direct the most significant activities of the VIE and KPCo’s equity interest could potentially be significant. Therefore, KPCo is required to consolidate Cost Recovery Funding. As of December 31, 2025, $16 million of the securitized bonds was included in Long-term Debt Due Within One Year and $453 million was included in Long-term Debt on the balance sheet. Cost Recovery Funding’s securitized assets were $462 million as of December 31, 2025, which was presented separately on the face of the balance sheet.

The securitized assets represent the right to impose and collect KPCo recovery charges from KPCo’s customers. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to KPCo or any other AEP entity. KPCo acts as the servicer for Cost Recovery Funding’s securitized assets and remits all related amounts collected from customers to Cost Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Cost Recovery Funding’s assets and liabilities on the balance sheet.

AEP Credit (Applies to AEP)

AEP Credit is a wholly-owned subsidiary of Parent. AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements. AEP provides a minimum of 5% equity and up to 35% of AEP Credit’s short-term borrowing needs in excess of third-party financings. Any third-party financing of AEP Credit only has recourse to the receivables securitized for such financing. Based on AEP’s control of AEP Credit, management concluded that AEP is the primary beneficiary and is required to consolidate AEP Credit. See the tables below for the classification of AEP Credit’s assets and liabilities on the balance sheets. See “Securitized Accounts Receivables - AEP Credit” section of Note 15.

EIS (Applies to AEP)

AEP’s subsidiaries participate in one protected cell of EIS for seven lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third-parties access to this insurance. AEP’s subsidiaries and any allowed third-parties share in the insurance coverage, premiums and risk of loss from claims. Based on AEP’s control and the structure of the protected cell of EIS, management concluded that AEP is the primary beneficiary of the protected cell and is required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the years ended December 31, 2025, 2024 and 2023 was $39 million, $37 million and $34 million, respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets.  The amount reported as equity is the protected cell’s policy holders’ surplus.

Transource Energy (Applies to AEP)

Transource Energy was formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. AEP has an 86.5% equity and voting ownership interest and the remaining 13.5% interest is held by a single third-party owner. Management concluded that Transource Energy is a VIE and that AEP is the primary beneficiary because AEP has the power to direct the most significant activities of the entity and AEP’s equity interest could potentially be significant. Therefore, AEP is required to consolidate Transource Energy. Transource Energy’s activities consist of the development, construction and operation of FERC-regulated transmission assets in Missouri, West Virginia, Pennsylvania, Maryland and Oklahoma. Transource Energy has a credit facility agreement where borrowings are loaned through intercompany lending agreements to its subsidiaries. The creditor to the agreement has no recourse to the general credit of AEP. Transource Energy’s credit facility agreement contains certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%. See the tables below for the classification of Transource Energy’s assets and liabilities on the balance sheets.

317

The balances below represent the assets and liabilities of AEP’s consolidated VIEs. These balances include intercompany transactions that are eliminated upon consolidation.

	December 31, 2025
	Consolidated VIEs
	SWEPCo Sabine		I&M DCC Fuel		AEP Texas Restoration Funding			APCo Appalachian Consumer Rate Relief Funding			SWEPCo Storm Recovery Funding		KPCo Cost Recovery Funding			AEP Credit		Protected Cell of EIS		Transource Energy
	(in millions)
ASSETS
Current Assets	$	1	$	118	$	18		$	18		$	17	$	24		$	1,232	$	223	$	45
Net Property, Plant and Equipment	—		227		—			—			—		—			—		—		658
Other Noncurrent Assets	80		118		98		(a)	79		(b)	312		462		(c)	10		—		4
Total Assets	$	81	$	463	$	116		$	97		$	329	$	486		$	1,242	$	223	$	707
LIABILITIES AND EQUITY
Current Liabilities	$	15	$	118	$	31		$	31		$	23	$	30		$	1,176	$	56	$	50
Noncurrent Liabilities	66		345		84			64			304		454			1		102		298
Equity	—		—		1			2			2		2			65		65		359
Total Liabilities and Equity	$	81	$	463	$	116		$	97		$	329	$	486		$	1,242	$	223	$	707

(a)Includes an intercompany item eliminated in consolidation of $4 million.

(b)Includes an intercompany item eliminated in consolidation of $1 million.

(c)Includes an intercompany item eliminated in consolidation of $16 million.

	December 31, 2024
	Consolidated VIEs
	SWEPCo Sabine		I&M DCC Fuel		AEP Texas Restoration Funding			APCo Appalachian Consumer Rate Relief Funding			SWEPCo Storm Recovery Funding		AEP Credit		Protected Cell of EIS		Transource Energy
	(in millions)
ASSETS
Current Assets	$	6	$	79	$	21		$	14		$	3	$	1,118	$	219	$	40
Net Property, Plant and Equipment	—		132		—			—			—		—		—		598
Other Noncurrent Assets	111		64		122		(a)	110		(b)	332		11		—		4
Total Assets	$	117	$	275	$	143		$	124		$	335	$	1,129	$	219	$	642
LIABILITIES AND EQUITY
Current Liabilities	$	20	$	79	$	31		$	31		$	24	$	1,069	$	55	$	57
Noncurrent Liabilities	96		196		111			91			309		1		96		274
Equity	1		—		1			2			2		59		68		311
Total Liabilities and Equity	$	117	$	275	$	143		$	124		$	335	$	1,129	$	219	$	642

(a)Includes an intercompany item eliminated in consolidation of $5 million.

(b)Includes an intercompany item eliminated in consolidation of $1 million.

318

Non-Consolidated Significant Variable Interests - AEP

AEPSC (Applies to Registrant Subsidiaries)

AEPSC, a wholly-owned subsidiary of Parent, is consolidated by AEP. Parent is the sole equity owner of AEPSC and controls the activities of AEPSC. AEPSC provides certain managerial and professional services to AEP’s subsidiaries.  The costs of the services are based on a direct-charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost.  AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered.  AEPSC finances its operations through cost reimbursement from other AEP subsidiaries.  There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business.  AEPSC and its billings are subject to regulation by the FERC.  AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations.  AEP subsidiaries are considered to have a significant variable interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure.  However, AEP subsidiaries do not have control over AEPSC.  In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.

Total AEPSC billings to the Registrant Subsidiaries were as follows:

	Years Ended December 31,
Company	2025		2024		2023
	(in millions)
AEP Texas	$	278	$	243	$	229
AEPTCo	319		290		270
APCo	352		335		325
I&M	189		188		178
OPCo	282		283		270
PSO	176		157		139
SWEPCo	207		194		185

The carrying amount and classification of variable interest in AEPSC’s accounts payable were as follows:

	December 31,
	2025				2024
Company	As Reported on the Balance Sheet		Maximum Exposure		As Reported on the Balance Sheet		Maximum Exposure
	(in millions)
AEP Texas	$	51	$	51	$	26	$	26
AEPTCo	54		54		29		29
APCo	52		52		36		36
I&M	32		32		25		25
OPCo	47		47		35		35
PSO	29		29		19		19
SWEPCo	32		32		22		22

AEGCo (Applies to I&M)

AEGCo, a wholly-owned subsidiary of Parent, is consolidated by AEP.  AEGCo owns a 50% ownership interest in Rockport Plant, Units 1 and 2. AEGCo sells its portion of the output from the Rockport Plant to I&M.  AEP has agreed to provide AEGCo with the funds necessary to satisfy all the debt obligations of AEGCo.  I&M is considered to have a significant variable interest in AEGCo due to these transactions.  I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations.  In the event AEGCo requires financing or other support outside the billings to I&M, it would be provided by AEP. AEGCo’s billings to I&M for the years ended December 31, 2025, 2024 and 2023 were $268 million, $209 million and $181 million, respectively. The carrying amounts of I&M’s liabilities associated with AEGCo as of December 31, 2025 and 2024 were $19 million and $14 million, respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liabilities.

319

AEP Development Services (Applies to OPCo)

AEP Development Services, LLC (Devco), a wholly-owned subsidiary of Parent, is consolidated by AEP. Devco was formed for the purpose of developing, constructing and installing energy projects for the regulated operating companies across the AEP system. In the fourth quarter of 2024, Devco executed a purchase agreement with Bloom Energy, acquiring 100 MWs of solid oxide fuel cells. Devco contemporaneously executed an affiliated services agreement with OPCo to establish the terms and conditions for Devco to design, procure, construct and ultimately sell customer-sited, behind-the-meter fuel cell generation facilities to OPCo. Sales of fuel cell generation facilities will be made for OPCo to meet its obligations arising from bilateral customer-sited renewable energy resource agreements (CSRERAs) entered with its commercial customers. Sales are generally expected to close when a fuel cell generation facility is mechanically complete and will be sold at net book value plus reimbursement for the costs of Devco’s services. OPCo will own and operate the fuel cell generation facilities, and sell power produced by them to its customers under the terms of the applicable CSRERAs.

Devco is a VIE because its operations and activities, including the initial 100 MWs purchase of fuel cells from Bloom Energy, are entirely financed by Parent through borrowings from the Nonutility Money Pool. Parent controls the significant activities of Devco and is exposed to its potential losses to the extent sales of completed fuel cell generation facilities to OPCo are insufficient to cover its costs of operations.  AEP intends to recover its investment through the fulfillment of contractual commitments to deploy and install fuel cells to provide electricity service to customers. Based on AEP’s control of Devco, management concluded that AEP is the primary beneficiary and is required to consolidate Devco. In addition, OPCo has a noncontrolling variable interest in Devco because of the pricing structure for the sales of fuel cell generation facilities. As of December 31, 2025 and 2024, the amounts of CWIP were $480 million and $457 million, respectively, and borrowings from the Nonutility Money Pool were $485 million and $456 million, respectively, on the balance sheets.

Non-Consolidated Significant Variable Interests - Registrant Subsidiaries

DHLC (Applies to AEP and SWEPCo)

DHLC is a mining operator which previously sold 50% of the lignite produced to SWEPCo and 50% to CLECO.  The operations of DHLC are governed by the lignite mining agreement among SWEPCo, CLECO and DHLC. SWEPCo and CLECO share the executive board seats and voting rights equally. In accordance with the lignite mining agreement, each entity is responsible for 50% of DHLC’s obligations, including debt.  SWEPCo and CLECO equally approve DHLC’s annual budget.  The creditors of DHLC have no recourse to any AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee earned by DHLC.  In April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC providing notice of the cessation of lignite mining. SWEPCo’s total billings from DHLC for the years ended December 31, 2025, 2024 and 2023 were not material.  DHLC paid dividends of $1 million, $1 million, and $1 million to SWEPCo for the years ended December 31, 2025, 2024 and 2023, respectively. SWEPCo does not have the power to control decision making that significantly impacts the economic performance of DHLC because such power is shared with CLECO. As a result, SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although it holds a significant variable interest in DHLC.  SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets.

SWEPCo’s investment in DHLC was:

	December 31,
	2025				2024
	As Reported on the Balance Sheet		Maximum Exposure		As Reported on the Balance Sheet		Maximum Exposure
	(in millions)
Capital Contribution from SWEPCo	$	7	$	7	$	7	$	7
Retained Earnings	1		1		1		1
SWEPCo’s Share of Obligations	—		11		—		16
Total Investment in DHLC	$	8	$	19	$	8	$	24

320

OVEC (Applies to AEP and OPCo)

AEP and several nonaffiliated utility companies jointly own OVEC.  As of December 31, 2025, AEP’s ownership in OVEC was 43.47%. Parent owns 39.17% and OPCo owns 4.3%. APCo, I&M and OPCo are members to an intercompany power agreement.  The Registrants’ power participation ratios are 15.69% for APCo, 7.85% for I&M and 19.93% for OPCo. Participants of this agreement are entitled to receive and are obligated to pay for all OVEC generating capacity, approximately 2,400 MWs, in proportion to their respective power participation ratios. The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs, including outstanding indebtedness, and provide a return on capital.  The intercompany power agreement ends in June 2040.

AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests. 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.  These environmental projects were funded through debt issuances. As of December 31, 2025 and 2024, OVEC’s outstanding indebtedness was approximately $873 million and $997 million, respectively. Although they are not an obligor or guarantor, the Registrants’ are responsible for their respective ratio of OVEC’s outstanding debt through the intercompany power agreement. Principal and interest payments related to OVEC’s outstanding indebtedness are disclosed in accordance with the accounting guidance for “Commitments.” See the “Commitments” section of Note 6 for additional information.

AEP is not required to consolidate OVEC as it is not the primary beneficiary, although AEP and OPCo each hold a significant variable interest in OVEC. Power to control decision making that significantly impacts the economic performance of OVEC is shared amongst the owners through their representation on the Board of Directors of OVEC and the representation of the sponsoring companies on the Operating Committee under the intercompany power agreement.

In November 2025 and December 2025, OPCo filed applications with the PUCO and FERC, respectively, to transfer its 4.3% ownership in OVEC to Parent and its 19.93% OVEC power participation entitlement to AGR. Upon completion of the transaction, Parent will remain responsible for the financial and other obligations of AGR under the intercompany power agreement. In December 2025, the PUCO approved the application and a decision from the FERC is expected in the first half of 2026.

AEP’s investment in OVEC was:

	December 31,
	2025				2024
	As Reported on the Balance Sheet		Maximum Exposure		As Reported on the Balance Sheet		Maximum Exposure
	(in millions)
Capital Contribution from AEP	$	5	$	5	$	5	$	5
AEP’s Share of OVEC Debt (a)	—		379		—		433
Total Investment in OVEC	$	5	$	384	$	5	$	438

(a)Based on the Registrants’ power participation ratios, APCo, I&M and OPCo’s share of OVEC debt was $137 million, $68 million and $174 million as of December 31, 2025, respectively, and $156 million, $78 million and $199 million as of December 31, 2024, respectively.

Power purchased by the Registrant Subsidiaries from OVEC is included in Purchased Electricity, Fuel and Other Consumables Used for Electric Generation and Purchased Electricity for Resale on the statements of income and is shown in the table below:

	Years Ended December 31,
Company	2025		2024		2023
	(in millions)
APCo	$	120	$	134	$	122
I&M	60		67		61
OPCo	153		170		155

321

Equity Method Investments in Unconsolidated Entities (Applies to AEP)

For a discussion of the equity method of accounting, see the “Equity Method Investments in Unconsolidated Entities” section of Note 1.

ETT

ETT designs, acquires, constructs, owns and operates certain transmission facilities in ERCOT. BHE, a nonaffiliated entity, holds a 50% membership interest in ETT and AEP Transmission Holdco holds a 50% membership interest in ETT. As a result, AEP, through its wholly-owned subsidiary, holds a 50% membership interest in ETT. As of December 31, 2025 and 2024, AEP’s investment in ETT was $969 million and $897 million, respectively. AEP’s equity earnings associated with ETT were $80 million, $86 million and $74 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Gigawatt AI

In August 2025, AEP and Gigawatt AI, Inc. (GWAI), a privately held company, entered into a new commercial arrangement. GWAI is focused on developing AI-centric operating systems and applications that optimize utility operations and infrastructure. AEP invested $100 million for a 10% ownership interest in the common stock and received a warrant for the option to acquire an additional 5% of GWAI’s common stock for $50 million. Contingent upon GWAI’s achievement of defined performance-based milestones, AEP will invest up to an additional $100 million for up to an additional 10% of GWAI’s common stock. In January 2026, AEP made an additional $25 million investment for an incremental 2.5% interest in GWAI’s common stock because of GWAI’s achievement of a performance-based milestone. In connection with AEP's equity interest, AEP was granted the right to designate one of the three members of GWAI's board of directors. The board position is currently held by an officer of AEP and therefore the investment is a related-party transaction. AEP's board participation provides AEP with direct influence over GWAI's governance and oversight, while GWAI's founders retain all other equity interests and board representation. AEP also acquired a perpetual software license for software developed by GWAI.

The $100 million equity interest is accounted for as an equity method investment due to AEP’s ability to exercise significant influence over certain GWAI policies. As of December 31, 2025, AEP’s carrying value of the investment in GWAI was $100 million, which was initially recognized at cost in Deferred Charges and Other Noncurrent Assets on the balance sheet. AEP’s proportionate share of GWAI’s losses was immaterial for the year ended December 31, 2025.

The common stock warrant meets the definition of a derivative instrument and is therefore required to be carried at fair value on a recurring basis. The fair value of the common stock warrant and AEP's acquired perpetual software license were immaterial as of December 31, 2025.

322

19.  PROPERTY, PLANT AND EQUIPMENT

The disclosures in this note apply to all Registrants unless indicated otherwise.

Property, Plant and Equipment is shown functionally on the face of the balance sheets. The following tables include the total plant balances as of December 31, 2025 and 2024:

December 31, 2025	AEP			AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Regulated Property, Plant and Equipment
Generation	$	28,252	(a)	$	—	$	—	$	7,886	$	5,415	$	—	$	4,365	$	6,621	(a)
Transmission	42,557			8,229		16,542		5,277		2,055		3,916		1,433		3,302
Distribution	33,364			6,835		—		5,938		3,823		7,661		3,987		3,242
Other	7,731			1,236		571		1,127		1,011		1,277		1,289		726
CWIP	7,613		(a)	1,766		2,005		802		397		811		635		712		(a)
Less: Accumulated Depreciation	27,879			2,204		1,915		6,360		4,829		2,992		2,749		3,288
Total Regulated Property, Plant and Equipment - Net	91,638			15,862		17,203		14,670		7,872		10,673		8,960		11,315
Nonregulated Property, Plant and Equipment - Net	736			2		—		43		72		11		4		26
Total Property, Plant and Equipment - Net	$	92,374		$	15,864	$	17,203	$	14,713	$	7,944	$	10,684	$	8,964	$	11,341

December 31, 2024	AEP			AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Regulated Property, Plant and Equipment
Generation	$	24,695	(a)	$	—	$	—	$	7,273	$	5,439	$	—	$	2,772	$	5,288	(a)
Transmission	38,871			7,547		14,913		5,001		1,958		3,664		1,345		2,864
Distribution	31,062			6,250		—		5,569		3,535		7,244		3,699		3,007
Other	6,545			1,173		516		1,023		947		1,245		547		683
CWIP	6,322		(a)	1,118		1,965		743		330		691		379		627		(a)
Less: Accumulated Depreciation	25,794			2,046		1,578		6,031		4,607		2,883		2,215		3,049
Total Regulated Property, Plant and Equipment - Net	81,701			14,042		15,816		13,578		7,602		9,961		6,527		9,420
Nonregulated Property, Plant and Equipment - Net	715			2		—		35		77		10		5		26
Total Property, Plant and Equipment - Net	$	82,416		$	14,044	$	15,816	$	13,613	$	7,679	$	9,971	$	6,532	$	9,446

(a)AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant.

323

Depreciation, Depletion and Amortization

The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class.  The following tables provide total regulated annual composite depreciation rates and depreciable lives for the Registrants:

AEP
	2025						2024						2023
Functional Class of Property	Annual Composite Depreciation Rate Ranges			Depreciable Life Ranges			Annual Composite Depreciation Rate Ranges			Depreciable Life Ranges			Annual Composite Depreciation Rate Ranges			Depreciable Life Ranges
				(in years)						(in years)						(in years)
Generation	2.3%	-	5.0%	20	-	162	2.7%	-	4.9%	20	-	162	2.7%	-	4.7%	20	-	162
Transmission	1.8%	-	2.7%	15	-	79	2.1%	-	2.7%	15	-	79	2.0%	-	2.7%	15	-	78
Distribution	2.7%	-	3.4%	7	-	85	2.8%	-	3.5%	7	-	85	2.9%	-	3.6%	7	-	85
Other	1.5%	-	8.7%	5	-	75	3.0%	-	8.9%	5	-	75	3.8%	-	9.1%	5	-	75

AEP Texas
	2025				2024				2023
Functional Class of Property	Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges
		(in years)				(in years)				(in years)
Transmission	2.3%	50	-	79	2.2%	50	-	79	2.2%	50	-	75
Distribution	2.7%	15	-	74	2.8%	15	-	74	2.9%	7	-	70
Other	5.8%	5	-	54	5.9%	5	-	54	6.0%	5	-	50

AEPTCo
	2025				2024				2023
Functional Class of Property	Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges
		(in years)				(in years)				(in years)
Transmission	2.7%	24	-	78	2.7%	24	-	78	2.6%	24	-	78
Other	7.4%	5	-	58	7.1%	5	-	58	7.0%	5	-	58

APCo
	2025				2024				2023
Functional Class of Property	Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges
		(in years)				(in years)				(in years)
Generation	3.0%	20	-	162	3.2%	35	-	162	3.3%	35	-	162
Transmission	2.3%	15	-	78	2.3%	15	-	78	2.3%	15	-	78
Distribution	3.3%	15	-	60	3.5%	12	-	60	3.6%	12	-	60
Other	6.6%	5	-	55	6.8%	5	-	55	7.4%	5	-	55

I&M
	2025				2024				2023
Functional Class of Property	Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges
		(in years)				(in years)				(in years)
Generation	5.0%	20	-	132	4.9%	20	-	132	4.7%	20	-	132
Transmission	2.6%	44	-	67	2.6%	44	-	67	2.5%	44	-	67
Distribution	2.7%	15	-	76	2.8%	15	-	76	2.9%	14	-	71
Other	8.7%	5	-	45	8.9%	5	-	45	9.1%	5	-	45

OPCo
	2025				2024				2023
Functional Class of Property	Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges
		(in years)				(in years)				(in years)
Transmission	2.3%	39	-	60	2.3%	39	-	60	2.3%	39	-	60
Distribution	2.9%	11	-	70	3.1%	11	-	70	3.1%	11	-	70
Other	6.0%	5	-	50	5.9%	5	-	50	6.4%	5	-	50

324

PSO
	2025				2024				2023
Functional Class of Property	Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges
		(in years)				(in years)				(in years)
Generation	2.3%	30	-	78	3.3%	30	-	78	3.0%	25	-	75
Transmission	2.6%	41	-	75	2.6%	41	-	75	2.6%	41	-	75
Distribution	2.8%	15	-	85	2.8%	15	-	85	2.9%	15	-	85
Other	6.8%	5	-	58	6.6%	5	-	58	6.8%	5	-	58

SWEPCo
	2025				2024				2023
Functional Class of Property	Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges			Annual Composite Depreciation Rate	Depreciable Life Ranges
		(in years)				(in years)				(in years)
Generation	3.4%	30	-	65	3.7%	30	-	65	2.9%	30	-	65
Transmission	2.1%	46	-	70	2.2%	46	-	70	2.2%	46	-	70
Distribution	2.9%	7	-	75	2.9%	7	-	75	2.9%	7	-	75
Other	6.9%	5	-	58	6.7%	5	-	58	8.5%	5	-	58

The following table includes the nonregulated annual composite depreciation rate ranges and nonregulated depreciable life ranges for AEP. With the exception of I&M, the Registrants' depreciation rate ranges and depreciable life ranges are not meaningful for nonregulated property for 2025, 2024 and 2023.

	2025						2024						2023
Functional Class of Property	Annual Composite Depreciation Rate Ranges (a)			Depreciable Life Ranges (a)			Annual Composite Depreciation Rate Ranges (a)			Depreciable Life Ranges (a)			Annual Composite Depreciation Rate Ranges			Depreciable Life Ranges
				(in years)						(in years)						(in years)
Generation	1.9%	-	7.6%	39	-	61	1.8%	-	6.0%	39	-	61	4.8%	-	6.7%	10	-	61
Transmission	NA			NA			NA			NA			2.5%			62
Distribution	NA			NA			NA			NA			NA			NA
Other	10.3%			5	-	35	9.7%			5	-	35	10.6%			5	-	35

(a) I&M's annual composite depreciation rate for Generation property is 1.9% and the depreciable life is 39 years.

NA Not applicable.

For regulated operations, the composite depreciation rate generally includes a component for non-ARO removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets.  Actual removal costs incurred are charged to Accumulated Depreciation and Amortization.  Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability.  For nonregulated operations, non-ARO removal costs are expensed as incurred. 

325

Asset Retirement Obligations (Applies to all Registrants except AEPTCo)

Listed below are significant changes to the Registrants ARO balances as of December 31, 2025 and 2024:

•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. In the second quarter of 2024, AEP evaluated the applicability of the rule to current and former plant sites and incurred ARO liabilities of $602 million and revised cash flow estimates by an additional $72 million based on initial cost estimates. See the “Federal EPA’s Revised CCR Rule” section of Note 6 for additional information.

•In December 2024, I&M recorded a $176 million revision as a result of the completion of the latest Cook Plant nuclear decommissioning study.  I&M's ARO related to nuclear decommissioning costs for the Cook Plant was $2.1 billion and $2 billion as of December 31, 2025 and 2024. As of December 31, 2025 and 2024, the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $4.5 billion and $4 billion, respectively.  These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheets.

The following is a reconciliation of the 2025 and 2024 aggregate carrying amounts of ARO by Registrant:

Company	ARO as of December 31, 2024		Accretion Expense		Liabilities Incurred		Liabilities Settled		Revisions in Cash Flow Estimates (a)		ARO as of December 31, 2025
	(in millions)
AEP(b)(c)(d)(e)(f)(g)	$	3,612	$	170	$	45	$	(103)	$	(12)	$	3,712
AEP Texas (e)	4		—		—		—		—		4
APCo (b)(e)(f)(g)	802		42		4		(19)		(51)		778
I&M (b)(c)(e)	2,094		86		—		(2)		4		2,182
OPCo (b)(e)	56		4		—		(1)		1		60
PSO (b)(e)(f)(g)	122		8		19		(3)		(3)		143
SWEPCo (b)(d)(e)(f)(g)	279		16		20		(65)		40		290

Company	ARO as of December 31, 2023		Accretion Expense		Liabilities Incurred		Liabilities Settled		Revisions in Cash Flow Estimates (a)		ARO as of December 31, 2024
	(in millions)
AEP (b)(c)(d)(e)(f)	$	3,031	$	140	$	612	$	(102)	$	(69)	$	3,612
AEP Texas (e)	5		—		—		(1)		—		4
APCo (b)(e)(f)	464		28		247		(18)		81		802
I&M (b)(c)(e)	2,106		80		86		(2)		(176)		2,094
OPCo (b)(e)	2		1		53		—		—		56
PSO (b)(e)(f)	84		6		34		(2)		—		122
SWEPCo (b)(d)(e)(f)	282		16		30		(69)		20		279

(a)Unless discussed above, primarily related to ash ponds, landfills and mine reclamation, generally due to changes in estimated closure area, volumes and/or unit costs.

(b)Includes ARO related to ash disposal facilities.

(c)Includes ARO related to nuclear decommissioning costs for the Cook Plant.

(d)Includes ARO related to Sabine and DHLC.

(e)Includes ARO related to asbestos removal.

(f)Includes ARO related to renewables.

(g)Includes ARO related to incurred ARO liabilities due to the acquisitions in 2025. See the “Acquisitions” section of Note 7 for additional information.

326

Allowance for Funds Used During Construction and Interest Capitalization

The Registrants’ amounts of allowance for equity funds used during construction are summarized in the following table:

	Years Ended December 31,
Company	2025		2024		2023
	(in millions)
AEP	$	245	$	211	$	175
AEP Texas	53		46		28
AEPTCo	93		89		83
APCo	17		16		12
I&M	18		13		11
OPCo	25		23		17
PSO	11		7		8
SWEPCo	23		14		11

The Registrants’ amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table:

	Years Ended December 31,
Company	2025		2024		2023
	(in millions)
AEP	$	154	$	130	$	117
AEP Texas	28		31		23
AEPTCo	37		34		31
APCo	10		11		14
I&M	10		9		8
OPCo	13		13		14
PSO	9		10		5
SWEPCo	13		15		10

327

Jointly-owned Electric Facilities (Applies to AEP, I&M, PSO and SWEPCo)

The Registrants have electric facilities that are jointly-owned with affiliated and nonaffiliated companies.  Using its own financing, each participating company is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest.  Each Registrant’s proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows:

				Registrant’s Share as of December 31, 2025
	Fuel Type	Percent of Ownership		Utility Plant in Service		Construction Work in Progress		Accumulated Depreciation
				(in millions)
AEP
Flint Creek Generating Station, Unit 1 (a)	Coal	50.0	%	$	406	$	2	$	208
Turk Generating Plant (a)	Coal	73.3	%	1,520		1		381
Total				$	1,926	$	3	$	589
I&M
Rockport Generating Plant (b)(c)	Coal	50.0	%	$	1,353	$	16	$	1,341
PSO
North Central Wind Energy Facilities (d)(e)	Wind	45.5	%	$	912	$	3	$	101
SWEPCo
Flint Creek Generating Station, Unit 1 (a)	Coal	50.0	%	$	406	$	2	$	208
Turk Generating Plant (a)	Coal	73.3	%	1,520		1		381
North Central Wind Energy Facilities (d)(e)	Wind	54.5	%	1,093		4		128
Total				$	3,019	$	7	$	717

				Registrant’s Share as of December 31, 2024
	Fuel Type	Percent of Ownership		Utility Plant in Service		Construction Work in Progress		Accumulated Depreciation
				(in millions)
AEP
Flint Creek Generating Station, Unit 1 (a)	Coal	50.0	%	$	404	$	4	$	189
Turk Generating Plant (a)	Coal	73.3	%	1,517		1		350
Total				$	1,921	$	5	$	539
I&M
Rockport Generating Plant (b)(c)	Coal	50.0	%	$	1,345	$	11	$	1,182
PSO
North Central Wind Energy Facilities (d)(e)	Wind	45.5	%	$	912	$	1	$	78
SWEPCo
Flint Creek Generating Station, Unit 1 (a)	Coal	50.0	%	$	404	$	4	$	189
Turk Generating Plant (a)	Coal	73.3	%	1,517		1		350
North Central Wind Energy Facilities (d)(e)	Wind	54.5	%	1,094		1		98
Total				$	3,015	$	6	$	637

(a)Operated by SWEPCo.

(b)Operated by I&M

(c)AEGCo owns 50%

(d)Operated by PSO.

(e)PSO and SWEPCo own undivided interests of 45.5% and 54.5% of the NCWF, respectively.

328

20. REVENUE FROM CONTRACTS WITH CUSTOMERS

The disclosures in this note apply to all Registrants, unless indicated otherwise.

Disaggregated Revenues from Contracts with Customers

The tables below represent AEP’s reportable segment revenues from contracts with customers, net of respective provisions for refund, by type of revenue:

	Year Ended December 31, 2025
	VIU		T&D		AEPTHCo		G&M		Corporate and Other		Reconciling Adjustments		AEP Consolidated
	(in millions)
Retail Revenues:
Residential Revenues	$	4,969	$	2,785	$	—	$	—	$	—	$	—	$	7,754
Commercial Revenues	3,068		1,626		—		—		—		—		4,694
Industrial Revenues (a)	2,718		533		—		—		—		(1)		3,250
Other Retail Revenues	242		60		—		—		—		—		302
Total Retail Revenues	10,997		5,004		—		—		—		(1)		16,000
Wholesale and Competitive Retail Revenues:
Generation Revenues	1,033		—		—		187		—		—		1,220
Transmission Revenues (b)	533		812		2,275		—		—		(2,017)		1,603
Retail, Trading and Marketing Revenues (c)	—		—		—		2,463		—		(66)		2,397
Total Wholesale and Competitive Retail Revenues	1,566		812		2,275		2,650		—		(2,083)		5,220
Other Revenues from Contracts with Customers (d)	236		259		36		10		137		(196)		482
Total Revenues from Contracts with Customers	12,799		6,075		2,311		2,660		137		(2,280)		21,702
Other Revenues:
Alternative Revenue Programs (e)	29		51		66		—		—		(85)		61
Other Revenues (f)	(9)		21		—		102		7		(8)		113
Total Other Revenues	20		72		66		102		7		(93)		174
Total Revenues	$	12,819	$	6,147	$	2,377	$	2,762	$	144	$	(2,373)	$	21,876

(a)Amounts include affiliated and nonaffiliated revenues.

(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $1.8 billion. The affiliated revenues for Vertically Integrated Utilities were $211 million. The remaining affiliated amounts were immaterial.

(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $66 million. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $113 million. The remaining affiliated amounts were immaterial.

(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $57 million. The remaining affiliated amounts were immaterial.

(f)Generation & Marketing includes economic hedge activity.

329

	Year Ended December 31, 2024
	VIU		T&D		AEPTHCo		G&M		Corporate and Other		Reconciling Adjustments		AEP Consolidated
	(in millions)
Retail Revenues:
Residential Revenues	$	4,562	$	2,756	$	—	$	—	$	—	$	—	$	7,318
Commercial Revenues	2,731		1,567		—		—		—		—		4,298
Industrial Revenues (a)	2,659		515		—		—		—		(1)		3,173
Other Retail Revenues	232		56		—		—		—		—		288
Total Retail Revenues	10,184		4,894		—		—		—		(1)		15,077
Wholesale and Competitive Retail Revenues:
Generation Revenues	748		—		—		103		—		—		851
Transmission Revenues (b)	483		770		1,978		—		—		(1,620)		1,611
Renewable Generation Revenues (a)	—		—		—		23		—		(4)		19
Retail, Trading and Marketing Revenues (c)	—		—		—		2,081		1		(96)		1,986
Total Wholesale and Competitive Retail Revenues	1,231		770		1,978		2,207		1		(1,720)		4,467
Other Revenues from Contracts with Customers (d)	227		198		26		4		185		(214)		426
Total Revenues from Contracts with Customers	11,642		5,862		2,004		2,211		186		(1,935)		19,970
Other Revenues:
Alternative Revenue Programs (e)	(22)		26		(53)		—		—		(30)		(79)
Other Revenues (a) (f)	(23)		20		—		(166)		(3)		2		(170)
Total Other Revenues	(45)		46		(53)		(166)		(3)		(28)		(249)
Total Revenues	$	11,597	$	5,908	$	1,951	$	2,045	$	183	$	(1,963)	$	19,721

(a)Amounts include affiliated and nonaffiliated revenues.

(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $1.6 billion and Vertically Integrated Utilities was $177 million. The remaining affiliated amounts were immaterial.

(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $96 million. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Corporate and Other was $137 million. The remaining affiliated amounts were immaterial.

(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.

(f)Generation & Marketing includes economic hedge activity.

330

	Year Ended December 31, 2023
	VIU		T&D		AEPTHCo		G&M		Corporate and Other		Reconciling Adjustments		AEP Consolidated
	(in millions)
Retail Revenues:
Residential Revenues	$	4,479	$	2,609	$	—	$	—	$	—	$	—	$	7,088
Commercial Revenues	2,679		1,497		—		—		—		—		4,176
Industrial Revenues (a)	2,748		642		—		—		—		(1)		3,389
Other Retail Revenues	243		51		—		—		—		—		294
Total Retail Revenues	10,149		4,799		—		—		—		(1)		14,947
Wholesale and Competitive Retail Revenues:
Generation Revenues	663		—		—		111		—		—		774
Transmission Revenues (b)	444		702		1,749		—		—		(1,418)		1,477
Renewable Generation Revenues (a)	—		—		—		81		—		(7)		74
Retail, Trading and Marketing Revenues (c)	—		—		—		1,836		1		(82)		1,755
Total Wholesale and Competitive Retail Revenues	1,107		702		1,749		2,028		1		(1,507)		4,080
Other Revenues from Contracts with Customers (d)	204		208		17		9		151		(160)		429
Total Revenues from Contracts with Customers	11,460		5,709		1,766		2,037		152		(1,668)		19,456
Other Revenues:
Alternative Revenue Programs (e)	(35)		(20)		(37)		—		—		(26)		(118)
Other Revenues (a) (f)	25		24		—		(405)		16		(16)		(356)
Total Other Revenues	(10)		4		(37)		(405)		16		(42)		(474)
Total Revenues	$	11,450	$	5,713	$	1,729	$	1,632	$	168	$	(1,710)	$	18,982

(a)Amounts include affiliated and nonaffiliated revenues.

(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $1.5 billion and Vertically Integrated Utilities was $205 million. The remaining affiliated amounts were immaterial.

(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $82 million. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Corporate and Other was $100 million. The remaining affiliated amounts were immaterial.

(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.

(f)Generation & Marketing includes economic hedge activity.

331

The tables below represent revenues from contracts with customers, net of respective provisions for refund, by type of revenue for the Registrant Subsidiaries:

	Year Ended December 31, 2025
	AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Retail Revenues:
Residential Revenues	$	758	$	—	$	1,863	$	895	$	2,026	$	884	$	856
Commercial Revenues	474		—		775		802		1,151		554		636
Industrial Revenues (a)	161		—		799		603		373		369		403
Other Retail Revenues	43		—		111		5		17		107		12
Total Retail Revenues	1,436		—		3,548		2,305		3,567		1,914		1,907
Wholesale Revenues:
Generation Revenues (b)	—		—		372		581		—		25		196
Transmission Revenues (c)	717		2,213		175		51		95		46		195
Total Wholesale Revenues	717		2,213		547		632		95		71		391
Other Revenues from Contracts with Customers (d)	41		36		88		114		218		34		38
Total Revenues from Contracts with Customers	2,194		2,249		4,183		3,051		3,880		2,019		2,336
Other Revenues:
Alternative Revenue Programs (e)	5		70		26		(9)		46		3		18
Other Revenues (a)	—		—		—		(11)		22		—		—
Total Other Revenues	5		70		26		(20)		68		3		18
Total Revenues	$	2,199	$	2,319	$	4,209	$	3,031	$	3,948	$	2,022	$	2,354

(a)Amounts include affiliated and nonaffiliated revenues.

(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $165 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.

(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEPTCo, APCo and SWEPCo were $1.8 billion, $79 million and $75 million, respectively. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for I&M were $70 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.

(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEPTCo were $56 million. The remaining affiliated amounts were immaterial.

332

	Year Ended December 31, 2024
	AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Retail Revenues:
Residential Revenues	$	725	$	—	$	1,772	$	847	$	2,031	$	800	$	726
Commercial Revenues	467		—		764		605		1,101		510		558
Industrial Revenues (a)	141		—		813		596		374		349		368
Other Retail Revenues	39		—		113		5		17		100		9
Total Retail Revenues	1,372		—		3,462		2,053		3,523		1,759		1,661
Wholesale Revenues:
Generation Revenues (b)	—		—		305		394		—		9		177
Transmission Revenues (c)	673		1,925		185		41		96		42		172
Total Wholesale Revenues	673		1,925		490		435		96		51		349
Other Revenues from Contracts with Customers (d)	36		26		87		116		162		39		33
Total Revenues from Contracts with Customers	2,081		1,951		4,039		2,604		3,781		1,849		2,043
Other Revenues:
Alternative Revenue Programs (e)	(1)		(60)		(6)		(8)		27		(3)		(7)
Other Revenues (a)	—		—		—		(24)		20		—		—
Total Other Revenues	(1)		(60)		(6)		(32)		47		(3)		(7)
Total Revenues	$	2,080	$	1,891	$	4,033	$	2,572	$	3,828	$	1,846	$	2,036

(a)Amounts include affiliated and nonaffiliated revenues.

(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $159 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.

(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $1.6 billion, APCo was $87 million and SWEPCo was $65 million. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $75 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.

(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.

333

	Year Ended December 31, 2023
	AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Retail Revenues:
Residential Revenues	$	656	$	—	$	1,613	$	842	$	1,954	$	831	$	800
Commercial Revenues	415		—		700		575		1,082		539		609
Industrial Revenues (a)	145		—		778		614		497		423		416
Other Retail Revenues	35		—		106		5		15		113		10
Total Retail Revenues	1,251		—		3,197		2,036		3,548		1,906		1,835
Wholesale Revenues:
Generation Revenues (b)	—		—		288		327		—		12		177
Transmission Revenues (c)	619		1,704		181		39		83		37		151
Total Wholesale Revenues	619		1,704		469		366		83		49		328
Other Revenues from Contracts with Customers (d)	36		16		74		120		172		22		29
Total Revenues from Contracts with Customers	1,906		1,720		3,740		2,522		3,803		1,977		2,192
Other Revenues:
Alternative Revenue Programs (e)	(4)		(49)		(19)		(11)		(15)		—		(9)
Other Revenues (a)	—		—		—		25		23		—		—
Total Other Revenues	(4)		(49)		(19)		14		8		—		(9)
Total Revenues	$	1,902	$	1,671	$	3,721	$	2,536	$	3,811	$	1,977	$	2,183

(a)Amounts include affiliated and nonaffiliated revenues.

(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $159 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.

(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $1.4 billion, APCo was $93 million and SWEPCo was $73 million. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $68 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.

(e)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues.

Performance Obligations

AEP has performance obligations as part of its normal course of business. A performance obligation is a promise to transfer a distinct good or service, or a series of distinct goods or services that are substantially the same and have the same pattern of transfer to a customer. The invoice practical expedient within the accounting guidance for “Revenue from Contracts with Customers” allows for the recognition of revenue from performance obligations in the amount of consideration to which there is a right to invoice the customer and when the amount for which there is a right to invoice corresponds directly to the value transferred to the customer.

The purpose of the invoice practical expedient is to depict an entity’s measure of progress toward completion of the performance obligation within a contract and can only be applied to performance obligations that are satisfied over time and when the invoice is representative of services provided to date. AEP subsidiaries elected to apply the invoice practical expedient to recognize revenue for performance obligations satisfied over time as the invoices from the respective revenue streams are representative of services or goods provided to date to the customer. Performance obligations for AEP’s subsidiaries are summarized as follows:

Retail Revenues

AEP’s subsidiaries within the Vertically Integrated Utilities and Transmission and Distribution Utilities segments have performance obligations to generate, transmit and distribute electricity for sale to rate-regulated retail customers. The performance obligation to deliver electricity is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are variable as they are subject to the customer’s usage requirements.

Rate-regulated retail customers typically have the right to discontinue receiving service at will, therefore these contracts between AEP’s subsidiaries and their customers for rate-regulated services are generally limited to the services requested and received to date for such arrangements. Retail customers are generally billed on a monthly basis, and payment is typically due within 15 to 20 days after the issuance of the invoice. Payments from REPs are due to AEP Texas within 35 days.

334

Wholesale Revenues - Generation

AEP’s subsidiaries within the Vertically Integrated Utilities and Generation & Marketing segments have performance obligations to sell electricity to wholesale customers from generation assets in PJM, SPP and ERCOT. The performance obligation to deliver electricity from generation assets is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Wholesale generation revenues are variable as they are subject to the customer’s usage requirements.

AEP’s subsidiaries within the Vertically Integrated Utilities and Generation & Marketing segments also have performance obligations to stand ready in order to promote grid reliability. Stand ready services are sold into PJM’s RPM capacity market. RPM entails a base auction and at least three incremental auctions for a specific PJM delivery year, with the incremental auctions spanning three years. The performance obligation to stand ready is satisfied over time and the consideration for which is variable until the occurrence of the final incremental auction, at which point the performance obligation becomes fixed.

Payments from the RTO for stand ready services are typically received within one week from the issuance of the invoice, which is typically issued weekly. Gross margin resulting from generation sales within the Vertically Integrated Utilities segment are primarily subject to margin sharing agreements with customers and vary by state, where the revenues are reflected gross in the disaggregated revenues tables above.

APCo has a performance obligation to supply wholesale electricity to KGPCo through a PPA. The FERC regulates the cost-based wholesale power transactions between APCo and KGPCo. The purchased power agreement includes a component for the recovery of transmission costs under the FERC OATT. The transmission cost component of purchased power is cost-based and regulated by the Tennessee Regulatory Authority. APCo’s performance obligation under the purchased power agreement is satisfied over time as KGPCo simultaneously receives and consumes the wholesale electricity. APCo’s revenues from the purchased power agreement are presented within the Generation Revenues line in the disaggregated revenues tables above.

Wholesale Revenues - Transmission

AEP’s subsidiaries within the Vertically Integrated Utilities, Transmission and Distribution Utilities and AEP Transmission Holdco segments have performance obligations to transmit electricity to wholesale customers through assets owned and operated by AEP subsidiaries. The performance obligation to provide transmission services in PJM, SPP and ERCOT is partially fixed for a period of one year or less. Payments from the RTO for transmission services are typically received within one week from the issuance of the invoice, which is issued monthly for SPP and ERCOT and weekly for PJM.

AEP subsidiaries within the PJM and SPP regions collect revenues through transmission formula rates. The FERC-approved rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners. The formula rates establish rates for a one year period and also include a true-up calculation for the prior year’s billings, allowing for over/under-recovery of the transmission owner’s ATRR. The annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations,” and are therefore presented as such in the disaggregated revenues tables above. AEP subsidiaries within the ERCOT region collect revenues through a combination of base rates and interim Transmission Costs of Services filings that are approved by the PUCT.

The AEP East Companies are parties to the TA, which defines how transmission costs are allocated among the AEP East Companies on a 12-month average coincident peak basis. PSO, SWEPCo and AEPSC are parties to the TCA by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. AEPTCo is a transmission owner within the PJM and SPP regions providing transmission services to affiliates in accordance with the OATT, TA and TCA. Affiliate revenues as a result of the respective TA and the TCA are reflected as Transmission Revenues in the disaggregated revenues tables above.

Marketing, Competitive Retail and Renewable Revenues

AEP’s subsidiaries within the Generation & Marketing segment have performance obligations to deliver electricity to competitive retail and wholesale customers. Performance obligations for marketing and competitive retail are satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are primarily variable as they are subject to customer’s usage requirements; however, certain contracts mandate a delivery of a set quantity of electricity at a predetermined price, resulting in a fixed performance obligation.

Payment terms under marketing arrangements typically follow standard Edison Electric Institute and International Swaps and Derivatives Association terms, which call for payment in 20 days. Payments for competitive retail and offtake arrangements for renewable assets range from 15 to 60 days and are dependent on the product sold, location and the creditworthiness of customer. Invoices for marketing arrangements, competitive retail and offtake arrangements for renewable assets are issued monthly.

335

Fixed Performance Obligations (Applies to AEP, APCo and I&M)

The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of December 31, 2025. Fixed performance obligations primarily include electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The Registrants elected to apply the exemption to not disclose the value of unsatisfied performance obligations for contracts with an original expected term of one year or less. Due to the annual establishment of revenue requirements, transmission revenues are excluded from the table below. The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues.

Company	2026		2027-2028		2029-2030		After 2030		Total
	(in millions)
AEP	$	85	$	86	$	39	$	16	$	226
APCo	16		32		23		12		83
I&M	4		9		5		2		20

Contract Assets and Liabilities

Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants did not have any material contract assets as of December 31, 2025 and 2024.

When the Registrants receive consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance sheet in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. The Registrants’ contract liabilities typically arise from services provided under joint use agreements for utility poles. The Registrants did not have any material contract liabilities as of December 31, 2025 and 2024.

Accounts Receivable from Contracts with Customers

Accounts receivable from contracts with customers are presented on the Registrants’ balance sheets within the Accounts Receivable - Customers line item. The Registrants’ balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Accounts Receivable - Customers were not material as of December 31, 2025 and 2024. See “Securitized Accounts Receivable - AEP Credit” section of Note 15 for additional information.

The following table represents the amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable - Affiliated Companies on the Registrant Subsidiaries’ balance sheets:

Years Ended December 31,	AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
2025	$	146	$	113	$	67	$	74	$	22	$	65
2024	132		84		55		64		13		21

Contract Costs

Contract costs to obtain or fulfill a contract for AEP subsidiaries within the Generation & Marketing segment are accounted for under the guidance for “Other Assets and Deferred Costs” and presented as a single asset and are neither bifurcated nor reclassified between current and noncurrent assets on the Registrants’ balance sheets. Contract costs to acquire a contract are amortized in a manner consistent with the transfer of goods or services to the customer in Other Operation on the Registrants’ income statements. The Registrants did not have material contract costs as of December 31, 2025 and 2024.

336

ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

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

Information required by this item is set forth under the caption Proposal to Ratify the Appointment of the Independent Registered Public Accounting Firm in the 2026 Proxy Statement, which is incorporated by reference into this item.

ITEM 9A.   CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

During 2025, management, including the principal executive officer and principal financial officer of each of the Registrants evaluated each respective Registrant’s disclosure controls and procedures.  Disclosure controls and procedures are defined as controls and other procedures of the Registrant that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms.  Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to each Registrant’s management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

As of December 31, 2025, the principal executive officer and financial officer of each of the Registrants concluded that the disclosure controls and procedures in place were effective at the reasonable assurance level.  The Registrants regularly strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.

Changes in Internal Control over Financial Reporting

There have been no changes in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter 2025 that materially affected, or are reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

Internal Control over Financial Reporting

See Management’s Report on Internal Control over Financial Reporting for each Registrant under Item 8. As discussed in that report, management assessed and reported on the effectiveness of each Registrant’s internal control over financial reporting as of December 31, 2025.  As a result of that assessment, management concluded that each Registrant’s internal control over financial reporting was effective as of December 31, 2025.

ITEM 9B.   OTHER INFORMATION

During the three months ended December 31, 2025, none of the Company’s directors or officers (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) adopted, terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K of the Securities Act of 1933).

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

None.

337

PART III

ITEM 10.   DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

AEP

Directors, Director Nomination Process and Audit Committee

Certain of the information called for in this Item 10, including the information relating to directors, is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2026 Annual Meeting of Shareholders (the 2026 Annual Meeting) including under the captions “Election of Directors,” “AEP’s Board of Directors and Committees,” “Directors” and “Nominees for Directors.”

Executive Officers

Reference also is made under the caption “Information About our Executive Officers” in Part I, Item 1 of this report.

Code of Ethics

AEP’s Principles of Business Conduct is the code of ethics that applies to AEP’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer. The Principles of Business Conduct is available on AEP’s website at www.aep.com.  The Principles of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Investor Relations, American Electric Power Company, Inc., 1 Riverside Plaza, Columbus, Ohio 43215.

If any substantive amendments to the Principles of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Principles of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, AEP will disclose the nature of such amendment or waiver on AEP’s website, www.aep.com, or in a report on Form 8-K.

Insider Trading Policies and Procedures

AEP has an insider trading policy governing the purchase, sale and other dispositions of the company’s debt and equity securities that applies to all company personnel, including directors, officers, employees, and other covered persons. The policy also applies to the company. The company believes that its insider trading policy is reasonably designed to promote compliance with insider trading laws, rules, and regulations, and NASDAQ listing standards applicable to the company. A copy of the company’s insider trading policy is filed as Exhibit 19.1 to this Form 10-K. The remaining information required by this Item will be included in the company’s definitive proxy statement which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act, relating to the 2026 Annual Meeting under the caption “Corporate Governance” and is incorporated herein by reference.

Delinquent Section 16(a) Reports

None.

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

Omitted pursuant to Instruction I(2)(c).

ITEM 11.   EXECUTIVE COMPENSATION

AEP

The information called for by this Item 11 is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2026 Annual Meeting including under the captions “Compensation Discussion and Analysis,” “Executive Compensation”, “Director Compensation” and “2025 Director Compensation Table”.  The information set forth under the subcaption “Human Resources Committee Report” and “Audit Committee Report” should not be deemed filed nor should it be incorporated by reference into any other filing under the Securities Act of 1933, as amended, or the Exchange Act except to the extent AEP specifically incorporates such report by reference therein.

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

Omitted pursuant to Instruction I(2)(c).

338

ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

AEP

The information relating to Security Ownership of Certain Beneficial Owners is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to 2026 Annual Meeting under the caption “Share Ownership of Certain Beneficial Owners” and “Share Ownership of Directors and Executive Officers.”

EQUITY COMPENSATION PLAN INFORMATION

The following table summarizes the ability of AEP to issue common stock pursuant to equity compensation plans as of December 31, 2025:

Plan Category	Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights (a)	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b)	Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans
Equity Compensation Plans Approved by Security Holders	2,199,734	—	8,909,934
Equity Compensation Plans Not Approved by Security Holders	—	—	—
Total	2,199,734	—	8,909,934

(a)The balance includes unvested performance shares and restricted stock units as well as vested performance shares deferred as AEP career shares and stock units payable to outside directors after their service to the Company ends, all of which will be settled and paid in shares of AEP common stock. For performance shares, the total includes the target number of shares that could be granted if performance meets target objectives. The number of securities that would be granted, with respect to performance shares, if performance meets the maximum payout level, is two times the amount included in this total.

(b)No consideration is required from participants for the exercise or vesting of any outstanding AEP equity compensation awards.

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

Omitted pursuant to Instruction I(2)(c).

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

AEP

The information called for by this Item 13 is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2026 Annual Meeting under the captions “Certain Relationships and Related Person Transactions” and “Director Independence.”

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

Omitted pursuant to Instruction I(2)(c).

339

ITEM 14.   PRINCIPAL ACCOUNTING FEES AND SERVICES

AEP

The information called for by this Item 14 is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2026 Annual Meeting under the captions “Audit and Non-Audit Fees,” “Audit Committee Report” and “Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of the Independent Auditor.”

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

Each of the above is a wholly-owned subsidiary of AEP and does not have a separate audit committee. A description of the AEP Audit Committee pre-approval policies, which apply to these companies, is contained in the definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2026 Annual Meeting under the captions “Audit and Non-Audit Fees,” “Audit Committee Report” and “Policy on Audit Committee Pre-Approval of the Audit and Permissible Non-Audit Services of the Independent Auditor.” The following table presents directly billed fees for professional services rendered by PricewaterhouseCoopers LLP for the audit of these companies’ annual financial statements for the years ended December 31, 2025 and 2024, and fees directly billed for other services rendered by PricewaterhouseCoopers LLP during those periods. PricewaterhouseCoopers LLP also provides additional professional and other services to AEP subsidiaries, the cost of which may ultimately be allocated to these companies though not billed directly to them.

	AEP Texas				AEPTCo				APCo
	2025		2024		2025		2024		2025		2024
Audit Fees	$	1,496,490	$	1,450,607	$	1,817,864	$	1,670,508	$	1,776,943	$	1,768,558
Audit-Related Fees	42,384		56,917		—		—		48,696		120,500
Total	$	1,538,874	$	1,507,524	$	1,817,864	$	1,670,508	$	1,825,639	$	1,889,058

	I&M				OPCo				PSO
	2025		2024		2025		2024		2025		2024
Audit Fees	$	1,517,387	$	1,374,594	$	1,171,100	$	1,231,434	$	863,009	$	745,452
Audit-Related Fees	14,785		49,160		14,785		14,250		6,312		63,000
Total	$	1,532,172	$	1,423,754	$	1,185,885	$	1,245,684	$	869,321	$	808,452

	SWEPCo
	2025		2024
Audit Fees	$	1,067,604	$	1,109,336
Audit-Related Fees	141,280		85,833
Total	$	1,208,884	$	1,195,169

340

PART IV

ITEM 15.   EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The following documents are filed as a part of this report:

(a)(1) FINANCIAL STATEMENTS:

The following financial statements have been incorporated herein by reference pursuant to Item 8.

AEP and Subsidiary Companies:

Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2025, 2024 and 2023; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2025, 2024 and 2023; Consolidated Statements of Changes in Equity for the years ended December 31, 2025, 2024 and 2023; Consolidated Balance Sheets as of December 31, 2025 and 2024; Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024 and 2023; Notes to Financial Statements of Registrants.

AEP Texas, APCo and I&M:

Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2025, 2024 and 2023; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2025, 2024 and 2023; Consolidated Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2025, 2024 and 2023; Consolidated Balance Sheets as of December 31, 2025 and 2024; Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024 and 2023; Notes to Financial Statements of Registrants.

AEPTCo:

Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2025, 2024 and 2023; Consolidated Statements of Changes in Member’s Equity for the years ended December 31, 2025, 2024 and 2023; Consolidated Balance Sheets as of December 31, 2025 and 2024; Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024 and 2023; Notes to Financial Statements of Registrants.

OPCo:

Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2025, 2024 and 2023; Consolidated Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2025, 2024 and 2023; Consolidated Balance Sheets as of December 31, 2025 and 2024; Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024 and 2023; Notes to Financial Statements of Registrants.

PSO:

Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Statements of Income for the years ended December 31, 2025, 2024 and 2023; Statements of Comprehensive Income (Loss) for the years ended December 31, 2025, 2024 and 2023; Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2025, 2024 and 2023; Balance Sheets as of December 31, 2025 and 2024; Statements of Cash Flows for the years ended December 31, 2025, 2024 and 2023; Notes to Financial Statements of Registrants.

SWEPCo:

Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2025, 2024 and 2023; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2025, 2024 and 2023; Consolidated Statements of Changes in Equity for the years ended December 31, 2025, 2024 and 2023; Consolidated Balance Sheets as of December 31, 2025 and 2024; Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024 and 2023; Notes to Financial Statements of Registrants.

341

(a)(2) FINANCIAL STATEMENT SCHEDULES:	Page Number
Schedule I
Condensed Financial Information of American Electric Power Company, Inc. (Parent)
Condensed Statements of Income and Comprehensive Income - Years Ended December 31, 2025, 2024 and 2023	S-2
Condensed Balance Sheets - December 31, 2025 and 2024	S-3
Condensed Statements of Cash Flows - Years Ended December 31, 2025, 2024 and 2023	S-5
Condensed Notes to Condensed Financial Information	S-6
Schedule II
AEP
Valuation and Qualifying Accounts and Reserves - Years Ended December 31, 2025, 2024 and 2023	S-9
Schedule I
Condensed Financial Information of AEP Transmission Company, LLC (AEPTCo Parent)
Condensed Statements of Income - Years Ended December 31, 2025, 2024 and 2023	S-11
Condensed Balance Sheets - December 31, 2025 and 2024	S-12
Condensed Statements of Cash Flows - Years Ended December 31, 2025, 2024 and 2023	S-14
Condensed Notes to Condensed Financial Information	S-15
Certain schedules have been omitted because the required information is contained in the notes to financial statements or because such schedules are not required or are not applicable.
(a)(3) EXHIBITS:
Exhibits for AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo are listed in the Exhibit Index beginning on page E-1 and are incorporated herein by reference.	E-1

ITEM 16.   FORM 10-K SUMMARY

None.

342

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

American Electric Power Company, Inc.
By:	/s/  Trevor I. Mihalik
	(Trevor I. Mihalik, Executive Vice President
	and Chief Financial Officer)

Date: February 12, 2026

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature		Title	Date
(i)	Principal Executive Officer:
	/s/  William J. Fehrman	Chair of the Board, President and Chief Executive Officer	February 12, 2026
	(William J. Fehrman)
(ii)	Principal Financial Officer:
	/s/  Trevor I. Mihalik	Executive Vice President and Chief Financial Officer	February 12, 2026
	(Trevor I. Mihalik)
(iii)	Principal Accounting Officer:
	/s/  Kate Dixon	Senior Vice President, Controller and Chief Accounting Officer	February 12, 2026
	(Kate Dixon)
(iv)	A Majority of the Directors:
	/s/ William J. Fehrman
	*Benjamin G.S. Fowke, III
	*Art A. Garcia
	*Hunter C. Gary
	*Sandra Beach Lin
	*Henry P. Linginfelter
	*Margaret M. McCarthy
	*Daryl Roberts
	*Joseph G. Sauvage
	*Daniel G. Stoddard
	*Sara Martinez Tucker
	*Lewis Von Thaer
*By:	/s/   Trevor I. Mihalik		February 12, 2026
	(Trevor I. Mihalik, Attorney-in-Fact)

343

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.  The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

AEP Texas Inc.
By:	/s/  Trevor I. Mihalik
	(Trevor I. Mihalik, Vice President and Chief Financial Officer)

Date: February 12, 2026

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.  The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature		Title	Date
(i)	Principal Executive Officer:
	/s/  William J. Fehrman	Chair of the Board, Chief Executive Officer and Director	February 12, 2026
	(William J. Fehrman)
(ii)	Principal Financial Officer:
	/s/  Trevor I. Mihalik	Vice President, Chief Financial Officer and Director	February 12, 2026
	(Trevor I. Mihalik)
(iii)	Principal Accounting Officer:
	/s/  Kate Dixon	Chief Accounting Officer	February 12, 2026
	(Kate Dixon)
(iv)	A Majority of the Directors:
	*Robert B. Berntsen
	*William J. Fehrman
	*Judith E. Talavera
	Trevor I. Mihalik
*By:	/s/  Trevor I. Mihalik		February 12, 2026
	(Trevor I. Mihalik, Attorney-in-Fact)

344

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.  The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

AEP Transmission Company, LLC
By:	/s/  Trevor I. Mihalik
	(Trevor I. Mihalik, Vice President and Chief
	Financial Officer)

Date: February 12, 2026

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.  The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature		Title	Date
(i)	Principal Executive Officer:
	/s/  William J. Fehrman	Chair of the Board, Chief Executive Officer and Manager	February 12, 2026
	(William J. Fehrman)
(ii)	Principal Financial Officer:
	/s/  Trevor I. Mihalik	Vice President, Chief Financial Officer and Manager	February 12, 2026
	(Trevor I. Mihalik)
(iii)	Principal Accounting Officer:
	/s/  Kate Dixon	Chief Accounting Officer	February 12, 2026
	(Kate Dixon)
(iv)	A Majority of the Managers:
	*Robert B. Berntsen
	*William J. Fehrman
	Trevor I. Mihalik
*By:	/s/  Trevor I. Mihalik		February 12, 2026
	(Trevor I. Mihalik, Attorney-in-Fact)

345

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.  The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

Appalachian Power Company
By:	/s/  Trevor I. Mihalik
	(Trevor I. Mihalik, Vice President and Chief Financial Officer)

Date: February 12, 2026

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.  The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature		Title	Date
(i)	Principal Executive Officer:
	/s/  William J. Fehrman	Chair of the Board, Chief Executive Officer and Director	February 12, 2026
	(William J. Fehrman)
(ii)	Principal Financial Officer:
	/s/  Trevor I. Mihalik	Vice President, Chief Financial Officer and Director	February 12, 2026
	(Trevor I. Mihalik)
(iii)	Principal Accounting Officer:
	/s/  Kate Dixon	Chief Accounting Officer	February 12, 2026
	(Kate Dixon)
(iv)	A Majority of the Directors:
	*Robert B. Berntsen
	*William J. Fehrman
	*Aaron D. Walker
	Trevor I. Mihalik
*By:	/s/  Trevor I. Mihalik		February 12, 2026
	(Trevor I. Mihalik, Attorney-in-Fact)

346

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.  The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

Indiana Michigan Power Company
By:	/s/ Trevor I. Mihalik
	(Trevor I. Mihalik, Vice President and Chief
	Financial Officer)

Date: February 12, 2026

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.  The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature		Title	Date
(i)	Principal Executive Officer:
	/s/  William J. Fehrman	Chair of the Board, Chief Executive Officer and Director	February 12, 2026
	(William J. Fehrman)
(ii)	Principal Financial Officer:
	/s/  Trevor I. Mihalik	Vice President, Chief Financial Officer and Director	February 12, 2026
	(Trevor I. Mihalik)
(iii)	Principal Accounting Officer:
	/s/  Kate Dixon	Chief Accounting Officer	February 12, 2026
	(Kate Dixon)
(iv)	A Majority of the Directors:
	*Steven F. Baker
	*Robert B. Berntsen
	*William J. Fehrman
	Scott A. Huebner
	*Katherine K. Runkle
	*Stephanny L. Smith
	*Andrew J. Williamson
	Trevor I. Mihalik
*By:	/s/  Trevor I. Mihalik		February 12, 2026
	(Trevor I. Mihalik, Attorney-in-Fact)

347

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.  The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

Ohio Power Company
By:	/s/  Trevor I. Mihalik
	(Trevor I. Mihalik, Vice President and Chief Financial Officer)

Date: February 12, 2026

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.  The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature		Title	Date
(i)	Principal Executive Officer:
	/s/  William J. Fehrman	Chair of the Board, Chief Executive Officer and Director	February 12, 2026
	(William J. Fehrman)
(ii)	Principal Financial Officer:
	/s/  Trevor Mihalik	Vice President, Chief Financial Officer and Director	February 12, 2026
	(Trevor I. Mihalik)
(iii)	Principal Accounting Officer:
	/s/  Kate Dixon	Chief Accounting Officer	February 12, 2026
	(Kate Dixon)
(iv)	A Majority of the Directors:
	*Robert B. Berntsen
	*William J. Fehrman
	*Marc D. Reitter
	Trevor I. Mihalik
*By:	/s/  Trevor I. Mihalik		February 12, 2026
	(Trevor I. Mihalik, Attorney-in-Fact)

348

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.  The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

Public Service Company of Oklahoma
By:	/s/  Trevor I. Mihalik
	(Trevor I. Mihalik, Vice President and Chief Financial Officer)

Date: February 12, 2026

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.  The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature		Title	Date
(i)	Principal Executive Officer:
	/s/  William J. Fehrman	Chair of the Board, Chief Executive Officer and Director	February 12, 2026
	(William J. Fehrman)
(ii)	Principal Financial Officer:
	/s/  Trevor I. Mihalik	Vice President, Chief Financial Officer and Director	February 12, 2026
	(Trevor I. Mihalik)
(iii)	Principal Accounting Officer:
	/s/  Kate Dixon	Chief Accounting Officer	February 12, 2026
	(Kate Dixon)
(iv)	A Majority of the Directors:
	*Robert B. Berntsen
	*William J. Fehrman
	*Leigh Anne Strahler
	Trevor I. Mihalik
*By:	/s/  Trevor I. Mihalik		February 12, 2026
	(Trevor I. Mihalik, Attorney-in-Fact)

349

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.  The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

Southwestern Electric Power Company
By:	/s/  Trevor I. Mihalik
	(Trevor I. Mihalik, Vice President and Chief Financial Officer)

Date: February 12, 2026

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.  The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature		Title	Date
(i)	Principal Executive Officer:
	/s/  William J. Fehrman	Chair of the Board, Chief Executive Officer and Director	February 12, 2026
	(William J. Fehrman)
(ii)	Principal Financial Officer:
	/s/  Trevor I. Mihalik	Vice President, Chief Financial Officer and Director	February 12, 2026
	(Trevor I. Mihalik)
(iii)	Principal Accounting Officer:
	/s/  Kate Dixon	Chief Accounting Officer	February 12, 2026
	(Kate Dixon)
(iv)	A Majority of the Directors:
	*Robert B. Berntsen
	*William J. Fehrman
	*D. Brett Mattison
	Trevor I. Mihalik
*By:	/s/  Trevor I. Mihalik		February 12, 2026
	(Trevor I. Mihalik, Attorney-in-Fact)

350

INDEX OF FINANCIAL STATEMENT SCHEDULES

	Page Number
The following financial statement schedules are included in this report on the pages indicated:
American Electric Power Company, Inc. (Parent):
Schedule I – Condensed Financial Information	S-2
Schedule I – Condensed Notes to Condensed Financial Information	S-6
American Electric Power Company, Inc. and Subsidiary Companies:
Schedule II – Valuation and Qualifying Accounts and Reserves	S-9

S-1

SCHEDULE I

AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)

CONDENSED FINANCIAL INFORMATION

CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE 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
Revenues	$	7	$	6	$	5
TOTAL REVENUES	7		6		5
EXPENSES
Other Operation	35		66		17
Depreciation and Amortization	1		1		1
Amortization of KPCo Basis Difference	(21)		(21)		(17)
TOTAL EXPENSES	15		46		1
OPERATING INCOME (LOSS)	(8)		(40)		4
Other Income (Expense):
Interest Income	102		108		181
Interest Expense	(548)		(532)		(526)
LOSS BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS	(454)		(464)		(341)
Income Tax Expense (Benefit)	(126)		(151)		(81)
Equity Earnings of Unconsolidated Subsidiaries	3,908		3,280		2,468
NET INCOME	3,580		2,967		2,208
Other Comprehensive Income (Loss)	39		52		(139)
TOTAL COMPREHENSIVE INCOME	$	3,619	$	3,019	$	2,069
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 Condensed Notes to Condensed Financial Information beginning on page S-6.

S-2

SCHEDULE I

AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)

CONDENSED FINANCIAL INFORMATION

CONDENSED BALANCE SHEETS

ASSETS

December 31, 2025 and 2024

(in millions)

	December 31,
	2025		2024
CURRENT ASSETS
Cash and Cash Equivalents	$	103	$	88
Advances to Affiliates	1,879		1,945
Accounts Receivable:
Affiliated Companies	23		33
Total Accounts Receivable	23		33
Prepayments and Other Current Assets	75		107
TOTAL CURRENT ASSETS	2,080		2,173
PROPERTY, PLANT AND EQUIPMENT
General	3		3
Total Property, Plant and Equipment	3		3
Accumulated Depreciation, Depletion and Amortization	2		1
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	1		2
OTHER NONCURRENT ASSETS
Investments in Unconsolidated Subsidiaries	39,550		35,306
Affiliated Notes Receivable	1,105		105
Deferred Charges and Other Noncurrent Assets	245		184
TOTAL OTHER NONCURRENT ASSETS	40,900		35,595
TOTAL ASSETS	$	42,981	$	37,770
See Condensed Notes to Condensed Financial Information beginning on page S-6.

S-3

SCHEDULE I

AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)

CONDENSED FINANCIAL INFORMATION

CONDENSED BALANCE SHEETS

LIABILITIES AND EQUITY

December 31, 2025 and 2024

(dollars in millions)

			December 31,
			2025		2024
CURRENT LIABILITIES
Advances from Affiliates			$	887	$	507
Accounts Payable:
General			1		5
Affiliated Companies			5		2
Short-term Debt			605		1,618
Long-term Debt Due Within One Year – Nonaffiliated			50		1,282
Accrued Interest			129		104
Other Current Liabilities			47		98
TOTAL CURRENT LIABILITIES			1,724		3,616
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			10,050		7,124
Deferred Credits and Other Noncurrent Liabilities			31		48
TOTAL NONCURRENT LIABILITIES			10,081		7,172
TOTAL LIABILITIES			11,805		10,788
Contingently Redeemable Performance Share Awards			38		38
COMMON SHAREHOLDERS’ 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)			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
TOTAL LIABILITIES AND EQUITY			$	42,981	$	37,770

See Condensed Notes to Condensed Financial Information beginning on page S-6.

S-4

SCHEDULE I

AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)

CONDENSED FINANCIAL INFORMATION

CONDENSED 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	$	3,580	$	2,967	$	2,208
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	1		1		1
Amortization of KPCo Basis Difference	(21)		(21)		(17)
Deferred Income Taxes	(12)		(53)		60
Equity Earnings of Unconsolidated Subsidiaries	(3,908)		(3,280)		(2,468)
Cash Dividends Received from Unconsolidated Subsidiaries	3,483		1,143		686
Change in Other Noncurrent Assets	(3)		5		(28)
Change in Other Noncurrent Liabilities	61		71		92
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	10		18		29
Accounts Payable	(1)		(17)		(16)
Other Current Assets	10		—		(4)
Other Current Liabilities	10		55		(14)
Net Cash Flows from Operating Activities	3,210		889		529
INVESTING ACTIVITIES
Construction Expenditures	(48)		(1)		(1)
Change in Advances to Affiliates, Net	66		60		2,008
Investment in Equity Method Investments	(100)		—		—
Capital Contributions to Unconsolidated Subsidiaries	(1,869)		(400)		(790)
Return of Capital Contributions from Unconsolidated Subsidiaries	—		899		57
Issuance of Notes Receivable to Unconsolidated Subsidiaries	(1,000)		—		(210)
Repayment of Notes Receivable from Unconsolidated Subsidiaries	—		190		—
Net Cash Flows from (Used for) Investing Activities	(2,951)		748		1,064
FINANCING ACTIVITIES
Issuance of Common Stock, Net	775		552		1,000
Issuance of Long-term Debt	2,966		1,285		1,830
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	(655)		(172)		(1,365)
Retirement of Long-term Debt	(1,300)		(1,104)		(1,050)
Change in Advances from Affiliates, Net	380		(222)		(192)
Redemption of Short-term Debt with Original Maturities Greater Than 90 Days	(678)		(871)		(1,129)
Dividends Paid on Common Stock	(2,008)		(1,898)		(1,752)
Other Financing Activities	(44)		(41)		(61)
Net Cash Flows Used for Financing Activities	(244)		(1,747)		(1,649)
Net Increase (Decrease) in Cash and Cash Equivalents	15		(110)		(56)
Cash and Cash Equivalents at Beginning of Period	88		198		254
Cash and Cash Equivalents at End of Period	$	103	$	88	$	198
See Condensed Notes to Condensed Financial Information beginning on page S-6.

S-5

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The condensed financial information of Parent is required as a result of the restricted net assets of AEP consolidated subsidiaries exceeding 25% of AEP consolidated net assets as of December 31, 2025.  Parent is a public utility holding company that owns all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries, including joint ventures and equity investments.  The primary source of income for Parent is equity in its subsidiaries’ earnings.  Its major source of cash is dividends from its wholly-owned subsidiaries, which are evaluated for cash flow presentation based on the nature of the distribution.  Parent borrows the funds for the money pool that is used by the subsidiaries for their short-term cash needs. Parent financial statements should be read in conjunction with the AEP consolidated financial statements and the accompanying notes thereto. For purposes of these condensed financial statements, AEP wholly-owned and majority-owned subsidiaries are recorded based upon its proportionate share of the subsidiaries’ net assets (similar to presenting them on the equity method).

Income Taxes

Parent files a consolidated federal income tax return with its subsidiaries. The benefit of current tax loss of the parent company (Parent Company Loss Benefit) to the AEP System subsidiaries is accounted for as an allocation through equity. The consolidated NOL of the AEP System is allocated to each company in the consolidated group with taxable loss. With the exception of the allocation of the consolidated AEP System NOL, Parent Company Loss Benefit and general business tax credits, the method of allocation reflects a separate return result for each company in the consolidated group.

2.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

Parent and its subsidiaries are parties to environmental and other legal matters. For further discussion, see Note 6 - Commitments, Guarantees and Contingencies.

S-6

3.  FINANCING ACTIVITIES

The following details long-term debt outstanding as of December 31, 2025 and 2024:

Long-term Debt

		Weighted-Average	Interest Rate Ranges as of		Outstanding as of
		Interest Rate as of	December 31,		December 31,
Type of Debt	Maturity	December 31, 2025	2025	2024	2025		2024
					(in millions)
Senior Unsecured Notes	2027-2050	4.58%	1.80%-5.95%	1.00%-5.95%	$	4,882	$	5,290
Pollution Control Bonds	2026-2029 (a)	3.12%	2.40%-3.75%	2.40%-3.75%	537		537
Junior Subordinated Notes	2027-2054	5.83%	3.88%-7.05%	3.88%-7.05%	4,681		2,579
Total Long-term Debt Outstanding					10,100		8,406
Long-term Debt Due Within One Year					50		1,282
Long-term Debt					$	10,050	$	7,124

(a)Certain Pollution Control Bonds are subject to redemption earlier than the maturity date.

Long-term debt outstanding as of December 31, 2025 is payable as follows:

	2026		2027		2028		2029		2030		After 2030		Total
	(in millions)
Principal Amount (a)	$	50	$	1,774	$	930	$	1,695	$	400	$	5,350	$	10,199
Unamortized Discount, Net and Debt Issuance Costs													(99)
Total Long-term Debt Outstanding													$	10,100

(a)Amounts reflect the impact of fair value hedge accounting. See “Accounting for Fair Value Hedging Strategies” section of Note 10 included in the 2025 Annual Report for additional information.

Short-term Debt

Parent’s outstanding short-term debt was as follows:

	December 31, 2025				December 31, 2024
Type of Debt	Outstanding Amount		Weighted-Average Interest Rate		Outstanding Amount		Weighted-Average Interest Rate
	(in millions)				(in millions)
Commercial Paper	$	605	3.92	%	$	1,618	4.70	%
Total Short-term Debt	$	605			$	1,618

S-7

4.  RELATED PARTY TRANSACTIONS

Payments on Behalf of Subsidiaries

Due to occasional time sensitivity and complexity of payments, Parent makes certain insurance, tax and benefit payments on behalf of subsidiary companies.  Parent is then fully reimbursed by the subsidiary companies.

Short-term Lending to Subsidiaries

Parent uses a commercial paper program to meet the short-term borrowing needs of subsidiaries.  The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain nonutility subsidiaries.  In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons.  The program also allows some direct borrowers to invest excess cash with Parent.

Interest expense related to Parent’s short-term borrowing is included in Interest Expense on Parent’s statements of income.  Parent incurred interest expense for amounts borrowed from subsidiaries of $31 million, $28 million and $33 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Interest income related to Parent’s short-term lending is included in Interest Income on Parent’s statements of income.  Parent earned interest income for amounts advanced to subsidiaries of $88 million, $84 million and $164 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Affiliated Notes

Parent issued long-term debt, portions of which were loaned to its subsidiaries.  Parent pays interest on the affiliated notes, but the subsidiaries accrue interest for their share of the affiliated borrowing and remit the interest to Parent.  Interest income related to Parent’s loans to subsidiaries is included in Interest Income on Parent’s statements of income.  Parent earned interest income on loans to subsidiaries of $7 million, $7 million and $6 million for the years ended December 31, 2025, 2024 and 2023, respectively.

S-8

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

AEP			Additions
Description	Balance at  Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts (a)		Deductions (b)		Balance at End of Period
	(in millions)
Deducted from Assets:
Allowance for Credit Losses:
Year Ended December 31, 2025	$	61	$	50	$	2	$	61	$	52
Year Ended December 31, 2024	60		45		3		47		61
Year Ended December 31, 2023	57		15		—		12		60

(a)Recoveries offset by reclasses to other assets and liabilities.

(b)Uncollectible accounts written off.

Schedule II for the Registrant Subsidiaries is not presented because the amounts are not material.

S-9

INDEX OF AEP TRANSMISSION COMPANY, LLC (AEPTCO PARENT)

FINANCIAL STATEMENT SCHEDULES

	Page Number
The following financial statement schedules are included in this report on the pages indicated:
AEP Transmission Company, LLC (AEPTCo Parent):
Schedule I – Condensed Financial Information	S-11
Schedule I – Condensed Notes to Condensed Financial Information	S-15

S-10

SCHEDULE I

AEP TRANSMISSION COMPANY, LLC (AEPTCo Parent)

CONDENSED FINANCIAL INFORMATION

CONDENSED STATEMENTS OF INCOME

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

(in millions)

	Years Ended December 31,
	2025		2024		2023
EXPENSES
Other Operation	$	—	$	2	$	—
TOTAL EXPENSES	—		2		—
OPERATING LOSS	—		(2)		—
Other Income (Expense):
Interest Income - Affiliated	308		241		218
Interest Expense	(257)		(239)		(215)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS OF UNCONSOLIDATED SUBSIDIARIES	51		—		3
Income Tax Expense	11		—		2
Equity Earnings of Unconsolidated Subsidiaries	1,035		688		613
NET INCOME	$	1,075	$	688	$	614
See Condensed Notes to Condensed Financial Information beginning on page S-15.

S-11

SCHEDULE I

AEP TRANSMISSION COMPANY, LLC (AEPTCo Parent)

CONDENSED FINANCIAL INFORMATION

CONDENSED BALANCE SHEETS

ASSETS

December 31, 2025 and 2024

(in millions)

	December 31,
	2025		2024
CURRENT ASSETS
Advances to Affiliates	$	70	$	20
Accounts Receivable:
General	32		—
Affiliated Companies	65		62
Total Accounts Receivable	97		62
Notes Receivable - Affiliated	425		90
TOTAL CURRENT ASSETS	592		172
OTHER NONCURRENT ASSETS
Notes Receivable - Affiliated	6,174		8,498
Investments in Unconsolidated Subsidiaries	6,690		4,273
TOTAL OTHER NONCURRENT ASSETS	12,864		12,771
TOTAL ASSETS	$	13,456	$	12,943
See Condensed Notes to Condensed Financial Information beginning on page S-15.

S-12

SCHEDULE I

AEP TRANSMISSION COMPANY, LLC (AEPTCo Parent)

CONDENSED FINANCIAL INFORMATION

CONDENSED BALANCE SHEETS

LIABILITIES AND EQUITY

December 31, 2025 and 2024

(in millions)

	December 31,
	2025		2024
CURRENT LIABILITIES
Accounts Payable:
General	$	81	$	69
Affiliated Companies	112		95
Long-term Debt Due Within One Year – Nonaffiliated	425		90
Accrued Interest	46		45
Other Current Liabilities	5		15
TOTAL CURRENT LIABILITIES	669		314
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	6,174		5,678
TOTAL NONCURRENT LIABILITIES	6,174		5,678
TOTAL LIABILITIES	6,843		5,992
MEMBER’S EQUITY
Paid-in Capital	4,962		3,101
Retained Earnings	1,651		3,850
TOTAL MEMBER’S EQUITY	6,613		6,951
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	13,456	$	12,943
See Condensed Notes to Condensed Financial Information beginning on page S-15.

S-13

SCHEDULE I

AEP TRANSMISSION COMPANY, LLC (AEPTCo Parent)

CONDENSED FINANCIAL INFORMATION

CONDENSED 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	$	1,075	$	688	$	614
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Equity Earnings of Unconsolidated Subsidiaries	(1,035)		(688)		(613)
Change in Other Noncurrent Assets	—		—		4
Change in Other Noncurrent Liabilities	7		4		12
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(35)		10		(38)
Accounts Payable	29		13		37
Accrued Interest	1		6		11
Other Current Liabilities	(9)		34		(31)
Net Cash Flows from (Used for) Operating Activities	33		67		(4)
INVESTING ACTIVITIES
Change in Advances to Affiliates, Net	(50)		(20)		—
Repayment of Notes Receivable from Affiliated Companies	2,922		95		60
Issuance of Notes Receivable to Affiliated Companies	(936)		(450)		(700)
Return of Capital Contributions from Unconsolidated Subsidiaries	739		133		184
Capital Contributions to Subsidiaries	(189)		(62)		(30)
Net Cash Flows from (Used for) Investing Activities	2,486		(304)		(486)
FINANCING ACTIVITIES
Capital Contributions from Member	70		62		30
Return of Capital to Member	—		(5)		(9)
Issuance of Long-term Debt – Nonaffiliated	929		446		689
Retirement of Long-term Debt – Nonaffiliated	(102)		(95)		(60)
Change in Advances from Affiliates, Net	—		(43)		15
Dividends Paid	(3,379)		(128)		(175)
Other Financing Activities	(37)		—		—
Net Cash Flows from (Used for) Financing Activities	(2,519)		237		490
Net Change in Cash and Cash Equivalents	—		—		—
Cash and Cash Equivalents at Beginning of Period	—		—		—
Cash and Cash Equivalents at End of Period	$	—	$	—	$	—
See Condensed Notes to Condensed Financial Information beginning on page S-15.

S-14

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The condensed financial information of AEPTCo Parent is required as a result of the restricted net assets of AEPTCo consolidated subsidiaries exceeding 25% of AEPTCo consolidated net assets as of December 31, 2025.  AEPTCo Parent is the direct holding company for the seven State Transcos.  The primary source of income for AEPTCo Parent is equity in its subsidiaries’ earnings. AEPTCo Parent financial statements should be read in conjunction with the AEPTCo consolidated financial statements and the accompanying notes thereto. For purposes of these condensed financial statements, AEPTCo wholly-owned and majority-owned subsidiaries are recorded based upon its proportionate share of the subsidiaries’ net assets (similar to presenting them on the equity method).

Income Taxes

AEPTCo Parent joins in the filing of a consolidated federal income tax return with its affiliates in the AEP System. The benefit of current tax loss of the parent company (Parent Company Loss Benefit) to the AEP System subsidiaries is accounted for as an allocation through equity. The consolidated NOL of the AEP System is allocated to each company in the consolidated group with taxable loss. With the exception of the allocation of the consolidated AEP System NOL, Parent Company Loss Benefit and general business tax credits, the method of allocation reflects a separate return result for each company in the consolidated group.

Noncontrolling Interest in Midwest Transmission Holdings

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. See Note 4 - Related Party Transactions for additional information.

2.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

AEPTCo Parent and its subsidiaries are parties to legal matters.  For further discussion, see Note 6 - Commitments, Guarantees and Contingencies.

3.  FINANCING ACTIVITIES

For discussion of Financing Activities, see Note 15 - Financing Activities to AEPTCo’s audited consolidated financial statements.

4.  RELATED PARTY TRANSACTIONS

Payments on Behalf of Subsidiaries

Due to occasional time sensitivity and complexity of payments, Parent makes certain insurance, tax and other payments on behalf of subsidiary companies.  Parent is then fully reimbursed by the subsidiary companies. AEPTCo Parent also makes convenience payments on behalf of its State Transcos. AEPTCo Parent is then fully reimbursed by its State Transcos.

Long-term Lending to Subsidiaries

AEPTCo Parent enters into debt arrangements with nonaffiliated entities. AEPTCo Parent has long-term debt of $6.6 billion and $5.8 billion as of December 31, 2025 and 2024, respectively. AEPTCo Parent uses the proceeds from these nonaffiliated debt arrangements to make affiliated loans to its State Transcos using the same interest rates and maturity dates as the nonaffiliated debt arrangements. AEPTCo Parent has recorded Notes Receivable – Affiliated of $6.6 billion and $8.6 billion as of December 31, 2025 and 2024, respectively. Related to these nonaffiliated and affiliated debt arrangements, AEPTCo Parent has recorded Accrued Interest of $46 million and $45 million as of December 31, 2025 and 2024, respectively. AEPTCo Parent has also recorded Accounts Receivable – Affiliated Companies of $65 million and $62 million as of December 31, 2025 and 2024, respectively. AEPTCo Parent has recorded Interest Income – Affiliated of $306 million, $238 million and $215 million for the years ended December 31, 2025, 2024 and 2023, respectively, related to Notes Receivable – Affiliated. AEPTCo Parent has recorded Interest Expense of $252 million, $238 million and $215 million for the years ended December 31, 2025, 2024 and 2023, respectively, related to the nonaffiliated debt arrangements.

S-15

Short-term Lending to Subsidiaries

Parent uses a commercial paper program to meet the short-term borrowing needs of subsidiaries.  The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain nonutility subsidiaries.  In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons.  The program also allows some direct borrowers to invest excess cash with Parent.

Interest expense related to AEPTCo Parent’s short-term borrowing is included in Interest Expense on AEPTCo Parent’s statements of income.  AEPTCo Parent incurred immaterial interest expense for amounts borrowed from AEP affiliates for the years ended December 31, 2025, 2024 and 2023.

Interest income related to AEPTCo Parent’s short-term lending is included in Interest Income – Affiliated on AEPTCo Parent’s statements of income.  AEPTCo Parent earned interest income for amounts advanced to AEP affiliates of $2 million, $3 million and $3 million for the years ended December 31, 2025, 2024 and 2023, respectively.

S-16

EXHIBIT INDEX

The documents listed below are being filed or have previously been filed on behalf of the Registrants shown and are incorporated herein by reference to the documents indicated and made a part hereof.  Exhibits (“Ex”) not identified as previously filed are filed herewith.  Exhibits designated with a dagger (†) are management contracts or compensatory plans or arrangements required to be filed as an Exhibit to this Form.  Exhibits designated with an asterisk (*) are filed herewith.

Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:
AEP‡   File No. 1-3525
3(a)	Composite of the Restated Certificate of Incorporation of AEP, dated April 26, 2022.	2023 Form 10-K, Ex 3(a)
3(b)	Composite By-Laws of AEP amended as of April 25, 2023.	Form 8-K, Ex 3(b) filed April 28, 2023
*†3(b)1	Amended By-Laws of AEP, as amended December 22, 2025 and effective July 1, 2026.
4(a)	Indenture (for unsecured debt securities), dated as of May 1, 2001, between AEP and The Bank of New York, as Trustee.	Registration Statement No. 333-86050, Ex 4(a)(b)(c) Registration Statement No. 333-105532, Ex 4(d)(e)(f) Registration Statement No. 333-200956, Ex 4(b) Registration Statement No. 333-222068, Ex 4(b) Registration Statement No. 333-249918, Ex 4(b)(c) Registration Statement No. 333-275345, Ex 4(b)(c)(d)
4(a)1	Company Order and Officer’s Certificate between AEP and The Bank of New York Mellon Trust Company, N.A. as Trustee dated December 8, 2023 establishing terms of the 5.20% Senior Notes, Series R due 2029.	Form 8-K, Ex. 4(a) filed December 8, 2023
4(b)	Junior Subordinated Indenture, dated March 1, 2008, between AEP and The Bank of New York Mellon Trust Company, N.A., as Trustee for the Junior Subordinated Debentures.	Registration Statement No. 333-156387, Ex 4(c)(d) Registration Statement No. 333-249918, Ex 4(f)(g)
4(b)1	Supplemental Indenture No. 6 between AEP and The Bank of New York Mellon Trust Company, N.A., as Trustee, dated June 20, 2024, establishing the terms of 7.050% Fixed-to-Fixed Reset Rate Junior Subordinated Debentures, Series A, due 2054 and the 6.950% Fixed-to-Fixed Reset Rate Junior Subordinated Debentures, Series B, due 2054.	Form 8-K Ex 4(a) filed June 20, 2024
4(b)2	Supplemental Indenture No. 7 between AEP and The Bank of New York Mellon Trust Company, N.A., as Trustee, dated September 25, 2025, establishing the terms of 5.80% Fixed-to-Fixed Reset Rate Junior Subordinated Debentures, Series C, due 2056 and the 6.050% Fixed-to-Fixed Reset Rate Junior Subordinated Debentures, Series D, due 2056.	Form 8-K Ex 4(a) filed September 23, 2025
4(b)3	Amended and Restated Supplemental Indenture No. 7 between AEP and The Bank of New York Mellon Trust Company, N.A., as Trustee, dated December 5, 2025, establishing the terms of 5.80% Fixed-to-Fixed Reset Rate Junior Subordinated Debentures, Series C, due 2056 and the 6.050% Fixed-to-Fixed Reset Rate Junior Subordinated Debentures, Series D, due 2056.	Form 8-K Ex 4(a) filed December 3, 2025

E-1

Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:
4(c)	$4,000,000,000 Credit Agreement dated March 31, 2021 among AEP, Initial Lenders and Wells Fargo Bank National Association as Administrative Agent.	Form 10-Q Ex 4.2, March 31, 2021
4(c)1	April 7, 2022 Amendment and extension to $4,000,000,000 Credit Agreement dated March 31, 2021 among AEP, Initial Lenders and Wells Fargo Bank National Association as Administrative Agent.	Form 10-Q Ex 4(a), March 31, 2022
4(c)2	March 28, 2024 Amendment and extension to $5,000,000,000 of the $4,000,000,000 Credit Agreement dated March 31, 2021 among AEP, Initial Lenders and Wells Fargo Bank National Association as Administrative Agent.	Form 10-Q Ex 4(d), March 31, 2024
4(d)	$1,000,000,000 Credit Agreement dated March 31, 2021 among AEP, Initial Lenders and Wells Fargo Bank National Association as Administrative Agent.	Form 10-Q Ex 4.3, March 31, 2021
4(d)1	April 7, 2022 Amendment and extension to $1,000,000,000 Credit Agreement dated March 31, 2021 among AEP, Initial Lenders and Wells Fargo Bank National Association as Administrative Agent.	Form 10-Q Ex 4(b), March 31, 2022
4(d)2	March 31, 2023 Amendment and extension to $1,000,000,000 Credit Agreement dated March 31, 2021 among AEP, Initial Lenders and Wells Fargo Bank National Association as Administrative Agent.	Form 10-Q Ex 4(b), March 31, 2023
4(d)3	March 28, 2024 Amendment and extension to $1,000,000,000 Credit Agreement dated March 31, 2021 among AEP, Initial Lenders and Wells Fargo Bank National Association as Administrative Agent.	Form 10-Q Ex 4(c), March 31, 2024
4(e)1	Distribution Agreement, dated November 25, 2025, among AEP and Barclays Capital Inc., BofA Securities, Inc., Citigroup Global Markets Inc., J.P. Morgan Securities LLC, Mizuho Securities USA LLC, MUFG Securities Americas Inc., Scotia Capital (USA) Inc., Wells Fargo Securities LLC, Barclays Bank PLC, Bank of America, N.A., Citibank N.A, J.P. Morgan Chase Bank, National Association, Mizuho Markets Americas LLC, MUFG Securities EMEA plc, The Bank of Nova Scotia and Wells Fargo Bank, National Association.	Form 8-K Ex 1.1 filed November 25, 2025
4(f)	Description of Securities.	2020 Form 10-K, Ex 4(c)
10(a)	Consent Decree with U.S. District Court dated October 9, 2007, as modified July 17, 2019.	Form 8-K, Ex. 10 filed October 9, 2007 Form 10-Q, Ex 10, June 30, 2013 Form 10-Q, Ex 10, June 30, 2019
†10(b)	AEP Retainer Deferral Plan for Non-Employee Directors, as Amended and Restated effective October 1, 2020.	Form 10-Q, Ex 10.2, September 30, 2020
†10(c)	AEP Stock Unit Accumulation Plan for Non-Employee Directors as amended October 1, 2020.	Form 10-Q, Ex 10.3, September 30, 2020

E-2

Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:
†10(c)1	AEP Stock Unit Accumulation Plan for Non-Employee Directors as amended June 1, 2022.	2021 Form 10-K, Ex 10(d)1
†10(d)	AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2020.	2019 Form 10-K, Ex 10(e)
†10(d)1	Guaranty by AEP of AEPSC Excess Benefits Plan.	1990 Form 10-K, Ex 10(h)(1)(B)
†10(e)	AEP System Supplemental Retirement Savings Plan, Amended and Restated as of October 6, 2021 (Non-Qualified).	2022 Form 10-K, Ex 10(e)
†10(f)	AEPSC Umbrella Trust for Executives.	1993 Form 10-K, Ex 10(g)(3)
†10(f)1A	First Amendment to AEPSC Umbrella Trust for Executives.	2008 Form 10-K, Ex 10(l)(3)(A)
†10(f)2A	Second Amendment to AEPSC Umbrella Trust for Executives.	2018 Form 10-K, Ex 10(g)(2)(A)
†10(g)	AEP System Incentive Compensation Deferral Plan Amended and Restated as of June 1, 2019.	Form 10-Q, Ex 10(1), September 30, 2019
†10(h)	AEP Change In Control Agreement, as Revised Effective January 1, 2017.	Form 10-Q, Ex 10(c), September 30, 2016
†10(i)	AEP System Long-Term Incentive Plan effective as of April 23, 2024	Form 10-Q Ex 10(c), March 31, 2024
†10(i)1A	Performance Share Award Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.	Form 10-Q, Ex 10(a), March 30, 2018
†10(i)2A	Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan as Amended and Restated effective January 1, 2022.	2022 Form 10-K, Ex 10(i)2A
†10(j)	AEP System Stock Ownership Requirement Plan Amended and Restated effective October 1, 2020.	Form 10-Q, Ex 10.1, September 30, 2020
†10(k)	Central and South West System Special Executive Retirement Plan Amended and Restated effective January 1, 2020.	2019 Form 10-K, Ex 10(l)
†10(l)	AEP Executive Severance Plan Amended and Restated effective July 15, 2024.	Form 10-Q Ex 10(a), June 30, 2024
*†10(l)(1)	First Amendment to the AEP Executive Severance Plan effective February 17, 2025.
†10(m)	AEP Aircraft Timesharing Agreement dated July 16, 2024 between AEPSC and William J. Fehrman.	Form 10-Q Ex 10(a), September 30, 2024
†10(m)(1)	AEP Amended and Restated Aircraft Time Sharing Agreement dated May 5, 2025 between AEPSC and William J. Fehrman.	Form 10-Q Ex 10(a), March 31, 2025
*†10(n)	AEP Board Observer Agreement effective December 22, 2025.
10(o)	Confirmation of Forward Sale Transaction, dated March 24, 2025, between AEP and Citibank, N.A. in capacity as a Forward Purchase.	Form 8-K, Ex 10.1 filed March 26, 2025

E-3

Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:
10(o)(1)	Confirmation of Forward Sale Transaction, dated March 24, 2025, between AEP and Barclays Bank PLC in capacity as a Forward Purchase.	Form 8-K, Ex 10.2 filed March 26, 2025
10(o)(2)	Confirmation of Forward Sale Transaction, dated March 25, 2025, between AEP and Citibank, N.A. in capacity as a Forward Purchase.	Form 8-K, Ex 10.3 filed March 26, 2025
10(o)(3)	Confirmation of Forward Sale Transaction, dated March 25, 2025, between AEP and Barclays Bank PLC in capacity as a Forward Purchase.	Form 8-K, Ex 10.4 filed March 26, 2025
*†10(p)	Severance, Release of All Claims, and Non-Competition Agreement by and between AEP and David M. Feinberg.
19.1	AEP Insider Trading Policy.	2024 Form 10-K, Ex 19
*21	List of subsidiaries of AEP.
*23	Consent of PricewaterhouseCoopers LLP.
*24	Power of Attorney.
*31(a)	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31(b)	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32(a)	Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
*32(b)	Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
97	AEP Policy on Recouping Incentive Compensation	2023 Form-10-K, Ex 97
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AEP TEXAS‡   File No. 333-221643
3(a)	Composite of the Restated Certificate of Incorporation, as amended.	Registration Statement No. 333-221643, Ex 3(a)
3(b)	Bylaws.	Registration Statement No. 333-221643, Ex 3(b)

E-4

Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:
4(a)	Indenture, dated as of September 1, 2017, between AEP Texas and The Bank of New York Mellon Trust Company, N.A., as Trustee.	Registration Statement No. 333-221643, Ex 4(a)-1,4(a)-2 Registration Statement No. 333-228657, Ex 4(a)-4,4(a)-5 Registration Statement No. 333-230613, Ex 4(a)(b) Registration Statement No. 333-253585, Ex 4(b)(c)(d) Registration Statement No. 333-279418 Ex 4(b)(c)(d)
4(b)	Company Order and Officer’s Certificate between AEP Texas and The Bank of New York Mellon Trust Company, N.A., as Trustee dated May 22, 2024, establishing terms of the 5.45% Senior Notes, Series N due 2029 and 5.70% Senior Notes, Series O due 2034.	Form 8-K, Ex 4(a) filed May 22, 2024
4(b)(1)	Company Order and Officer’s Certificate between AEP Texas and The Bank of New York Mellon Trust Company, N.A., as Trustee dated September 24, 2025, establishing terms of the 5.70% Senior Notes, Series O due 2034 and 5.85% Senior Notes, Series P due 2055.	Form 8-K, Ex 4(a) filed September 22, 2025
*23	Consent of PricewaterhouseCoopers LLP.
*24	Power of Attorney.
*31(a)	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31(b)	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32(a)	Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
*32(b)	Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
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AEPTCo‡   File No. 333-217143
3(a)	Limited Liability Company Agreement of AEP Transmission Company, LLC dated as of January 27, 2006.	Registration Statement No. 333-217143, Ex 3(a)

E-5

Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:
3(b)	First Amendment to Limited Liability Company Agreement of AEPTCo dated as of May 21, 2013.	Registration Statement No. 333-217143, Ex 3(b)
4(a)	Indenture, dated as of November 1, 2016, between AEPTCo and The Bank of New York Mellon Trust Company, N.A., as Trustee.	Registration Statement No. 333-217143, Ex 4(a)-1, 4(a)-2 Registration Statement No. 333-225325, Ex 4(b)(c)(d) Registration Statement No. 333-255605, Ex 4(b)(c)(d)(e) Registration Statement No. 333-277662 Ex 4(b)(c)(d)
4(b)	Company Order and Officer’s Certificate between AEPTCo and The Bank of New York Mellon Trust Company, N.A., as Trustee, dated March 13, 2024 establishing terms of the 5.15% Senior Notes, Series Q due 2034.	Form 8-K Ex 4(a) filed March 13, 2024
4(b)(1)	Company Order and Officer’s Certificate between AEPTCo and The Bank of New York Mellon Trust Company, N.A., as Trustee, dated May 14, 2025, establishing terms of the Note.	Form 8-K, Ex 4(a) filed May 12, 2025
4(c)	Note Purchase Agreement, dated as of October 18, 2012 between AEPTCo and the Initial Purchasers.	Registration Statement No. 333-217143, Ex 4(c)-1
4(c)1	Supplement to Note Purchase Agreement, dated as of November 7, 2013 between AEPTCo and the Initial Purchasers.	Registration Statement No. 333-217143, Ex 4(c)-2
4(c)2	Supplement to Note Purchase Agreement, dated as of November 14, 2014 between AEP Transmission Company, LLC and the Initial Purchasers.	Registration Statement No. 333-217143, Ex 4(c)-3
4(d)	Note Purchase Agreement, dated October 15, 2025, by and among AEPTCo, the Secretary of Energy acting through the U.S. Department of Energy and the Federal Financing Bank.	Form 8-K, Ex 10.1 filed October 15, 2025
4(e)	Future Advance Promissory Note of AEPTCo dated October 15, 2025.	Form 8-K, Ex 10.2 filed October 15, 2025
10(a)	Stock Purchase Agreement dated as of October 26, 2021 among AEP, AEPTCo and Liberty Utilities Co.	Form 10-Q, Ex 10, September 30, 2021
10(a)1	First Amendment to Stock Purchase Agreement dated September 29, 2022 among AEP, AEPTCo and Liberty Utilities Co.	Form 10-Q, Ex 10, September 30, 2022
10(a)2	Second Amendment to Stock Purchase Agreement dated January 16, 2023 among AEP, AEPTCo and Liberty Utilities Co.	2023 Form 10-K, Ex 10(2)A
10(a)3	Mutual Termination Agreement dated and effective April 17, 2023 among AEP, AEPTCo and Liberty Utilities Co. terminating the Stock Purchase Agreement dated October 26, 2021 the First Amendment to the Stock Purchase Agreement, dated as of September 29, 2022, and the Second Amendment to the Stock Purchase Agreement, dated as of January 16, 2023.	Form 10-Q, Ex 10, June 30, 2023
10(b)	Contribution Agreement by and among AEPTCo, Midwest Transmission Company, LLC and Olympus BidCo L.P. dated as of January 9, 2025.	2024 Form 10-K, Ex 10(b)

E-6

Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:
10(b)(1)	Amended and Restated Limited Liability Company Agreement, dated June 5, 2025, among AEPTCo, Midwest Transmission Holdings, LLC and Olympus BidCo L.P.	Form 10-Q, Ex 10(a), June 30, 2025
10(c)	Loan Guarantee Agreement, dated October 15, 2025, by and between AEPTCo and the U.S. Department of Energy.	Form 8-K, Ex 10.3 filed October 15, 2025
*23	Consent of PricewaterhouseCoopers LLP.
*24	Power of Attorney.
*31(a)	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31(b)	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32(a)	Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
*32(b)	Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
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APCo‡   File No. 1-3457
3(a)	Composite of the Restated Articles of Incorporation of APCo, amended as of March 7, 1997.	1996 Form 10-K, Ex 3(d)
3(b)	Composite By-Laws of APCo, amended as of February 26, 2008.	2007 Form 10-K, Ex 3(b)

E-7

Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:
4(a)	Indenture (for unsecured debt securities), dated as of January 1, 1998, between APCo and The Bank of New York, As Trustee.	Registration Statement No. 333-45927, Ex 4(a)(b) Registration Statement No. 333-49071, Ex 4(b) Registration Statement No. 333-84061, Ex 4(b)(c) Registration Statement No. 333-100451, Ex 4(b) Registration Statement No. 333-116284, Ex 4(b)(c) Registration Statement No. 333-123348, Ex 4(b)(c) Registration Statement No. 333-136432, Ex 4(b)(c)(d) Registration Statement No. 333-161940, Ex 4(b)(c)(d) Registration Statement No. 333-182336, Ex 4(b)(c) Registration Statement No. 333-200750, Ex 4(b)(c) Registration Statement No. 333-214448, Ex 4(b) Registration Statement No. 333-236613, Ex 4(b)(c) Registration Statement No. 333-268874, Ex 4(b)(c)(d)(e) Registration Statement No. 333-290611, Ex 4(b)
4(b)	Company Order and Officer’s Certificate between APCo and The Bank of New York Mellon Trust Company, N.A., as Trustee, dated March 20, 2024 establishing terms of the 5.65% Senior Notes, Series CC due 2034.	Form 8-K Ex 4(a) filed March 20, 2024
10(a)	Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended September 10, 2010.	2013 Form 10-K, Ex 10(a)
10(b)	Consent Decree with U.S. District Court dated October 9, 2007, as modified July 17, 2019.	Form 8-K, Ex. 10 filed October 9, 2007 Form 10-Q, Ex 10, June 30, 2013 Form 10-Q, Ex 10, June 30, 2019
*23	Consent of PricewaterhouseCoopers LLP.
*24	Power of Attorney.
*31(a)	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31(b)	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32(a)	Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
*32(b)	Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
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E-8

Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:
I&M‡   File No. 1-3570
3(a)	Composite of the Amended Articles of Acceptance of I&M, dated of March 7, 1997.	1996 Form 10-K, Ex 3(c)
3(b)	Composite By-Laws of I&M, amended as of February 26, 2008.	2007 Form 10-K, Ex 3(b)
4	Indenture (for unsecured debt securities), dated as of October 1, 1998, between I&M and The Bank of New York, as Trustee.	Registration Statement No. 333-88523, Ex 4(a)(b)(c) Registration Statement No. 333-58656, Ex 4(b)(c) Registration Statement No. 333-108975, Ex 4(b)(c)(d) Registration Statement No. 333-136538, Ex 4(b)(c) Registration Statement No. 333-156182, Ex 4(b) Registration Statement No. 333-185087, Ex 4(b) Registration Statement No. 333-207836, Ex 4(b) Registration Statement No. 333-225103, Ex 4(b)(c)(d) Registration Statement No. 333-268880, Ex 4(b)(c) Registration Statement No. 333-290612, Ex 4(b)
4(a)	Company Order and Officer’s Certificate between I&M and The Bank of New York Mellon Trust Company, N.A., as Trustee, dated March 23, 2023 establishing terms of the 5.625% Senior Notes, Series P, due 2053.	Form 8-K, Ex 4(a) filed March 23, 2023
10(a)	Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended September 10, 2010.	2013 Form 10-K, Ex 10(a)
10(b)	Unit Power Agreement dated as of March 31, 1982 between AEGCo and I&M, as amended.	Registration Statement No. 33-32752, Ex 28(b)(1)(A)(B)
10(c)	Consent Decree with U.S. District Court dated October 9, 2007, as modified July 17, 2019.	Form 8-K, Ex. 10 filed October 9, 2007 Form 10-Q, Ex 10, June 30, 2013 Form 10-Q, Ex 10, June 30, 2019
*23	Consent of PricewaterhouseCoopers LLP.
*24	Power of Attorney.
*31(a)	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31(b)	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32(a)	Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
*32(b)	Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
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E-9

Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:
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OPCo‡   File No. 1-6543
3(a)	Composite of the Amended Articles of Incorporation of OPCo, dated June 3, 2002.	Form 10-Q, Ex 3(e), June 30, 2002
3(b)	Amended Code of Regulations of OPCo.	Form 10-Q, Ex 3(b), June 30, 2008
4(a)	Indenture (for unsecured debt securities), dated as of September 1, 1997, between OPCo and Bankers Trust Company (now The Bank of New York Mellon Trust Company, N.A. as assignee of Deutsche Bank Trust Company Americas), as Trustee.	Registration Statement No. 333-49595, Ex 4(a)(b)(c) Registration Statement No. 333-106242, Ex 4(b)(c)(d) Registration Statement No. 333-127913, Ex 4(b)(c) Registration Statement No. 333-139802, Ex 4(b)(c)(d) Registration Statement No. 333-161537, Ex 4(b)(c)(d) Registration Statement No. 333-211192, Ex 4(b) Registration Statement No. 333-230094, Ex 4(b) Registration Statement No. 333-255600, Ex 4(b)(c)(d) Registration Statement No. 333-275801, Ex 4(b)
4(a)1	Resignation of Deutsche Bank Trust Company Americas, as Trustee and appointment of The Bank of New York Mellon Trust Company, N.A. as Trustee of Indenture with OPCo dated as of September 1, 1997.	Form 8-K, Item 8.01 filed October 8, 2018
4(a)2	Company Order and Officer’s Certificate between OPCo and The Bank of New York Mellon Trust Company, N.A. as Trustee dated September 9, 2021 establishing terms of the 2.90% Senior Notes, Series R, due 2051.	Form 8-K, Ex 4(a) filed September 13, 2021
4(a)3	Company Order and Officer’s Certificate between OPCo and The Bank of New York Mellon Trust Company, N.A. as Trustee dated May 6, 2024 establishing terms of the 5.65% Senior Notes, Series T due 2034.	Form 8-K, Ex 4(a) filed May 6, 2024
4(b)	Indenture (for unsecured debt securities), dated as of February 1, 2003, between OPCo and Bank One, N.A., as Trustee.	Registration Statement No. 333-127913, Ex 4(d)(e)(f)
4(c)	Indenture (for unsecured debt securities), dated as of September 1, 1997, between CSPCo (predecessor in interest to OPCo) and Bankers Trust Company, as Trustee.	Registration Statement No. 333-54025, Ex 4(a)(b)(c)(d) Registration Statement No. 333-128174, Ex 4(b)(c)(d) Registration Statement No. 333-150603, Ex 4(b)
4(d)	Indenture (for unsecured debt securities), dated as of February 1, 2003, between CSPCo (predecessor in interest to OPCo) and Bank One, N.A., as Trustee.	Registration Statement No. 333-128174, Ex 4(e)(f)(g) Registration Statement No. 333-150603, Ex 4(b)
4(e)	First Supplemental Indenture, dated as of December 31, 2011, by and between OPCo and The Bank of New York Mellon Trust Company, N.A., as trustee, supplementing the Indenture dated as of September 1, 1997 between CSPCo (predecessor in interest to OPCo) and the trustee.	Form 8-K, Ex 4.1 filed January 6, 2012

E-10

Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:
4(f)	Third Supplemental Indenture, dated as of December 31, 2011, by and between OPCo and The Bank of New York Mellon Trust Company, N.A., as trustee, supplementing the Indenture dated as of February 14, 2003 between CSPCo (predecessor in interest to OPCo) and the trustee.	Form 8-K, Ex 4.2 filed January 6, 2012
10(a)	Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended September 10, 2010.	2013 Form 10-K, Ex 10(a)
10(b)	Consent Decree with U.S. District Court dated October 9, 2007, as modified July 17, 2019.	Form 8-K, Ex. 10 filed October 9, 2007 Form 10-Q, Ex 10, June 30, 2013 Form 10-Q, Ex 10, June 30, 2019
*23	Consent of PricewaterhouseCoopers LLP.
*24	Power of Attorney.
*31(a)	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31(b)	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32(a)	Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
*32(b)	Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
101.INS	XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH	XBRL Taxonomy Extension Schema.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF	XBRL Taxonomy Extension Definition Linkbase.
101.LAB	XBRL Taxonomy Extension Label Linkbase.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase.
104	Cover Page Interactive Data File. Formatted as inline XBRL and contained in Exhibit 101.
PSO‡   File No. 0-343
3(a)	Certificate of Amendment to Restated Certificate of Incorporation of PSO.	Form 10-Q, Ex 3(a), June 30, 2008
3(b)	Composite By-Laws of PSO amended as of February 26, 2008.	2007 Form 10-K, Ex 3(b)
4(a)	Indenture (for unsecured debt securities), dated as of November 1, 2000, between PSO and The Bank of New York, as Trustee.	Registration Statement No. 333-100623, Ex 4(a)(b) Registration Statement No. 333-114665, Ex 4(b)(c) Registration Statement No. 333-133548, Ex 4(b)(c) Registration Statement No. 333-156319, Ex 4(b)(c) Registration Statement No. 333-251378, Ex 4(b)(c) Registration Statement No. 333-282058 Ex. 4(b)(c)

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Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:
4(b)	Twelfth Supplemental Indenture dated as of December 1, 2024 between PSO and The Bank of New York Mellon Trust Company, N.A. as Trustee establishing terms of the 5.20% Senior Notes, Series M, due 2035.	Form 8-K. Ex 4(a) filed December 5, 2024
4(b)(1)	Thirteenth Supplemental Indenture dated June 1, 2025, between PSO and The Bank of New York Mellon Trust Company, N.A., as Trustee, establishing terms of the Notes.	Form 8-K, Ex 4(a) filed June 23, 2025
4(c)	Credit Agreement dated as of January 19, 2021 among PSO as Borrower, Initial Lenders and Sumitomo Mitsui Banking Corporation as Administrative Agent.	2020 Form 10-K, Ex 4(d)
4(c)A	April 19, 2022 Amendment and extension to $500,000,000 Credit Agreement dated January 19, 2021 among PSO, Initial Lenders and Sumitomo Mitsui Banking Corporation as Administrative Agent.	Form 10-Q Ex 4(c), March 31, 2022
*23	Consent of PricewaterhouseCoopers LLP.
*24	Power of Attorney.
*31(a)	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31(b)	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32(a)	Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
*32(b)	Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
101.INS	XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH	XBRL Taxonomy Extension Schema.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF	XBRL Taxonomy Extension Definition Linkbase.
101.LAB	XBRL Taxonomy Extension Label Linkbase.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase.
104	Cover Page Interactive Data File. Formatted as inline XBRL and contained in Exhibit 101.
SWEPCo‡   File No. 1-3146
3(a)	Composite of Amended Restated Certificate of Incorporation of SWEPCo.	2008 Form 10-K, Ex 3(a)
3(a)(A)	Amendment to Amended Restated Certificate of Incorporation.	Form 8-K Ex 3.1 filed September 1, 2020

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Exhibit Designation	Nature of Exhibit	Previously Filed as Exhibit to:
3(b)	Composite By-Laws of SWEPCo amended as of February 26, 2008.	2007 Form 10-K, Ex 3(b)
4(a)	Indenture (for unsecured debt securities), dated as of February 4, 2000, between SWEPCo and The Bank of New York, as Trustee.	Registration Statement No. 333-96213 Registration Statement No. 333-87834, Ex 4(a)(b) Registration Statement No. 333-100632, Ex 4(b) Registration Statement No. 333-108045, Ex 4(b) Registration Statement No. 333-145669, Ex 4(c)(d) Registration Statement No. 333-161539, Ex 4(b)(c) Registration Statement No. 333-194991, Ex 4(b)(c) Registration Statement No. 333-208535, Ex 4(b)(c) Registration Statement No. 333-226856, Ex 4(b)(c) Registration Statement No. 333-238159, Ex 4(b) Registration Statement No. 333-258961, Ex 4(b) Registration Statement No. 333-282060, Ex 4(b)(c)
*23	Consent of PricewaterhouseCoopers LLP.
*24	Power of Attorney.
*31(a)	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31(b)	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32(a)	Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
*32(b)	Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
101.INS	XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH	XBRL Taxonomy Extension Schema.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF	XBRL Taxonomy Extension Definition Linkbase.
101.LAB	XBRL Taxonomy Extension Label Linkbase.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase.
104	Cover Page Interactive Data File. Formatted as inline XBRL and contained in Exhibit 101.

‡ Certain instruments defining the rights of holders of long-term debt of the registrants included in the financial statements of registrants filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10% of the total assets of registrants.  The registrants hereby agree to furnish a copy of any such omitted instrument to the SEC upon request.

The agreements and other documents filed as exhibits to this report are not intended to provide factual information or other disclosure other than with respect to the terms of the agreements or other documents themselves, and you should not rely on them for that purpose. In particular, any representations and warranties made by AEP in these agreements or other documents were made solely within the specific context of the relevant agreement or document and may not describe the actual state of affairs as of the date they were made or at any other time.

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