aep-20260930

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For The Quarterly Period Ended September 30, 2026

☐ 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

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

☐

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 registrants were required to submit such files).

Yes

☐

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

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

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 registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).

Yes

☐

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 H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.


			Number of shares of common stock outstanding of the Registrants as of
			October 28, 2026

American Electric Power Company, Inc.			544,526,330
			($6.50 par value)
AEP Texas Inc.			100
			($0.01 par value)
AEP Transmission Company, LLC (a)			NA

Appalachian Power Company			13,499,500
			(no par value)
Indiana Michigan Power Company			1,400,000
			(no par value)
Ohio Power Company			27,952,473
			(no par value)
Public Service Company of Oklahoma			9,013,000
			($15 par value)
Southwestern Electric Power Company			3,680
			($18 par value)

(a)100% interest is held by AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of American Electric Power Company, Inc.

NA Not applicable.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX OF QUARTERLY REPORTS ON FORM 10-Q

September 30, 2026

Page

Number

Glossary of Terms

Forward-Looking Information

Part I. FINANCIAL INFORMATION

Items 1, 2, 3 and 4 - Financial Statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk and Controls and Procedures:

American Electric Power Company, Inc. and Subsidiary Companies:

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

Quantitative and Qualitative Disclosures About Market Risk

Condensed Consolidated Financial Statements

AEP Texas Inc. and Subsidiaries:

Management’s Narrative Discussion and Analysis of Results of Operations

Condensed Consolidated Financial Statements

AEP Transmission Company, LLC and Subsidiaries:

Management’s Narrative Discussion and Analysis of Results of Operations

Condensed Consolidated Financial Statements

Appalachian Power Company and Subsidiaries:

Management’s Narrative Discussion and Analysis of Results of Operations

Condensed Consolidated Financial Statements

Indiana Michigan Power Company and Subsidiaries:

Management’s Narrative Discussion and Analysis of Results of Operations

Condensed Consolidated Financial Statements

Ohio Power Company and Subsidiaries:

Management’s Narrative Discussion and Analysis of Results of Operations

Condensed Consolidated Financial Statements

Public Service Company of Oklahoma:

Management’s Narrative Discussion and Analysis of Results of Operations

Condensed Financial Statements

Southwestern Electric Power Company Consolidated:

Management’s Narrative Discussion and Analysis of Results of Operations

Condensed Consolidated Financial Statements

102

Index of Condensed Notes to Condensed Financial Statements of Registrants

108

Controls and Procedures

197

Part II. OTHER INFORMATION

Item 1.

Legal Proceedings

198

Item 1A.

Risk Factors

198

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

198

Item 3.

Defaults Upon Senior Securities

198

Item 4.

Mine Safety Disclosures

198

Item 5.

Other Information

198

Item 6.

Exhibits

199

SIGNATURE

200

This combined Form 10-Q 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.

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. (the Company), 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 East Companies						APCo, I&M, KGPCo, KPCo, OPCo and WPCo.
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 T&D Services						AEP T&D Services, LLC, an unregulated subsidiary of AEP, is a specialized infrastructure services organization that delivers engineering, project management, procurement, and construction services for electric transmission, distribution and related utility infrastructure.
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.
Appalachian Recovery Funding						Appalachian Recovery Funding, LLC, a wholly-owned subsidiary of APCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to certain Virginia jurisdictional Amos and Mountaineer Property, Plant and Equipment balances and deferred storm costs.

APSC						Arkansas Public Service Commission.

ARO						Asset Retirement Obligations.

ASU						Accounting Standards Update.
ATM						At-the-Market.


Term						Meaning

Batch Zero						A one-time transitional interconnection process established by ERCOT and approved by the PUCT in 2026 that evaluates qualifying large load interconnection requests on a system-wide basis, allocates available transmission capacity, identifies necessary transmission upgrades and requires financial commitments from participating customers. The process applies primarily to large electric loads of 75 MW or greater and serves as the precursor to ERCOT's future recurring batch interconnection framework.
BESS						Battery Energy Storage System.

CAA						Clean Air Act.
CAMT						Corporate Alternative Minimum Tax.


CCN						Certificate of Convenience and Necessity.
CCR						Coal Combustion Residual.
CEO						Chief Executive Officer.
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.

CPA						Capacity Purchase Agreement.
CPCN						Certificate of Public Convenience and Necessity.
CSAPR						Cross-State Air Pollution Rule.
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.



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.



ERCOT						Electric Reliability Council of Texas regional transmission organization.


ETR						Effective Tax Rate.
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.
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.


Term						Meaning

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.
Grid Growth Ventures						Grid Growth Ventures, LLC, a holding company formed by Transource Energy and First Energy Transmission, LLC, in 2025, which is 43.25% owned by AEP.
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.

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.


kV						Kilovolt.
KWh						Kilowatt-hour.
LPSC						Louisiana Public Service Commission.
MATS						Mercury and Air Toxic Standards.

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.
MRBC						Modified Rate Base Cost.
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.

Nonutility Money Pool						Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.

NOLC						Net Operating Loss Carryforward.
NOX						Nitrogen Oxide.

OATT						Open Access Transmission Tariff.
OCC						Corporation Commission of the State of Oklahoma.

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Term						Meaning

ODEQ						Oklahoma Department of Environmental Quality.



OHTCo						AEP Ohio Transmission Company, Inc., a wholly-owned transmission subsidiary of Midwest Transmission Holdings.
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.

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.

PBA						Performance Based Accreditation.
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.
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.
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.


Term						Meaning

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.
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.


T&D						Transmission and Distribution Utilities.
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 AEP.



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.

VIE						Variable Interest Entity.
Virginia SCC						Virginia State Corporation Commission.
VIU						Vertically Integrated Utilities.
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.
WVSC						West Virginia Supreme Court.

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 “Part I – Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this quarterly report, 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’s service territory.
•			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, modified, repealed or suspended federal, state or local legislation, regulations, policies or executive actions that alter the regulatory framework; delay or prevent approvals or permits; affect approved or planned investments; or prevent timely recovery of costs and investments.
•			Volatility and instability in financial markets precipitated by disruptive events, including fiscal and monetary policy or uncertainty 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.
•			Projected increases in demand from data centers are subject to uncertainty and may not materialize as expected, or may occur at a different pace or scale than anticipated, which could impact our load forecasts, capital investment plans, cost recovery expectations and financial results.
•			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 plan for, develop, construct, acquire, or integrate a broad range of generation and energy storage resources, as well as related transmission and distribution infrastructure, including obtaining necessary regulatory approvals, permits, and incentives for which the timing is dependent upon the priorities, requirements, processes and determinations of the local policy and regulatory authorities; complying with cost caps and other regulatory or contractual requirements; and recovering associated costs and earning an appropriate return while meeting reliability, affordability, environmental, and customer‑service obligations.
•			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 affecting completion of the current or future capital investment plans, including labor, material, equipment or parts shortages and delays; and limited availability and extended lead times for critical equipment, including large power transformers and bridging power solutions.
•			The impact of prolonged or recurring U.S. federal government shutdowns on AEP’s operations, regulatory approvals and financial performance, including potential 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.
•			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, policies, methodologies for evaluating and approving load interconnection, and the allocation of costs within RTOs including ERCOT, PJM and SPP and the impacts of potential market changes or our participation 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 ratings impacting the cost of debt.
•			The impact of geopolitical developments on global energy markets, including volatility in fuel supply and pricing, power generation economics and customer demand patterns.
•			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 the Annual Report on Form 10-K for the fiscal year ended December 31, 2025 (the “2025 Annual Report”) and in Part II of this report.

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/.

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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-Q. 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. FINANCIAL INFORMATION

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

AEP CONSOLIDATED RESULTS OF OPERATIONS

Third Quarter of 2026 Compared to Third Quarter of 2025

Earnings Attributable to AEP Common Shareholders increased from $1 billion in 2025 to $1.2 billion in 2026 primarily due to:

•An increase in sales volumes in the residential class driven by favorable weather in 2026.

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

•An increase due to rate proceedings in AEP’s various jurisdictions.

•An increase in sales volume in the commercial and industrial customer classes driven primarily by new data processing load.

These increases were partially offset by:

•An increase in interest expense due to higher long-term debt balances and higher interest rates.

•A decrease due to a credit to certain existing wholesale generation customers.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

Earnings Attributable to AEP Common Shareholders decreased from $3 billion in 2025 to $2.8 billion in 2026 primarily due to:

•The favorable $480 million impact from the receipt of the June 2025 FERC NOLC order related to the treatment of NOLCs in transmission formula rates, partially offset by higher ongoing revenues and income due to continued investment in transmission assets.

•An increase in interest expense due to higher long-term debt balances and higher interest rates.

•A decrease due to a credit to certain existing wholesale generation customers.

•A decrease due to a probable, partial disallowance of the Pirkey Plant net book value in the SWEPCo 2025 Texas Base Rate Case.

These decreases were partially offset by:

•An increase due to rate proceedings in AEP’s various jurisdictions.

•An increase in sales volume in the commercial and industrial customer classes driven primarily by new data processing load.

•A gain from the sale of a non-utility investment in land at APCo.

See Results of Operations section for additional information by segment.

Non-GAAP Financial Measures

AEP reports its financial results in accordance with GAAP. AEP supplements its reporting of financial information with certain non-GAAP financial measures, such as operating earnings. The most comparable GAAP measure to operating earnings is GAAP earnings. Operating earnings, which could differ from earnings reported in accordance with GAAP, 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, that management believes 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. These non-GAAP measures should not be deemed more useful than, a substitute for, or an alternative to the most comparable GAAP measures.

Reconciliation of GAAP Earnings to Operating Earnings

The following tables present a reconciliation of operating earnings to the most directly comparable GAAP measure.


	Three Months Ended September 30, 2026
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
GAAP Earnings (a)	$	1,187	$	172	$	196	$	124	$	113	$	112	$	234	$	188
Adjustments to GAAP Earnings:
Mark-to-Market Impact of Commodity Hedging Activities (b)	14		—		—		—		8		—		—		—
Wholesale Customer Contract Agreements (c)	22		—		—		—		—		—		—		22
Income Tax Effect of Specified Items (d)	(7)		—		—		—		(2)		—		—		(4)
Total Specified Items	29		—		—		—		6		—		—		18

Operating Earnings (Non-GAAP)	$	1,216	$	172	$	196	$	124	$	119	$	112	$	234	$	206

(a)Represents the earnings (loss) attributable to common shareholders or AEP member, or net income (loss) for registrants with no noncontrolling interest.

(b)Represents the mark‑to‑market impact of economic hedging activities which are excluded to align with the recognition of the underlying hedged exposures.

(c)Represents SWEPCo’s agreements with certain existing wholesale customers under generation supply contracts, which resulted in credits to these wholesale customers that were paid in 2026.

(d)Tax effect is calculated using the statutory tax rate unless otherwise noted.


	Three Months Ended September 30, 2025
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
GAAP Earnings (a)	$	972	$	166	$	179	$	81	$	150	$	101	$	130	$	189
Adjustments to GAAP Earnings (b):
Mark-to-Market Impact of Commodity Hedging Activities (c)	(1)		—		—		—		(5)		—		—		—
Impact of Ohio Legislation (d)	(8)		—		—		—		—		(8)		—		—
Total Specified Items	(9)		—		—		—		(5)		(8)		—		—

Operating Earnings (Non-GAAP)	$	963	$	166	$	179	$	81	$	145	$	93	$	130	$	189

(a)Represents the earnings (loss) attributable to common shareholders or AEP member, or net income (loss) for registrants with no noncontrolling interest.

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

(c)Represents the mark‑to‑market impact of economic hedging activities which are excluded to align with the recognition of the underlying hedged exposures.

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


	Nine Months Ended September 30, 2026
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
GAAP Earnings (a)	$	2,774	$	405	$	571	$	369	$	358	$	338	$	303	$	330
Adjustments to GAAP Earnings:
Mark-to-Market Impact of Commodity Hedging Activities (b)	32		—		—		—		15		—		—		—
Impact of WVPSC Order (c)	(35)		—		—		(29)		—		—		—		—
Pirkey Plant Partial Disallowance (d)	31		—		—		—		—		—		—		31
UTM Partial Disallowance (e)	22		22		—		—		—		—		—		—
Wholesale Customer Contract Agreements (f)	45		—		—		—		—		—		—		45
Income Tax Effect of Specified Items (g)	(20)		(5)		—		6		(4)		—		—		(15)
Total Specified Items	75		17		—		(23)		11		—		—		61

Operating Earnings (Non-GAAP)	$	2,849	$	422	$	571	$	346	$	369	$	338	$	303	$	391

(a)Represents the earnings (loss) attributable to common shareholders or AEP member, or net income (loss) for registrants with no noncontrolling interest.

(b)Represents the mark‑to‑market impact of economic hedging activities which are excluded to align with the recognition of the underlying hedged exposures.

(c)Represents the impact of the WVPSC order related to the 2024 Modified Rate Base Cost surcharge update filing.

(d)Represents the estimated impact of the probable, partial disallowance of the Pirkey Plant net book value in the 2025 Texas Base Rate Case.

(e)Represents the estimated impact of the probable, partial disallowance of costs included in AEP Texas’ UTM filing.

(f)Represents SWEPCo’s agreements with certain existing wholesale customers under generation supply contracts, which resulted in credits to these wholesale customers that were paid in 2026.

(g)Tax effect is calculated using the statutory tax rate unless otherwise noted.


	Nine Months Ended September 30, 2025
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
GAAP Earnings (a)	$	2,998	$	389	$	946	$	353	$	332	$	267	$	221	$	353
Adjustments to GAAP Earnings (b):
Mark-to-Market Impact of Commodity Hedging Activities (c)	5		—		—		—		11		—		—		—
Sale of AEP OnSite Partners (d)	10		—		—		—		—		—		—		—
Impact of Ohio Legislation (e)	19		—		—		—		—		19		—		—
FERC NOLC Order (f)	(480)		—		(354)		(29)		(36)		—		(4)		(54)
Total Specified Items	(446)		—		(354)		(29)		(25)		19		(4)		(54)

Operating Earnings (Non-GAAP)	$	2,552	$	389	$	592	$	324	$	307	$	286	$	217	$	299

(a)Represents the earnings (loss) attributable to common shareholders or AEP member, or net income (loss) for registrants with no noncontrolling interest.

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

(c)Represents the mark‑to‑market impact of economic hedging activities which are excluded to align with the recognition of the underlying hedged exposures.

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

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

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

ELECTRIC INDUSTRY TRANSFORMATION

AEP continues to convert large load interest across its service territory into signed customer financial commitments. These commitments, primarily from data processing and other energy-intensive customers, are expected to support sales growth, expand the customer base and improve utilization of AEP’s generation, transmission and distribution systems. New data processing load contributed to commercial and industrial sales growth during 2026, demonstrating that large load additions have begun to contribute to operating results.

To serve committed and forecasted growth, AEP outlined a $100.4 billion, five-year capital plan focused on strengthening transmission infrastructure, adding new generation to support both existing customers and forecasted large load increases and continued improvements in distribution system reliability. Throughout this investment cycle, AEP remains focused on customer affordability and expects to utilize incremental load growth, rate design, continued operation and maintenance expense efficiency and financing mechanisms, such as securitizations, to help address affordability.

AEP is leveraging its generation portfolio, transmission network and infrastructure execution capabilities to support committed and forecasted customer demand, including:

•The addition of 1,859 MWs of owned generating capacity in 2026.

•Signing agreements in 2026 to acquire 5,099 MWs in additional generation facilities.

•Requests for proposals seeking approximately 14,400 MWs of generating capacity.

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

•Long-term agreements with leading infrastructure services companies to provide engineering, project management and construction support for planned transmission infrastructure expansion.

AEP has advanced large load tariff proposals and modifications across its jurisdictions to facilitate customer interconnections while protecting existing customers. Approved and proposed provisions may include contract periods of up to 20 years, take-or-pay minimums covering 80% to 90% of contracted demand, credit support and customer responsibility for specified infrastructure costs. As of September 30, 2026, AEP filed proposals in eight jurisdictions, with six approved and two pending in Oklahoma and SWEPCo-Texas. AEP continues to engage with regulators, policymakers, RTOs, customers and suppliers to connect large load customers while advancing reliability, resiliency and affordability across its service territory.

PJM Resource Adequacy Reforms

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 (FRR) alternative in which load-serving entities self-supply their generation through owned or contracted resources. All AEP East Companies other than OPCo 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 PJM Board of Managers issued a decision letter initiating changes to PJM’s capacity market and interconnection processes.

In July 2026, the PJM Board of Managers approved near-term resource adequacy reforms intended to address projected reliability concerns associated with significant forecasted load growth and capacity shortages. PJM subsequently filed proposals with the FERC in July and August 2026 to establish a Reliability Backstop Procurement (RBP) mechanism and an Interim Resource Adequacy Service (IRAS). The RBP would procure new capacity through long-term commitments, while IRAS would provide for emergency curtailment of certain new large loads not supported by qualifying new capacity. PJM proposed to exclude FRR entities from the RBP procurement targets and associated cost allocation. PJM also proposed to exclude FRR load from the IRAS curtailment service. For new large loads in FRR service areas, PJM instead proposed to cap reliance on existing generation capacity at the quantity owned or contracted before June 1, 2027, with additional capacity needs for those loads to be met through new resources.

In September 2026, the FERC accepted the RBP proposal for filing but suspended its effectiveness until February 28, 2027, subject to refund and further proceedings concerning cost allocation, transmission-owner exit obligations and load-serving entity collateral requirements. To expedite implementation, the FERC encouraged PJM to submit a revised proposal by October 29, 2026. PJM indicated that it intends to submit a revised proposal.

The FERC found PJM’s proposed exclusion of FRR entities from the RBP and associated cost allocation to be just and reasonable. Separately, PJM proposed provisions intended to prevent costs associated with committed RBP resources from being shifted to remaining PJM participants following a transmission owner’s withdrawal. Those provisions could require a withdrawing transmission owner to satisfy certain future obligations on an accelerated basis or arrange for their continued payment. The FERC questioned assigning these obligations to transmission owners rather than the load-serving entities benefiting from the procurement and directed further proceedings on that issue.

In October 2026, the FERC accepted PJM’s definition of Large Load and its Large Load Registry, effective October 12, 2026, and directed a compliance filing within 30 days. The registry covers existing and future large loads, with information-reporting obligations on load-serving entities and supporting information from electric distributors where needed. AEP’s operating companies, including both FRR and non-FRR entities are subject to the Large Load Registry reporting requirement. However, the FERC rejected the remainder of the IRAS filing, including the proposed curtailment framework, Bring Your Own New Capacity requirements and related capacity-market provisions. The FERC identified jurisdictional and other deficiencies and provided guidance for a revised proposal should PJM choose to refile. The IRAS rejection also eliminated the proposed FRR procurement restrictions described above, including the June 1, 2027 cutoff for determining the quantity of existing generation capacity available to serve new large loads.

The ultimate form and timing of additional or revised tariff provisions, and their associated implementation requirements, cost recovery mechanisms and operational impacts, remain uncertain. At this time, AEP cannot predict the outcome of further FERC proceedings or estimate the potential impact, if any, that final approved provisions may have on its financial condition, results of operations or cash flows. AEP will continue to monitor these matters.

Large Load Interconnections in Texas

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 manner intended to support economic development in Texas while reducing 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 continues its rulemaking efforts to implement SB 6, including provisions related to large load interconnection standards, load forecasting, reliability requirements and transmission cost allocation. The PUCT adopted changes in September 2026, effective October 2026, to the Texas Administrative Code related to Large Load Interconnection Standards. The changes require a large load customer to execute an intermediate agreement, provide certain disclosures and post financial security in the amount of $50,000 per MW before inclusion in an ERCOT interconnection study. The new rule requires a large load customer to execute a standardized interconnection agreement once the allocation of capacity is determined from the ERCOT batch study, provide certain disclosures, and in addition to the financial security, the cash required for the direct interconnection of their load to the broader system. The new rule also establishes the consequences of withdrawing all or a portion of requested or contracted peak demand, establishes the terms for the return of financial security to a large load customer that energizes and requires utilities to segregate cash collateral posted as financial security. In October 2026, AEP Texas segregated approximately $1.2 billion of cash collateral pursuant to the new rule.

AEP Texas has executed Letters of Agreement for approximately 49 gigawatts of incremental load by 2031, including prospective load seeking consideration under ERCOT’s Batch Zero process. ERCOT's Batch Zero process is a one-time transitional interconnection process established by ERCOT and approved by the PUCT in 2026 that is designed to evaluate qualifying large load interconnection requests on a system-wide basis, allocate available transmission capacity, identify necessary transmission upgrades and require financial commitments from participating customers. The process applies primarily to large electric loads of 75 MW or greater and serves as the precursor to ERCOT's future recurring batch interconnection framework. In July 2026, AEP Texas received approximately $2 billion of financial security in the form of cash collateral, corporate or parental guarantees and letters of credit for the 45 gigawatts of prospective load seeking consideration for participation in the Batch Zero process through 2032.

In August 2026, the Governor of Texas directed the PUCT and ERCOT to conduct a comprehensive verification of all Batch Zero loads and an audit of data center projects 25 MW and above advancing through ERCOT's interconnection process before any additional projects move forward. Following the governor’s direction, ERCOT announced that it would not meet an August 2026 deadline associated with the Batch Zero interconnection study process and received a good-cause exception from the PUCT regarding Batch Zero schedule and implementation requirements. ERCOT has currently paused Batch Zero classification and study activity and stated it will not authorize large loads to energize until verification is complete.

The recent activities of the PUCT and ERCOT are expected to provide greater clarity regarding large load interconnection requirements, transmission infrastructure needs and the timing and scale of future load growth. Accordingly, the amount, timing and cost responsibility associated with these prospective large load interconnections remain subject to ongoing ERCOT and PUCT actions.

Customer Demand

AEP uses sales volumes by customer class as a way to measure drivers of customer demand. Through the third quarter of 2026, AEP experienced higher customer demand, driven primarily by new data processing load added in the commercial and industrial customer classes. In addition, AEP experienced higher customer demand in the residential class, due to favorable weather in the third quarter of 2026 compared to the third quarter of 2025. The table below shows the percentage change in sales volume by customer class.

(a)Percentage change for the three months ended September 30, 2026 as compared to the three months ended September 30, 2025. Load figures are billed and accrued retail sales excluding firm wholesale load.

(b)Percentage change for the nine months ended September 30, 2026 as compared to the nine months ended September 30, 2025. Load figures are billed and accrued retail sales excluding firm wholesale load.

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 2026, AEP subsidiary companies acquired five generation facilities to support AEP’s portfolio and enhance reliability. These transactions reflect the companies’ continued focus on securing necessary generation to meet future customer demand. See the “Acquisitions” section of Note 6 for additional information. The table below summarizes these acquisitions:

Company

Plant Name

Fuel Type

Location

Acquisition Date

Net Maximum Capacity

(in MWs)

I&M

Oregon

Natural Gas

Oregon, OH

March 2026

870

APCo

Grover Hill

Wind

Paulding County, OH

May 2026

143

AGR

Wolf Hills

Natural Gas

Bristol, VA

August 2026

263

I&M

Big Sandy Peaker

Natural Gas

Kenova, WV

August 2026

318

PSO

Lazbuddie

Wind

Parmer and Castro Counties, TX

August 2026

265

Total Acquired Generation Facilities

1,859

Pending Generation Facilities

In April 2026, I&M entered into a PSA to acquire the Sycamore Riverside Energy Center (Sycamore Plant), a 918 MW natural gas and ultra-low sulfur distillate (dual-fuel)-fired generation facility located in Sullivan County, Indiana. I&M filed an application with the IURC in late April seeking a CPCN for approval of the estimated project costs and associated ratemaking and accounting treatment. A final order from the IURC is expected in December 2026.

In May 2026, APCo filed an application with the Virginia SCC seeking approval for two new solar PSAs including Skycrest (155 MWs) located in Jay County, Indiana, anticipated to be placed in service in December 2028, and Riverstart V (100 MWs) located in Randolph County, Indiana, anticipated to be placed in service in August 2028. The petition also included request for approval of two wind PPA extensions consisting of Beech Ridge (101 MWs) with an 8-year extension starting in 2030 and Camp Grove (150 MWs) with a 10-year extension starting in 2027.

In July 2026, AGR entered into a PSA to acquire the Longview Power Plant, a 710 MW coal-fired generation facility located in Monongalia County, West Virginia. The transaction is subject to customary closing conditions, including approval from the FERC and other required regulatory approvals. The agreement was signed to support growing energy demand in the region and strengthen AEP's ability to provide reliable power at affordable prices. The Company currently expects the acquisition to close in the fourth quarter of 2026 or the first quarter of 2027, although the timing and ultimate completion of the transaction are subject to receiving the required regulatory approvals and other closing conditions.

In July 2026, I&M filed an application for a CPCN with the IURC for approval to construct the Rockport Energy Center, a 1,520 MW combined-cycle natural gas facility to be located in Spencer County, Indiana. In the application, the Company seeks approval of the estimated costs of the project, the authority to recover costs in connection with its development and approval of specific ratemaking and accounting treatment. A final order from the IURC is expected in the first quarter of 2027.

In July 2026, I&M filed an application under its Expedited Generation Resource Plan (EGR Plan) requesting approval of amended contractual terms to the previously approved 245 MW Lake Trout Solar Project PSA. A final order is expected in November 2026.

In September 2026, SWEPCo filed applications for CCNs with the APSC, LPSC and PUCT, seeking regulatory approval for the acquisition of the Brantley Branch project, a 200 MW 6-hour BESS, located in Rusk County, Texas. Regulatory approvals are expected in the third quarter of 2027 and the project is expected to close and come into service in the fourth quarter of 2028.

In October 2026, KPCo entered into an amended agreement with TeraWulf Inc., for 1 GW of contracted demand. KPCo plans to file an application seeking approval of the agreement and the related generation investments in the fourth quarter of 2026.

Significant Approved Generation and Storage Filings

AEP received regulatory approvals from various state regulatory commissions to acquire approximately 2,327 MWs of owned generation and storage facilities, totaling approximately $2.3 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 1,124 MWs of renewable PPAs. The following table summarizes regulatory approvals received for approved generation projects that are not yet in service as of September 30, 2026:

Company

Generation Type

Expected Commercial
Operation

Owned/PPA

Generating Capacity

(in MWs)

APCo

Solar

2027-2028

PPA

343

I&M

Solar

2027-2028

PPA

380

I&M

Wind

2027-2030

PPA

401

PSO

Solar

2027

Owned

150

PSO

BESS

2027-2028

Owned

224

PSO

Gas combustion turbines

2028

Owned

450

SWEPCo

Gas combustion turbines

2027-2028

Owned

1,503

Total Approved Projects

3,451

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)

APCo

May 2026

Owned wind and solar

2029

800

APCo

May 2026

Purchased power from solar, wind and hydroelectric resources

2028/2029

300

APCo

August 2026

Contracted BESS

2029

300

APCo

August 2026

Owned BESS

2030

500

APCo

August 2026

Owned combined cycles

2031

1,500

I&M

October 2026

All-source

2033/2034

4,000

PSO

January 2026

All-source

2029

4,000

SWEPCo

May 2026

All-source

2031

3,000

Total Significant RFPs

14,400

Capacity Purchase Agreements

In addition to the generation projects discussed above, AEP enters into CPAs to satisfy operating companies’ capacity reserve margins to serve customers. The following table includes CPA amounts under contract as of September 30, 2026, by year, for the five-year period 2026-2030:


	APCo	I&M		PSO (a)		SWEPCo (a)
	Gas	Natural Gas	Wind		Natural Gas	Wind	Natural Gas	Wind
Delivery Start Year	(in MWs)
2026	—	—	73		460	86	150	87
2027	—	160	—		410	86	300	83
2028	198	1,151	—		724	—	461	88
2029	—	1,139	—		751	—	488	88
2030	—	996	—		789	—	225	88

(a)Seasonal average of volume contracted.

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 financial condition.

The following tables summarize the completed and pending base rate case proceedings. See Note 4 - Rate Matters for additional information.

Completed Base Rate Case Proceedings

Annual

Previously

Base Revenue

Approved

New Rates

Company

Jurisdiction

Increase

ROE

Effective

(in millions)

APCo/WPCo

West Virginia

9.75%

August 2025

(a)

SWEPCo

Arkansas

9.5%

9.65%

February 2026

(b)

KPCo

Kentucky

9.75%

March 2026

(c)

OPCo

Ohio

9.7%

9.84%

April 2026

(a)In August 2025, in response to APCo’s and WPCo’s 2024 West Virginia Base Rate Case filing, the WVPSC originally approved a combined $76 million annual increase in base rates based upon a 9.25% ROE. In February 2026, the WVPSC issued an order on reconsideration of the 2024 West Virginia Base Rate Case, approving a revised ROE of 9.75%, resulting in a $15 million prospective annual increase in base rates, to arrive at an authorized annual increase of $91 million effective February 2026.

(b)See “2025 Arkansas Base Rate Case” section of Note 4 in the 2025 Annual Report for additional information.

(c)In March 2026, KPCo filed a request with the KPSC seeking rehearing on the vegetation management finding in the base case order in addition to certain other denied costs. In April 2026, the KPSC issued an order approving KPCo’s request for rehearing.

Pending Base Rate Case Proceedings

Annual

Base Revenue

Filing

Increase/ (Decrease)

Requested

Company

Jurisdiction

Date

Request

ROE

(in millions)

SWEPCo

Texas

October 2025

10.75%

PSO

Oklahoma

January 2026

299

10.5%

APCo

Virginia

May 2026

10.5%

I&M

Indiana

August 2026

(42)

10.1%

Other Significant Regulatory Matters

Piketon Transmission Project (Applies to AEP, AEPTCo and OPCo)

In August 2026, OHTCo, OPCo and an unaffiliated customer executed definitive agreements related to the construction of three 765 kV transmission lines by OHTCo to support the development of a proposed 10.4 GW data center campus in Piketon, Ohio. The three 765 kV transmission lines, each expected to provide approximately 3.2 GWs of incremental transmission capacity, have targeted in-service date goals of December 31, 2028, 2029 and 2030. The initial 800 MWs of load is expected to be served utilizing existing transmission capacity and does not require any additional regulatory approvals.

For the balance of the approximately 10.4 GW, and subject to applicable regulatory approvals and the terms of the definitive agreements, OHTCo is expected to recover approved transmission-related costs related to the new load through arrangements with OPCo, which will, in turn, recover such amounts from the customer pursuant to a retail service agreement designed to prevent any of the costs of the project from being allocated to other OPCo customers. Under the agreement, the customer is responsible for those costs, including the applicable return, with no allocation of those costs to other OPCo customers.

The definitive agreements related to the transmission investment to serve the load provide for a base ROE of 11.35%, which may increase to 11.99% or decrease to 10.71% based on the actual project costs as compared to budgeted costs and actual in-service dates as compared to targeted in-service dates for each transmission line, and include payment terms extending for 20 years following the applicable in-service dates. The agreements establish a budget for the project of approximately $5 billion. The Piketon Transmission Project requires regulatory approvals from PJM, the PUCO and the FERC. The equipment purchase agreement currently in effect requires the customer to fully collateralize OHTCo equipment purchases prior to receiving the required regulatory approvals. The ultimate scope, timing, cost recovery mechanisms and economics of the project are subject to regulatory review and approval.

2025 UTM Filing

In October 2025, AEP Texas submitted its first filing with the PUCT seeking recovery of eligible costs through the UTM. In March 2026, a Texas ALJ issued a PFD recommending partial disallowance of the requested amounts which was based on an interpretation of a later effective date for eligible UTM deferrals. In April 2026, AEP Texas filed responses reflective of the legislative intent of Texas House Bill 5247 (2025). In May 2026, the PUCT Chairman issued a Commissioner Memorandum agreeing with the ALJ’s PFD and ordered the PUCT staff to complete a calculation to confirm the final disallowance amount. Completion of the Commission-required calculation and final order were filed in the third quarter of 2026. In conjunction with the Commissioner Memorandum, AEP Texas recognized an unfavorable pretax impact of $23 million in May 2026 attributable to a portion of the deferrals included in the UTM application period.

UTM Regulatory Assets

As of September 30, 2026, AEP Texas has deferred, beginning August 2025, approximately $89 million of eligible costs as a regulatory asset for inclusion in future AEP Texas’ UTM applications. AEP Texas has also deferred approximately $34 million related to its system resiliency plan for inclusion in future UTM applications. Investments included in the UTM and the existing capital tracker filings remain subject to prudency review in the utility’s next base rate case proceeding before the PUCT. If any of these deferred costs or investments are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

West Virginia Securitization

In March 2026, the WVPSC issued a financing order approving APCo’s and WPCo’s (the Companies) proposed securitization. In July 2026, the WVPSC approved an overall balance of $2.7 billion of eligible costs for securitization. The Companies are proceeding with the securitization bond issuance process and plan to complete the securitization in the fourth quarter of 2026, subject to market conditions. See “2025 West Virginia Securitization Filing” section of Note 4 for additional information.

West Virginia Modified Rate Base Cost Surcharge

A group of APCo customers submitted an appeal to the WVSC alleging that the WVPSC erred in its April 2026 order approving a final MRBC true-up without sufficient record support. In September 2026, APCo and the WVPSC filed motions for the WVSC to dismiss this APCo customer appeal. See the “2026 ENEC Update Filing” and “West Virginia Modified Rate Base Cost (MRBC) Surcharge Update Filing” sections of Note 4 for additional information.

West Virginia Inflation-Based Rate Adjustment

In April 2026, the WVPSC issued an order conditionally approving an annual Inflation-Based Rate Adjustment to current base rates of 4% for residential and commercial customers and 2.5% for industrial customers, provided that the Companies: (a) agree with proceeding with securitization, unless otherwise ordered by the WVPSC, (b) agree that the April 2026 Notice of Intent to file a 2026 West Virginia base rate case will be withdrawn and (c) agree that a new base rate case will not be filed prior to June 1, 2027. In April 2026, the Companies agreed to the terms of the Inflation-Based Rate Adjustment described above and filed revised tariff sheets reflecting a $40 million combined annual increase to base rates effective July 1, 2026.

A group of APCo customers submitted an appeal to the WVSC alleging that the WVPSC erred in its April 2026 order approving the Inflation-Based Rate Adjustment without adequate findings, evidentiary support or reasoned explanation demonstrating the approval of reasonable rates under WVPSC statutes. In September 2026, APCo and the WVPSC filed motions for the WVSC to dismiss the APCo customer appeal.

An intervening party submitted an appeal to the WVSC regarding the Inflation-Based Rate Adjustment alleging that the WVPSC: (a) failed to carry its burden of proving that the Companies’ existing rates were unreasonable and needed to be changed, (b) failed to adequately support its order with evidence of record and (c) violated the due process rights of the intervening party and the customers that it represents. See the “West Virginia Inflation-Based Rate Adjustment” section of Note 4 for additional information.

If any refund liabilities are imposed related to these West Virginia jurisdictional issues, it would reduce future net income and cash flows and impact financial condition.

Indiana House Enrolled Act 1002

On February 26, 2026, House Enrolled Act 1002 (HEA 1002) was signed into law in Indiana. This law requires Indiana’s investor-owned electricity suppliers to petition the IURC for approval of a multi-year rate plan (MYRP). When establishing an electricity supplier’s authorized return for its MYRP, Indiana law requires the IURC to consider any changes in risk to the electricity supplier and its customers that may result from implementing the MYRP. HEA 1002 also states that performance metrics and performance incentive mechanisms (PIM) will be applicable to each year of the electricity supplier’s MYRP with regards to affordability and service restoration.

In July 2026, the IURC launched two investigations applicable to all Indiana electric suppliers. One investigation considers the risks to the electricity suppliers and customers in Indiana as a result of the electricity supplier implementing an MYRP with respect to an electric suppliers’ authorized return. The second investigation considers the development of guidelines for electric suppliers and stakeholders to utilize in evaluating the future use of trackers under a MYRP framework. In October 2026, the IURC finalized the list of issues for its investigations into ROE and tracker mechanisms with stakeholder testimony due in December 2026 and hearings scheduled for February 2027.

Mitchell Plant Cooling Tower CPCN Requests

In February 2026, WPCo and KPCo filed CPCN and cost recovery requests (Mitchell CPCN) with the WVPSC and KPSC, respectively, to obtain the regulatory approvals necessary to: (a) construct a new mechanical draft cooling tower which would allow for continued operation of the 780 MW Mitchell Plant Unit 2 and (b) recover the related estimated investment of $191 million. WPCo and KPCo each own a 50% undivided interest in Mitchell Plant.

In June 2026, the Department of Energy awarded $51 million to support the WPCo and KPCo Mitchell Plant Cooling Tower investment.

In October 2026, the KPSC issued an order conditionally approving construction and cost recovery through a rider, subject to WVPSC CPCN approval and receipt of funding related to the June 2026 Department of Energy award. In addition, KPCo is required to provide the KPSC with written notice of any increase to estimated project costs that exceeds 5%. Additionally in October 2026, the WVPSC issued an order approving construction. Cost recovery will be addressed in a future filing. WPCo is required to provide the WVPSC with written notice of any increase to estimated project costs that exceeds 10%.

As of September 30, 2026, the net book value of Mitchell Plant Unit 2, before cost of removal and including CWIP and inventory, is estimated to be approximately $639 million ($382 million at WPCo and $257 million at KPCo). If AEP cannot ultimately recover Mitchell Plant Unit 2 costs, it would reduce future net income and cash flows and impact financial condition.

Federal Tax Legislation

In February 2026, the Department of Treasury and the IRS issued additional interim guidance on the application of CAMT, Notice 2026-7. This guidance allows taxpayers to deduct certain tax-deductible repairs when determining adjusted financial statement income for CAMT purposes. This guidance is expected to result in a reduction to applicable Registrants’ prior and future CAMT liabilities.

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.

Fuel Cell Agreements

In 2025, OPCo signed two contracts totaling approximately 98 MWs for electricity service from fuel cells. 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. In June 2026, the appeals were dismissed and the PUCO decisions are now final and non-appealable.

In January 2026, an unregulated subsidiary of AEP executed: (a) an unconditional purchase agreement to acquire a substantial portion of its 1 GW option for solid oxide fuel cells for the development and construction of a fuel cell generation facility for approximately $2.65 billion and (b) a 20 year offtake arrangement with a high investment grade third-party customer for 100% of the output of the fuel cell generation facility expected to be located near Cheyenne, Wyoming.

Grid Growth Ventures Investment (Applies to AEP)

In 2026, Transource Energy executed agreements to form Grid Growth Ventures, LLC (Grid Growth Ventures) with First Energy Transmission, LLC to participate in PJM’s 2025 Regional Transmission Expansion Plan (RTEP) competitive process. In February 2026, PJM selected the projects proposed by Grid Growth Ventures to address forecasted reliability and load growth requirements. The RTEP projects awarded by PJM were estimated to cost approximately $1.2 billion and AEP’s share of this investment was estimated to be $600 million. The RTEP projects awarded by PJM will be developed, owned and operated by Grid Ohio Growth EHV, LLC and Grid Growth Ohio, LLC, subsidiaries of Grid Growth Ventures.

In March 2026, subsidiaries of Grid Growth Ventures, Grid Growth Ohio EHV, LLC and Grid Growth Ohio, LLC, submitted to the FERC a request for acceptance of formula rates for each company, consisting of a formula rate template and implementation protocols, effective May 2026. The filing also requested approval of Federal Power Act Section 219 transmission incentive rate treatments for the projects awarded by PJM to the Grid Growth Ventures subsidiaries. The requested incentive rate treatments include: (a) recovery of abandonment costs if the projects are cancelled for reasons beyond Grid Growth Ventures’ control, (b) inclusion of CWIP in rates while the projects are in development, (c) use of hypothetical capital structure of 40% debt and 60% equity until the earlier of either December 31, 2032 or the date all of the projects are in service, after which Grid Growth Ventures will use its actual capital structure and (d) regulatory asset treatment for pre-commercial costs including carrying charges. The filing also proposed depreciation rates, requested a base ROE of 10.8% for both companies and requested authorization to replicate the formula rate and rate incentive treatments for any subsidiaries of Grid Growth Ventures. In July 2026, the FERC issued an order accepting the formula rate, subject to settlement proceedings which will determine the companies’ base ROE, cost of debt, formula rate template language and depreciation rates.

Midcontinent Grid Solutions Investment (Applies to AEP)

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 were estimated to cost approximately $1.2 billion and AEP’s share of this investment was estimated to be $500 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 September 2025, the FERC issued an order accepting the formula rates requested by Midcontinent Grid Solutions, LLC’s subsidiary, Midcontinent Grid Solutions Iowa, LLC (MGS Iowa), granting its 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. The 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 MGS Iowa, MGS Wisconsin is authorized to replicate MGS Iowa’s FERC-approved formula rate. A request was filed in April 2026 and included an additional incentive for the recovery of abandonment costs if the projects are cancelled for reasons beyond MGS Wisconsin’s control. In June 2026, the FERC approved MGS Wisconsin’s request.

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. As of September 30, 2026, there were four jurisdictions awaiting approval and two jurisdictions that have been approved but are subject to refund in their status of transitioning to stand-alone treatment of NOLCs in retail ratemaking. 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 September 30, 2026, AEP had NOLC regulatory assets of $92 million, of which $83 million are classified as pending final regulatory approval and $9 million are classified as approved for recovery.

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 5 – Commitments, Guarantees and Contingencies for additional information.

Claims for Indemnification Made by Owners of the Gavin Power Station

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 September 30, 2026, AEP owned generating capacity of approximately 27,200 MWs, of which approximately 10,200 MWs were coal-fired. In April 2024, the Federal EPA announced four major new rules directed at fossil-fuel electric generation facilities. Since then, the Federal EPA has finalized actions revising or repealing portions of certain 2024 rules and has proposed additional revisions or repeals. Most recently, in September 2026, the Federal EPA finalized a partial repeal of the 2024 greenhouse gas standards for fossil fuel-fired electric generating units and concurrently proposed rescinding the remaining power-sector greenhouse gas findings and standards under Clean Air Act Section 111. Management continues to evaluate the impacts of the rules that are currently in effect 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 regulatory requirements and associated costs of compliance 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) regulatory and policy changes implemented by the President and the Federal EPA 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 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, which in turn may require AEP to make investments in pollution control equipment at existing generating units or change 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. 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. In June 2026, the United States Court of Appeals for the District of Columbia Circuit denied the request. In a separate case, in July 2026, the United States District Court for the Northern District of California ordered the Federal EPA to complete area designations under the Agency’s revised annual fine particulate matter (PM2.5) NAAQS by February 2027. In September 2026, the Federal EPA appealed the district court’s order to the United States Court of Appeals for the Ninth Circuit. The agency requested, and the Ninth Circuit granted, expedited consideration of the case. However, while the appeals are pending, the Federal EPA is taking the actions required under the CAA to meet the court’s February 2027 deadline. In October 2026, the Federal EPA issued notices to states, territories, and tribes describing its intended designation approach and requested additional information within 30 days. In October 2026, the Federal EPA also joined a broad coalition of states and associations in petitioning the United States Supreme Court to review the 2024 standard.

If the rule is not vacated by any further legal challenge, states must revise SIPs to attain the new standard. Areas around some of AEP’s generating facilities may be deemed nonattainment, which may require additional pollution controls or the implementation of operational constraints. At this time, 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 United States 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. In February 2026, the Federal EPA proposed to approve the Regional Haze SIP for Oklahoma’s second implementation period. In August 2026, the Federal EPA proposed approval of an Oklahoma SIP revision submitted in March 2026 for the first implementation period, revising source-specific Regional Haze requirements applicable to Northeastern Power Station. Management will continue to monitor the rulemakings and 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. Several environmental groups have challenged the rule and in April 2026, AEP and other utilities moved to intervene in support of the Federal EPA in that litigation.

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.

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. In August 2023, a FIP (the Good Neighbor Plan) went into effect that further revised the ozone season NOX budgets under the existing CSAPR ozone season program in states to which the FIP applies. The FIP was the subject of judicial review in the United States Court of Appeals for the District of Columbia Circuit and has since been administratively stayed pending the Supreme Court lifting its June 2024 order staying enforcement of the Good Neighbor Plan, other courts lifting judicial orders staying the Federal EPA SIP disapproval actions as to SIPs submitted by several states, 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 stayed the litigation pending rulemaking by the Federal EPA. In June 2025, the Federal EPA proposed to repeal the GHG emissions standards for fossil-fueled fired electric generating units based on a determination that GHG emissions from power plants do not significantly contribute to air pollution that may endanger public health or the environment. 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 September 2026, the Federal EPA finalized a partial repeal of the 2024 standards, including the emission guidelines for existing fossil fuel-fired steam generating units, the carbon capture and sequestration-based standards for coal-fired steam generating units undertaking a large modification, and the Phase 2 carbon capture and sequestration-based standards for new base-load stationary combustion turbines. Concurrently, the Federal EPA issued a supplemental proposal to rescind the remaining greenhouse gas findings and standards for fossil fuel-fired power plants under Clean Air Act Section 111. Management is evaluating the final rule and supplemental proposal, including their effects on compliance planning, generation strategy and the pending litigation. The final rule will become effective 60 days after publication in the Federal Register. Management cannot predict the outcome of the supplemental proposal or related litigation. Future changes to greenhouse gas requirements could affect the timing and economics of investments in AEP's fossil generation fleet. 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. Accordingly, AEP continues to focus on developing energy solutions that align with state and federal policy objectives, customer expectations, and reliability requirements. These energy solutions may include a range of generation and energy resources, depending on the needs and priorities of the jurisdictions. AEP remains committed to evaluating and pursuing generation strategies that support reliability, affordability and long-term energy needs where supported by regulators and customers. As an example, APCo and I&M are seeking early site permits to bring small modular reactors to Virginia and Indiana as part of their evaluation of future generation options. AEP’s performance will ultimately be driven by the needs and desires of the jurisdictions 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 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 February 2026, the Federal EPA finalized its repeal of the 2024 MATS rule, and the rule’s requirements reverted to the 2012 MATS rule emission standards. That repeal has been challenged by various groups. Management will continue to monitor the litigation but does not anticipate any challenges complying with the standards in the now-repealed 2024 rule should its repeal be reversed by the court.

CCR Rule

The Federal EPA’s CCR Rule regulates the disposal and beneficial 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 Court 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 the second quarter of 2024, AEP evaluated the applicability of the rule to current and former plant sites and recorded a $674 million increase in ARO, 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. 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. In April 2026, the Federal EPA proposed revisions to the CCR Rule that would rescind requirements for CCR management units, revise requirements for beneficial use of CCR materials, allow expanded reliance on state-approved and other regulatory closures of legacy units, and introduce a new, permit-based, site-specific compliance pathway. In July 2026, the Federal EPA issued an advance notice of proposed rulemaking regarding the Federal CCR Permit Program. The Federal EPA is evaluating whether a general permit structure could support the site-specific compliance pathways proposed in April 2026. Management is evaluating the proposal and has participated in the rulemaking process.

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 5 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 eliminate the need to install zero liquid discharge systems for facilities that comply with the 2020 rule’s control technology requirements and commit by December 31, 2025 to retire by 2034. Several petitions for review have been filed with various federal courts challenging the 2024 ELG rule. SWEPCo also challenged the rule by filing a joint petition 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. The Federal EPA has announced plans to reconsider the standards and deadlines established by the 2024 ELG rule.

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. The Deadline Extension ELG Rule also extended the deadline to commit to cease coal combustion by 2034 from December 31, 2025 to December 31, 2031. Several environmental organizations filed petitions for review challenging the Federal EPA's December 2025 ELG Deadline Extension Rule. Those challenges were consolidated in the United States Court of Appeals for the Second Circuit, where the litigation remains pending. Management is evaluating the compliance alternatives in the ELG rule, taking into consideration the requirements of other rules and their combined impacts to operations. Management cannot predict the outcome of the pending litigation or 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. In September 2026, the agencies issued a supplemental notice of proposed rulemaking seeking additional public comment on alternative approaches prior to issuing a final rule. The rulemaking remains pending. 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 September 30, 2026:


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	$	50	$	259		2026			(c)	$	8


SWEPCo	Pirkey Plant	—		47		(d)	2023			(e)	—
SWEPCo	Welsh Plant, Units 1 and 3	220		264			2028	(f)		(g)	43

(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 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, which the ODEQ has submitted. Federal EPA proposed to approve the revised Oklahoma SIP in August 2026. That proposal remains pending. In anticipation of approval from the Federal EPA, PSO began operating Northeastern Plant, Unit 3 on natural gas in January 2026.

(d)Represents Texas 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 Unit that has been Retired and Related Fuel Operations” section of Note 4 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. In February 2026, the APSC issued an order approving the application for a CCN. Additionally, in September and October 2026, the PUCT and the LPSC, respectively, issued orders approving the stipulation and settlement agreements related to the CCN applications.

(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.

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.

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 8 - Business Segments for additional information on AEP’s segments.

The following discussion of AEP’s results of operations by segment provides a comparison of Earnings (Loss) Attributable to AEP Common Shareholders for the three months ended and nine months ended September 30, 2026 as compared to the three months ended and nine months ended September 30, 2025. 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 three and nine months ended September 30, 2026 and 2025, see the discussions of Results of Operations by Registrant Subsidiary.

A detailed discussion of AEP’s 2025 results of operations by operating segment can be found in Management’s Discussion and Analysis of Financial Condition and Results of Operations section included in the 2025 Annual Report.

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2026		2025		2026		2025
	(in millions)
Vertically Integrated Utilities	$	697	$	578	$	1,443	$	1,335
Transmission and Distribution Utilities	284		267		743		656
AEP Transmission Holdco	219		200		653		1,013
Generation & Marketing	96		45		268		209
Corporate and Other	(109)		(118)		(333)		(215)
Earnings Attributable to AEP Common Shareholders	$	1,187	$	972	$	2,774	$	2,998

See Note 8 - 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.

VERTICALLY INTEGRATED UTILITIES

Summary of KWh Energy Sales for Vertically Integrated Utilities


	Three Months Ended September 30,		Nine Months Ended September 30,
	2026	2025	2026	2025
	(in millions of KWhs)
Retail:
Residential	9,631	8,842	24,947	24,618
Commercial	8,475	7,355	22,540	19,548
Industrial	8,619	8,552	25,201	25,248
Miscellaneous	652	599	1,753	1,701
Total Retail	27,377	25,348	74,441	71,115

Wholesale (a)	5,088	4,217	12,183	12,451

Total KWhs	32,465	29,565	86,624	83,566

(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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2026	2025	2026	2025
	(in degree days)
Eastern Region
Actual – Heating	—	1	1,663	1,736
Normal – Heating	2	2	1,700	1,702

Actual – Cooling	841	722	1,222	1,104
Normal – Cooling	729	733	1,086	1,085

Western Region
Actual – Heating	—	—	632	966
Normal – Heating	—	—	911	903

Actual – Cooling	1,844	1,447	2,785	2,278
Normal – Cooling	1,413	1,415	2,190	2,186


Vertically Integrated Utilities
Reconciliation of 2025 to 2026 Earnings Attributable to AEP Common Shareholders


(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Earnings Attributable to AEP Common Shareholders	$	578	$	1,335

Changes in Revenues:
Retail Revenues	408		759
Off-system Sales	5		52
Transmission Revenues	1		13
Other Revenues	1		(2)
Total Change in Revenues	415		822

Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	47		68
Other Operation and Maintenance	(120)		(327)
Asset Impairments and Other Related Charges	—		(31)

Depreciation and Amortization	(112)		(193)
Taxes Other Than Income Taxes	(4)		(35)


Other Income	—		(2)
Allowance for Equity Funds Used During Construction	5		17
Non-Service Cost Components of Net Periodic Benefit Cost	(7)		(19)
Interest Expense	(61)		(168)
Total Change in Expenses and Other	(252)		(690)

Income Tax Benefit	(45)		(25)

Net Income Attributable to Noncontrolling Interests	1		1

2026 Earnings Attributable to AEP Common Shareholders	$	697	$	1,443

Third Quarter of 2026 Compared to Third Quarter of 2025

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

•Retail Revenues increased $408 million primarily due to the following:

•A $261 million increase in base rate and rider revenues.

•A $99 million increase in weather-related usage primarily in the residential class driven by a 24% increase in cooling degree days primarily in the western region.

•A $45 million increase in weather-normalized revenues primarily in the commercial and industrial classes, partially offset by a decrease in the residential class.

These increases were partially offset by:

•An $18 million decrease at SWEPCo due to a credit to certain existing wholesale generation customers.

•Off-system Sales increased $5 million primarily due to Rockport Plant, Unit 2 merchant sales, economic hedging activity at I&M and margins in July 2026 attributable to increased PJM prices at APCo.

•Transmission Revenues increased $1 million primarily due to the following:

• A $15 million increase due to continued transmission investment.

This increase was partially offset by:

•A $12 million decrease due to the repayment of SPP upgrade credits, offset by an equal amount of incremental SPP upgrade costs in Other Operation and Maintenance expenses.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $47 million primarily due to decreases at APCo and PSO, partially offset by increases at I&M and SWEPCo.

•Other Operation and Maintenance expenses increased $120 million primarily due to the following:

•A $63 million increase in generation expenses due to outage and non-outage maintenance, nuclear and renewable energy.

•A $32 million increase in employee-related costs.

•A $30 million increase in storm expenses.

These increases were partially offset by:

•A $24 million decrease due to the refund of SPP upgrade costs at PSO and SWEPCo.

•Depreciation and Amortization expenses increased $112 million primarily due to the following:

•A $79 million increase due to a higher depreciable base at I&M and PSO.

•A $28 million increase at APCo primarily due to a July 2026 order approving a final true-up to recover past West Virginia MRBC costs.

These increases were partially offset by:

•A $5 million decrease at I&M due to Michigan PTC deferral activity.

•Allowance for Equity Funds Used During Construction increased $5 million primarily due to a higher AFUDC base and higher equity return rates at I&M and PSO.

•Non-Service Cost Components of Net Periodic Benefit Cost increased $7 million primarily due to the continued recognition of unfavorable 2022 pension plan asset returns used to calculate the 2026 pension expense.

•Interest Expense increased $61 million primarily due to higher long-term debt balances.

•Income Tax Benefit decreased $45 million primarily due to the following:

•A $42 million decrease due to a decrease in PTCs.

•A $35 million decrease due to an increase in pretax book income.

These decreases were partially offset by:

•A $16 million increase due to a decrease in flow-through expense.

•A $12 million increase due to a decrease in state taxes.

•A $7 million increase due to a decrease in flow-through CAMT expense.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

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

•Retail Revenues increased $759 million primarily due to the following:

•A $632 million increase in base rate and rider revenues.

•A $157 million increase in weather-normalized revenues primarily in the commercial and industrial classes, partially offset by a decrease in the residential class.

•A $72 million increase in weather-related usage primarily in the residential class driven by a 19% increase in cooling degree days primarily in the western region.

These increases were partially offset by:

•A $107 million decrease in fuel revenues primarily due to decreases at APCo, PSO and SWEPCo, partially offset by an increase at I&M.

•A $41 million decrease at SWEPCo due to a credit to certain existing wholesale generation customers.

•Off-system Sales increased $52 million primarily due to Rockport Plant, Unit 2 merchant sales during Winter Storm Fern in January 2026, partially offset by a decrease in merchant sales and economic hedging activity at I&M and margins in July 2026 attributable to increased PJM prices at APCo.

•Transmission Revenues increased $13 million primarily due to the following:

•A $78 million increase due to continued transmission investment.

This increase was partially offset by:

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

•A $12 million decrease due to the repayment of SPP upgrade credits, offset by lower SPP upgrade costs in Other Operation and Maintenance expenses.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $68 million primarily due to decreases at APCo, PSO and SWEPCo, partially offset by an increase at I&M.

•Other Operation and Maintenance expenses increased $327 million primarily due to the following:

•A $137 million increase in generation expenses due to outage and non-outage maintenance, nuclear and renewable energy.

•A $63 million increase in employee-related costs.

•A $62 million increase in storm expenses.

•A $29 million increase in vegetation management costs.

•An $11 million increase in distribution-related expenses driven by system improvements, reliability programs, meters and transformers, customer driven third-party work and amortization of storm-related regulatory assets.

These increases were partially offset by:

•A $24 million decrease due to the refund of SPP upgrade costs at PSO and SWEPCo.

•Asset Impairments and Other Related Charges increased $31 million due to the probable, partial disallowance of the Pirkey Plant net book value in the 2025 Texas Base Rate Case at SWEPCo.

•Depreciation and Amortization expenses increased $193 million primarily due to the following:

•A $145 million increase primarily due to a higher depreciable base at I&M, PSO and SWEPCo.

•A $26 million increase at APCo primarily due to the cumulative regulatory deferral true-up for the impact of CAMT expense incurred related to IRS Notice 2026-07 allowing tax repair deductions in the calculation of CAMT.

•An $8 million increase due to NOLC-related Excess ADIT deferrals recorded in 2025 and the amortization of these deferrals recorded in 2026 for IURC approved recovery through I&M’s Indiana tax rider.

These increases were partially offset by:

•An $11 million decrease at I&M due to Michigan PTC deferral activity.

•A $5 million decrease at SWEPCo primarily due to higher over-recovery of costs and allowable returns associated with generation rider recovery.

•Taxes Other Than Income Taxes increased $35 million primarily due to the following:

•A $21 million increase in property taxes at APCo, PSO and SWEPCo.

•A $7 million increase due to higher business and occupation taxes at APCo.

•Allowance for Equity Funds Used During Construction increased $17 million primarily due to a higher AFUDC base and higher equity return rates primarily at I&M, KPCo and SWEPCo.

•Non-Service Cost Components of Net Periodic Benefit Cost increased $19 million primarily due to the continued recognition of unfavorable 2022 pension plan asset returns used to calculate the 2026 pension expense.

•Interest Expense increased $168 million primarily due to higher long-term debt balances.

•Income Tax Benefit decreased $25 million primarily due to the following:

•A $114 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.

•A $28 million decrease due to an increase in pretax book income.

These decreases were partially offset by:

•A $70 million increase due to an increase in PTCs.

•A $31 million increase due to the cumulative true-up of CAMT related to IRS Notice 2026-07 allowing tax repair deductions in the calculation of CAMT.

•A $12 million increase due to a decrease in state taxes.

TRANSMISSION AND DISTRIBUTION UTILITIES

Summary of KWh Energy Sales for Transmission and Distribution Utilities


	Three Months Ended September 30,		Nine Months Ended September 30,
	2026	2025	2026	2025
	(in millions of KWhs)
Retail:
Residential	8,726	8,256	21,377	21,566
Commercial	14,885	12,610	40,623	33,240
Industrial	8,084	7,009	23,060	20,813
Miscellaneous	218	209	555	553
Total Retail (a)	31,913	28,084	85,615	76,172

Wholesale (b)	2	552	901	1,683

Total KWhs	31,915	28,636	86,516	77,855

(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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2026	2025	2026	2025
	(in degree days)
Eastern Region
Actual – Heating	—	—	1,996	2,077
Normal – Heating	2	3	1,993	1,996

Actual – Cooling	794	734	1,115	1,076
Normal – Cooling	704	707	1,032	1,032

Western Region
Actual – Heating	—	—	144	296
Normal – Heating	—	—	215	208

Actual – Cooling	1,611	1,367	2,735	2,520
Normal – Cooling	1,347	1,348	2,382	2,369


Transmission and Distribution Utilities
Reconciliation of 2025 to 2026 Earnings Attributable to AEP Common Shareholders
(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Earnings Attributable to AEP Common Shareholders	$	267	$	656

Changes in Revenues:
Retail Revenues	210		345
Off-system Sales	(32)		(13)
Transmission Revenues	14		66
Other Revenues	(14)		(4)
Total Change in Revenues	178		394

Changes in Expenses and Other:
Purchased Electricity for Resale	14		27
Purchased Electricity from AEP Affiliates	(8)		(13)
Other Operation and Maintenance	(141)		(258)

Depreciation and Amortization	(21)		(44)

Taxes Other Than Income Taxes	(11)		(37)


Other Income	4		3
Allowance for Equity Funds Used During Construction	12		27
Non-Service Cost Components of Net Periodic Benefit Cost	(3)		(1)
Interest Expense	(12)		(23)
Total Change in Expenses and Other	(166)		(319)

Income Tax Expense	6		14
Equity Earnings of Unconsolidated Subsidiary	(1)		(2)

2026 Earnings Attributable to AEP Common Shareholders	$	284	$	743

Third Quarter of 2026 Compared to Third Quarter of 2025

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

•Retail Revenues increased $210 million primarily due to the following:

•A $141 million increase in rider revenues in Ohio and Texas.

•A $40 million increase due to higher prices for purchased power to serve OPCo’s SSO customers.

•A $19 million increase in weather-related usage primarily due to an 18% increase in cooling degree days in Texas and an 8% increase in cooling degree days in Ohio.

•A $10 million increase in weather-normalized revenues primarily in the commercial and industrial classes in Ohio.

•Off-system Sales decreased $32 million primarily due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

•Transmission Revenues increased $14 million primarily due to continued transmission investment in Ohio and Texas.

•Other Revenues decreased $14 million primarily due to the following:

•An $8 million decrease primarily due to lower third-party Legacy Generation Resource Rider revenues as a result of approved legislation in Ohio in May 2025, which ended the retail recovery of OVEC purchased power costs.

•A $5 million decrease primarily due to a reduction in the PUCT authorized cap on Texas energy efficiency utility incentives.

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

•Purchased Electricity for Resale expenses decreased $14 million primarily due to the following:

•A $34 million decrease in OVEC purchased power costs due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

•An $8 million decrease as a result of legislation approved in Ohio in 2025 related to the elimination of OPCo’s ability to recover from, or refund to, customers the difference between purchased power expenses from OVEC and OVEC-related revenues from PJM.

•A $2 million decrease in recoverable alternative energy rider expenses.

These decreases were partially offset by:

•A $36 million increase in recoverable auction purchases to serve SSO customers in Ohio.

•Purchased Electricity from AEP Affiliates increased $8 million primarily due to an increase in recoverable purchases to serve SSO customers in Ohio.

•Other Operation and Maintenance expenses increased $141 million primarily due to the following:

•An $86 million increase primarily due to an increase in recoverable PJM transmission expenses in Ohio.

•A $14 million increase in transmission and distribution expenses in Texas.

•A $14 million increase in distribution expenses primarily related to recoverable storm restoration costs and recoverable vegetation management expenses in Ohio.

•A $7 million increase due to recoverable Transmission Cost Recovery Factor expenses in Texas.

•A $7 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.

•Depreciation and Amortization expenses increased $21 million primarily due to a higher depreciable base in Ohio and Texas.

•Taxes Other Than Income Taxes increased $11 million primarily due to higher property taxes in Ohio.

•Allowance for Equity Funds Used During Construction increased $12 million primarily due to a higher AFUDC base in Texas.

•Interest Expense increased $12 million primarily due to the following:

•A $14 million increase due to higher long-term debt balances in Texas.

•A $10 million increase due to interest on customer deposits in Texas from ERCOT’s Batch Zero process.

These increases were partially offset by:

•A $6 million decrease due to an increase in the debt component of AFUDC in Texas.

•A $5 million decrease due to the deferral of eligible costs related to the UTM in Texas.

•Income Tax Expense decreased $6 million primarily due to an increase in Excess ADIT credits refunded to customers as approved in the 2025 Ohio base rate case.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

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

•Retail Revenues increased $345 million primarily due to the following:

•A $232 million increase in rider revenues in Ohio and Texas.

•A $99 million increase due to higher prices for purchased power to serve OPCo’s SSO customers.

•A $33 million increase in weather-normalized revenues primarily in the residential and commercial classes in Ohio and Texas.

These increases were partially offset by:

•A $20 million decrease in weather-related usage primarily driven by a 4% decrease in heating degree days in Ohio and less extreme weather conditions in the first six months of 2026 compared to the same period in 2025 in Texas.

•Off-system Sales decreased $13 million primarily due to the following:

•A $32 million decrease due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

This decrease was partially offset by:

•An $18 million increase due to increased sales of OPCo’s OVEC purchased power in the first half of 2026 driven by higher market prices and volumes.

•Transmission Revenues increased $66 million primarily due to continued transmission investment in Ohio and Texas.

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

•Purchased Electricity for Resale expenses decreased $27 million primarily due to the following:

•A $57 million decrease in OVEC purchased power costs due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

•A $52 million decrease as a result of legislation approved in Ohio in 2025 related to the elimination of OPCo’s ability to recover from, or refund to, customers the difference between purchased power expenses from OVEC and OVEC-related revenues from PJM.

These decreases were partially offset by:

•An $86 million increase in recoverable auction purchases to serve SSO customers in Ohio.

•Purchased Electricity from AEP Affiliates expenses increased $13 million primarily due to an increase in recoverable purchases to serve SSO customers in Ohio.

•Other Operation and Maintenance expenses increased $258 million primarily due to the following:

•A $151 million increase in transmission expenses primarily due to a $134 million increase in recoverable PJM transmission expenses and a $12 million increase in recoverable vegetation management expenses in Ohio.

•A $28 million increase in distribution expenses primarily related to recoverable vegetation management expenses and recoverable storm restoration costs in Ohio.

•A $22 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.

•An $18 million increase due to the partial disallowance of regulatory assets associated with the UTM deferrals in Texas.

•A $14 million increase in transmission and distribution expenses in Texas.

•A $13 million increase in administrative and general expenses primarily due to employee-related expenses in Texas.

•Depreciation and Amortization expenses increased $44 million due to a higher depreciable base in Ohio and Texas.

•Taxes Other Than Income Taxes increased $37 million due to the following:

•A $25 million increase due to higher property taxes in Ohio.

•An $8 million increase in state excise taxes due to increased billed KWhs in Ohio.

•Allowance for Equity Funds Used During Construction increased $27 million primarily due to a higher AFUDC base in Texas.

•Interest Expense increased $23 million primarily due to the following:

•A $38 million increase due to higher long-term debt balances in Texas.

•An $11 million increase due to interest on customer deposits in Texas from ERCOT’s Batch Zero process.

These increases were partially offset by:

•A $15 million decrease due to an increase in the debt component of AFUDC in Texas.

•An $11 million decrease due to the deferral of eligible costs related to the UTM in Texas.

•Income Tax Expense decreased $14 million primarily due to the following:

•A $23 million decrease due to an increase in Excess ADIT credits refunded to customers as approved in the 2025 Ohio base rate case.

•A $5 million decrease due to an increase in AFUDC equity.

This decrease was partially offset by:

•An $16 million increase due to an increase in pretax book income in Ohio.

AEP TRANSMISSION HOLDCO

Summary of Investment in Transmission Assets for AEP Transmission Holdco


	September 30,
	2026		2025
	(in millions)
Plant in Service	$	18,629	$	16,877
Construction Work in Progress	2,990		2,376
Accumulated Depreciation and Amortization	2,224		1,891
Total Transmission Property, Net	$	19,395	$	17,362



AEP Transmission Holdco
Reconciliation of 2025 to 2026
Earnings Attributable to AEP Members from AEP Transmission Holdco
(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Earnings Attributable to AEP Members from AEP Transmission Holdco	$	200	$	1,013

Changes in Transmission Revenues:
Transmission Revenues	42		(49)
Total Change in Transmission Revenues	42		(49)

Changes in Expenses and Other:
Other Operation and Maintenance	(12)		(39)
Depreciation and Amortization	(12)		(36)
Taxes Other Than Income Taxes	10		(14)
Interest and Investment Income	2		4

Allowance for Equity Funds Used During Construction	5		9
Non-Service Cost Components of Net Periodic Pension Cost	—		(1)
Interest Expense	(8)		(29)
Total Change in Expenses and Other	(15)		(106)

Income Tax Expense	(8)		(210)
Equity Earnings of Unconsolidated Subsidiaries	4		7
Net Income Attributable to Noncontrolling Interests	(4)		(2)

2026 Earnings Attributable to AEP Members from AEP Transmission Holdco	$	219	$	653

Third Quarter of 2026 Compared to Third Quarter of 2025

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

•Transmission Revenues increased $42 million primarily due to continued transmission investment.

Expenses and Other and Income Tax Expense:

•Other Operation and Maintenance expenses increased $12 million primarily due to the following:

•A $6 million increase in employee-related costs.

•A $2 million increase in vegetation management and facility compliance costs.

•A $2 million increase in affiliated rent and shared services.

•Depreciation and Amortization expenses increased $12 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes decreased $10 million primarily due to prior period adjustments in Ohio, partially offset by higher property taxes associated with increased transmission investment.

•Allowance for Equity Funds Used During Construction increased $5 million primarily due to a higher CWIP base.

•Interest Expense increased $8 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $8 million primarily due to an increase in pretax book income.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

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

•Transmission Revenues decreased $49 million primarily due to the following:

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

This decrease was partially offset by:

•A $161 million increase due to continued transmission investment.

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

•Other Operation and Maintenance expenses increased $39 million primarily due to the following:

•A $16 million increase in employee-related costs.

•A $12 million increase in vegetation management and facility compliance costs.

•A $7 million increase in affiliated rent and shared services.

•Depreciation and Amortization expenses increased $36 million due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $14 million primarily due to higher property taxes associated with increased transmission investment, partially offset by prior period adjustments in Ohio.

•Allowance for Equity Funds Used During Construction increased $9 million primarily due to a higher CWIP base and higher equity rates.

•Interest Expense increased $29 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $210 million primarily due to the following:

•A $254 million increase 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 increase was partially offset by:

•A $31 million decrease due to a decrease in pretax book income.

•A $5 million decrease due to a decrease in state taxes.

•Equity Earnings of Unconsolidated Subsidiaries increased $7 million primarily due to higher pretax earnings at ETT.

•Net Income Attributable to Noncontrolling Interests increased $2 million primarily due to the following:

•A $56 million increase primarily due to the Midwest Transmission Holdings noncontrolling interest transaction that closed in June 2025.

This increase was partially offset by:

•A $54 million decrease due to higher 2025 earnings for Midwest Transmission Holdings due to the impact of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

GENERATION & MARKETING



Reconciliation of 2025 to 2026 Earnings Attributable to AEP Common Shareholders
(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Earnings Attributable to AEP Common Shareholders	$	45	$	209

Changes in Revenues:
Retail, Trading and Marketing	116		384
Merchant Generation	64		108
Other Revenues	58		94
Total Change in Revenues	238		586

Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(167)		(533)
Other Operation and Maintenance	(13)		2

Depreciation and Amortization	(1)		(2)

Interest and Investment Income	5		14

Non-Service Cost Components of Net Periodic Benefit Cost	—		(1)
Interest Expense	(1)		—
Total Change in Expenses and Other	(177)		(520)

Income Tax Expense	(10)		(7)



2026 Earnings Attributable to AEP Common Shareholders	$	96	$	268

Third Quarter of 2026 Compared to Third Quarter of 2025

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

•Retail, Trading and Marketing increased $116 million primarily due to higher market prices in 2026.

•Merchant Generation increased $64 million primarily due to higher realized prices in 2026.

•Other Revenues increased $58 million primarily due to continued progress on customer infrastructure projects in 2026.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $167 million primarily due to an increase in energy costs in 2026.

•Other Operation and Maintenance expenses increased $13 million primarily due to continued progress on customer infrastructure projects in 2026, partially offset by renewable contract modification proceeds.

•Interest and Investment Income increased $5 million primarily due to an increase in interest income due to higher advances to affiliates.

•Income Tax Expense increased $10 million primarily due to an increase in pretax book income.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

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

•Retail, Trading and Marketing increased $384 million primarily due to higher market prices in 2026, partially offset by reduced MTM hedging gains.

•Merchant Generation increased $108 million primarily due to higher realized prices in 2026.

•Other Revenues increased $94 million primarily due to continued progress on customer infrastructure projects in 2026.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $533 million primarily due to an increase in energy costs in 2026.

•Interest and Investment Income increased $14 million primarily due to an increase in interest income due to higher advances to affiliates.

•Income Tax Expense increased $7 million primarily due to an increase in pretax book income.

CORPORATE AND OTHER

Third Quarter of 2026 Compared to Third Quarter of 2025

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $118 million in 2025 to a loss of $109 million in 2026 primarily due to:

•A $71 million increase in Income Tax Benefit primarily due to the following:

•A $44 million increase due to an increase in PTCs.

•A $10 million increase due to a decrease in pretax book income.

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

This increase in earnings was partially offset by:

•A $36 million increase in interest expense primarily due to higher long-term debt balances.

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

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $215 million in 2025 to a loss of $333 million in 2026 primarily due to:

•A $74 million increase in interest expense primarily due to higher long-term debt balances.

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

•An $11 million decrease in the recognition of deferred revenues on completed contracts.

These decreases in earnings were partially offset by:

•A $20 million increase in Income Tax Benefit primarily due to the following:

•A $26 million increase due to a decrease in pretax book income.

•A $7 million increase due to an increase in PTCs.

These increases were partially offset by:

•A $17 million decrease due to an increase in state taxes.

AEP CONSOLIDATED INCOME TAXES

Third Quarter of 2026 Compared to Third Quarter of 2025

Income Tax Expense decreased $14 million primarily due to:

•A $22 million decrease due to an increase in flow-through benefits primarily driven by AFUDC equity.

•A $21 million decrease due to a decrease in state taxes.

•A $7 million decrease due to a decrease in flow-through CAMT expense.

•A $4 million decrease due to an increase in excess ADIT asset reversals.

•A $2 million decrease due to an increase in PTCs.

These decreases were partially offset by:

•A $46 million increase due to an increase in pretax book income.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

Income Tax Expense increased $208 million primarily due to:

•A $368 million increase 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 increase was partially offset by:

•A $76 million decrease due to an increase in PTCs.

•A $31 million decrease due to the cumulative true-up of CAMT related to IRS Notice 2026-07 allowing tax repair deductions in the calculation of CAMT.

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

•A $13 million decrease due to an increase in flow-through benefits primarily driven by AFUDC equity.

•A $13 million decrease due to favorable discrete adjustments.

FINANCIAL CONDITION

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

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization


	September 30, 2026				December 31, 2025
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	52,541	59.4	%	$	47,322	58.4	%
Short-term Debt	1,875		2.1		1,508		1.9
Total Debt	54,416		61.5		48,830		60.3
AEP Common Equity	32,775		37.1		31,138		38.4
Noncontrolling Interests	1,268		1.4		1,080		1.3
Total Debt and Equity Capitalization	$	88,459	100.0	%	$	81,048	100.0	%

AEP’s ratio of debt-to-total capital increased from 60.3% to 61.5% as of December 31, 2025 and September 30, 2026, respectively, primarily due to 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 September 30, 2026, AEP had $8 billion of 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.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments. As of September 30, 2026, available liquidity was approximately $7.4 billion as illustrated in the table below:

Amount

Maturity

Commercial Paper:

(in millions)

Revolving Credit Facility

6,500

April 2031

Revolving Credit Facility

1,500

April 2029

Cash and Cash Equivalents

418

Total Liquidity Sources

8,418

Less:

AEP Commercial Paper Outstanding

975

Net Available Liquidity

7,443

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 the first nine months of 2026 was $2.1 billion. The weighted-average interest rate for AEP’s commercial paper for the nine months ended September 30, 2026 was 3.94%.

Other Credit Facilities

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 seven uncommitted facilities totaling $850 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of September 30, 2026 was $525 million with maturities ranging from October 2026 to September 2027.

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 2028. As of September 30, 2026, 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 September 30, 2026, this contractually defined percentage was 56.0%. 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.

ATM Program

In November 2025, AEP filed a prospectus supplement under which it may sell up to $3.5 billion of its common stock through an ATM program. In the first quarter of 2026, two million shares of common stock were issued for $264 million in net proceeds. In addition to these issuances and sales of shares of common stock, AEP also may use the ATM program to enter into forward sale agreements. As of September 30, 2026, AEP had issued six million shares in forward sale agreements through its ATM program with expected proceeds of $684 million.

See “Forward Equity Agreements” section of Note 12 for additional information regarding shares issued or expected to be issued under forward sale agreements.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.97 per share in October 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 12 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.

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.


	Nine Months Ended September 30,
	2026		2025
	(in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	$	268	$	246
Net Cash Flows from Operating Activities	5,767		5,131
Net Cash Flows Used for Investing Activities	(11,171)		(7,749)
Net Cash Flows from Financing Activities	5,643		3,479

Net Increase in Cash, Cash Equivalents and Restricted Cash	239		861
Cash, Cash Equivalents and Restricted Cash at End of Period	$	507	$	1,107

Operating Activities


	Nine Months Ended September 30,
	2026		2025
	(in millions)
Net Income	$	2,868	$	3,091
Non-Cash Adjustments to Net Income (a)	3,162		2,517
Mark-to-Market of Risk Management Contracts	(116)		(193)
Pension Contributions to Qualified Plan Trust	—		(95)
Property Taxes	564		541

Deferred Fuel Over/Under-Recovery, Net	133		165


Change in Other Noncurrent Assets	(838)		(720)
Change in Other Noncurrent Liabilities	673		134
Change in Certain Components of Working Capital	(679)		(309)
Net Cash Flows from Operating Activities	$	5,767	$	5,131

(a)Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Deferred Income Taxes, Asset Impairments and Other Related Charges and AFUDC.

Net Cash Flows from Operating Activities increased by $636 million primarily due to the following:

•A $539 million increase in cash from Change in Other Noncurrent Liabilities. This increase is primarily due to the increase in customer deposits, the timing of deferred revenue on customer infrastructure projects and changes in regulatory liabilities driven by timing differences in refunds to customers under rate rider mechanisms.

•A $422 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.

•A $95 million increase in cash due to a discretionary contribution to the qualified pension plan made in 2025. See Note 7 - Benefit Plans for additional information.

•A $47 million increase in cash due to changes in risk management contract collateral positions.

These increases in cash were partially offset by:

•A $370 million decrease in cash from the Change in Certain Components of Working Capital. This decrease is primarily due to timing of accounts receivable collections and an increase in fuel, materials and supplies driven by higher coal inventory on hand, partially offset by the increase in customer deposits.

Investing Activities


	Nine Months Ended September 30,
	2026		2025
	(in millions)
Construction Expenditures	$	(9,107)	$	(6,001)
Acquisitions of Generation Facilities	(2,394)		(1,657)
Acquisitions of Nuclear Fuel	(97)		(89)



Contribution in Aid of Construction Advances	572		148
Other	(145)		(150)
Net Cash Flows Used for Investing Activities	$	(11,171)	$	(7,749)

Net Cash Flows Used for Investing Activities increased by $3.4 billion primarily due to the following:

•A $3.1 billion increase in Construction Expenditures primarily due to increases in Vertically Integrated Utilities of $1.1 billion, Transmission and Distribution Utilities of $1 billion and AEP Transmission Holdco of $600 million.

•A $737 million increase primarily due to the acquisitions of five generation facilities in 2026. See “Acquisitions” section of Note 6 for additional information.

This increase was partially offset by:

•A $424 million decrease due to higher contributions in aid of construction primarily due to increases in Transmission and Distribution Utilities of $237 million and AEP Transmission Holdco of $185 million.

Financing Activities


	Nine Months Ended September 30,
	2026		2025
	(in millions)
Issuance of Common Stock	$	417	$	187
Issuance/Retirement of Debt, Net	5,559		2,079


Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs	—		2,783
Dividends Paid on Common Stock	(1,558)		(1,498)
Security Deposits	1,199		—
Other	26		(72)
Net Cash Flows from Financing Activities	$	5,643	$	3,479

Net Cash Flows from Financing Activities increased by $2.2 billion primarily due to the following:

•A $1.7 billion increase due to changes in short-term debt.

•A $1.2 billion increase in security deposits primarily due to the collection of additional deposits under ERCOT’s Batch Zero process.

•A $970 million decrease in retirements of long-term debt. See Note 12 - Financing Activities for additional information.

•A $777 million increase in issuances of long-term debt. See Note 12 - Financing Activities for additional information.

•A $230 million increase in issuances of common stock primarily under AEP’s ATM Program. See Note 12 - Financing Activities for additional information.

These increases in cash were partially offset by:

•A $2.8 billion decrease due to proceeds from the 2025 Midwest Transmission Holdings Noncontrolling Interest transaction. See “Noncontrolling Interest in Midwest Transmission Holdings” section of Note 6 for additional information.

See the “Financing Activities Subsequent Events” section of Note 12 for Long-term debt and other securities issued, retired and principal payments made after September 30, 2026 through October 28, 2026, the date that the third quarter Form 10-Q was filed.

BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately $15.6 billion of capital expenditures in 2026. For the five-year period, 2027 through 2031, management forecasts capital expenditures of $100.4 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 2027-2031 estimated capital expenditures by Business Segment are as follows:



Segment	2027-2031 Budgeted Capital Expenditures
	(in billions)
Vertically Integrated Utilities	$	52.2
Transmission and Distribution Utilities	23.6
AEP Transmission Holdco	18.1
Generation & Marketing	4.4
Corporate and Other	2.1
Total	$	100.4

SIGNIFICANT CASH REQUIREMENTS

A summary of significant cash requirements is included in the 2025 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING STANDARDS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2025 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and asset retirement obligations.

ACCOUNTING STANDARDS

See Note 2 - New Accounting Standards for information related to accounting standards and SEC rulemaking activity.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For a detailed discussion of AEP’s market risks, see “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A of AEP's Annual Report on Form 10-K for the year ended December 31, 2025. During the nine months ended September 30, 2026, there were no material changes to disclosures about market risk, inclusive of credit risk, value at risk associated with risk management contracts and interest rate risk. See Note 9 – Derivatives and Hedging and Note 10 – Fair Value Measurements for additional information related to risk management contracts.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions, except per-share and share amounts)

(Unaudited)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,

	2026		2025		2026		2025
REVENUES
Vertically Integrated Utilities	$	3,923	$	3,511	$	10,338	$	9,531
Transmission and Distribution Utilities	1,853		1,680		5,015		4,638
Generation & Marketing	922		694		2,546		1,976
Other Revenues	134		126		398		416
TOTAL REVENUES	6,832		6,011		18,297		16,561

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	2,087		1,981		5,808		5,375

Other Operation	1,028		798		2,592		2,088
Maintenance	447		405		1,302		1,114


Asset Impairments and Other Related Charges	—		—		31		—


Depreciation and Amortization	1,025		879		2,842		2,566
Taxes Other Than Income Taxes	433		426		1,303		1,213
TOTAL EXPENSES	5,020		4,489		13,878		12,356

OPERATING INCOME	1,812		1,522		4,419		4,205

Other Income (Expense):


Other Income	6		12		26		35
Allowance for Equity Funds Used During Construction	81		59		226		173
Non-Service Cost Components of Net Periodic Benefit Cost	25		34		82		104

Interest Expense	(606)		(509)		(1,743)		(1,493)

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	1,318		1,118		3,010		3,024

Income Tax Expense	125		139		221		13
Equity Earnings of Unconsolidated Subsidiaries	25		21		79		80





NET INCOME	1,218		1,000		2,868		3,091

Net Income Attributable to Noncontrolling Interests	31		28		94		93

EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1,187	$	972	$	2,774	$	2,998

WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	544,431,979		534,867,357		543,566,814		534,186,206



TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	2.18	$	1.82	$	5.10	$	5.61

WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	550,103,235		537,988,799		549,270,434		536,364,715



TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	2.16	$	1.81	$	5.05	$	5.59



See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2026		2025		2026		2025
Net Income	$	1,218	$	1,000	$	2,868	$	3,091

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $1 and $(4) for the Three Months Ended September 30, 2026 and 2025, Respectively, and $3 and $(7) for the Nine Months Ended September 30, 2026 and 2025, Respectively	5		(16)		12		(26)

Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2026 and 2025, Respectively, and $1 and $0 for the Nine Months Ended September 30, 2026 and 2025, Respectively	1		—		3		1


TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	6		(16)		15		(25)

TOTAL COMPREHENSIVE INCOME	1,224		984		2,883		3,066

Total Comprehensive Income Attributable To Noncontrolling Interests	31		28		94		93

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1,193	$	956	$	2,789	$	2,973

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	AEP Common Shareholders
	Common Stock								Accumulated Other Comprehensive Income (Loss)
	Shares	Amount		Paid-in Capital		Retained Earnings					Noncontrolling Interests		Total
TOTAL EQUITY – DECEMBER 31, 2024	534	$	3,472	$	9,606	$	13,869		$	(3)	$	42	$	26,986

Issuance of Common Stock	1	7		68									75
Common Stock Dividends						(500)		(a)			(1)		(501)
Other Changes in Equity				(22)									(22)
Net Income						800					2		802
Other Comprehensive Income									24				24
TOTAL EQUITY – MARCH 31, 2025	535	3,479		9,652		14,169			21		43		27,364

Issuance of Common Stock	1	4		53									57
Common Stock Dividends						(499)		(a)			(1)		(500)
Other Changes in Equity				8									8

Midwest Transmission Holdings NCI Transaction				1,791							992		2,783
Net Income						1,226					63		1,289
Other Comprehensive Loss									(33)				(33)
TOTAL EQUITY – JUNE 30, 2025	536	3,483		11,504		14,896			(12)		1,097		30,968

Issuance of Common Stock	—	3		52									55
Capital Contributions from NCI											34		34
Common Stock Dividends						(499)		(a)					(499)
Dividends Paid to NCI											(69)		(69)
Other Changes in Equity				6									6

Net Income						972					28		1,000
Other Comprehensive Loss									(16)				(16)
TOTAL EQUITY – SEPTEMBER 30, 2025	536	$	3,486	$	11,562	$	15,369		$	(28)	$	1,090	$	31,479

TOTAL EQUITY – DECEMBER 31, 2025	542	$	3,523	$	12,138	$	15,441		$	36	$	1,080	$	32,218

Issuance of Common Stock	3	21		337									358
Capital Contributions from NCI											96		96
Common Stock Dividends						(520)		(a)					(520)
Dividends Paid to NCI											(35)		(35)
Other Changes in Equity				(28)									(28)

Net Income						874					29		903
Other Comprehensive Loss									(14)				(14)
TOTAL EQUITY – MARCH 31, 2026	545	3,544		12,447		15,795			22		1,170		32,978

Issuance of Common Stock	1	2		45									47
Capital Contributions from NCI											60		60
Common Stock Dividends						(519)		(a)					(519)
Dividends Paid to NCI											(54)		(54)
Other Changes in Equity				7									7

Net Income						713					34		747
Other Comprehensive Income									23				23
TOTAL EQUITY – JUNE 30, 2026	546	3,546		12,499		15,989			45		1,210		33,289

Issuance of Common Stock	—	1		11									12
Capital Contributions from NCI											113		113
Common Stock Dividends						(519)		(a)					(519)
Dividends Paid to NCI											(86)		(86)
Other Changes in Equity				10									10
Net Income						1,187					31		1,218
Other Comprehensive Income									6				6
TOTAL EQUITY – SEPTEMBER 30, 2026	546	$	3,547	$	12,520	$	16,657		$	51	$	1,268	$	34,043

(a) Cash dividends declared per AEP common share were $0.95 and $0.93 in 2026 and 2025, respectively.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2026 and December 31, 2025

(in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	418	$	197
Restricted Cash (September 30, 2026 and December 31, 2025 Amounts Include $89 and $71, Respectively, Related to Restoration Funding, Appalachian Consumer Rate Relief Funding, Appalachian Recovery Funding, Storm Recovery Funding and Cost Recovery Funding)	89		71
Other Temporary Investments (September 30, 2026 and December 31, 2025 Amounts Include $239 and $209, Respectively, Related to EIS)	252		220
Accounts Receivable:
Customers	1,421		1,166
Accrued Unbilled Revenues	422		421
Pledged Accounts Receivable – AEP Credit	1,600		1,272
Miscellaneous	101		60
Allowance for Credit Losses	(54)		(52)
Total Accounts Receivable	3,490		2,867
Fuel	506		576
Materials and Supplies	1,287		1,046
Risk Management Assets	588		352
Accrued Tax Benefits	344		85
Regulatory Asset for Under-Recovered Fuel Costs	504		426


Prepayments and Other Current Assets	362		212
TOTAL CURRENT ASSETS	7,840		6,052

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	27,674		28,388
Transmission	44,509		42,557
Distribution	35,251		33,364
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	9,843		8,635
Construction Work in Progress	10,907		7,635
Total Property, Plant and Equipment	128,184		120,579
Accumulated Depreciation and Amortization	27,956		28,205
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	100,228		92,374

OTHER NONCURRENT ASSETS
Regulatory Assets	4,967		4,804
Securitized Assets	2,221		933
Spent Nuclear Fuel and Decommissioning Trusts	5,256		4,916
Goodwill	53		53
Long-term Risk Management Assets	266		265
Operating Lease Assets	660		661
Deferred Charges and Other Noncurrent Assets	4,204		4,402
TOTAL OTHER NONCURRENT ASSETS	17,627		16,034

TOTAL ASSETS	$	125,695	$	114,460

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

September 30, 2026 and December 31, 2025

(in millions, except per-share and share amounts)

(Unaudited)


			September 30,		December 31,
			2026		2025
CURRENT LIABILITIES
Accounts Payable			$	3,944	$	3,429
Short-term Debt:
Securitized Debt for Receivables – AEP Credit			900		900
Other Short-term Debt			975		608
Total Short-term Debt			1,875		1,508
Long-term Debt Due Within One Year (September 30, 2026 and December 31, 2025 Amounts Include $201 and $207, Respectively, Related to DCC Fuel, Restoration Funding, Appalachian Consumer Rate Relief Funding, Appalachian Recovery Funding, Storm Recovery Funding, Transource Energy and Cost Recovery Funding)			2,677		3,194
Risk Management Liabilities			209		132
Customer Deposits			770		507
Accrued Taxes			1,363		2,002
Accrued Interest			719		544
Obligations Under Operating Leases			95		100


Other Current Liabilities			3,634		1,898
TOTAL CURRENT LIABILITIES			15,286		13,314

NONCURRENT LIABILITIES
Long-term Debt (September 30, 2026 and December 31, 2025 Amounts Include $2,519 and $1,294, Respectively, Related to DCC Fuel, Restoration Funding, Appalachian Consumer Rate Relief Funding, Appalachian Recovery Funding, Storm Recovery Funding, Transource Energy and Cost Recovery Funding)			49,864		44,128
Long-term Risk Management Liabilities			214		178
Deferred Income Taxes			11,721		10,951
Regulatory Liabilities and Deferred Investment Tax Credits			8,748		8,362
Asset Retirement Obligations			3,669		3,556
Employee Benefits and Pension Obligations			262		232
Obligations Under Operating Leases			584		578
Deferred Credits and Other Noncurrent Liabilities			1,228		905
TOTAL NONCURRENT LIABILITIES			76,290		68,890

TOTAL LIABILITIES			91,576		82,204

Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)


Contingently Redeemable Performance Share Awards			76		38

EQUITY
Common Stock – Par Value – $6.50 Per Share:
	2026	2025
Shares Authorized	900,000,000	600,000,000
Shares Issued	545,692,925	542,048,288
(1,186,815 Shares were Held in Treasury as of September 30, 2026 and December 31, 2025, Respectively)			3,547		3,523
Paid-in Capital			12,520		12,138
Retained Earnings			16,657		15,441
Accumulated Other Comprehensive Income (Loss)			51		36
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY			32,775		31,138

Noncontrolling Interests			1,268		1,080

TOTAL EQUITY			34,043		32,218

TOTAL LIABILITIES AND EQUITY			$	125,695	$	114,460

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Nine Months Ended September 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	2,868	$	3,091


Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	2,842		2,566

Deferred Income Taxes	515		124


Asset Impairments and Other Related Charges	31		—

Allowance for Equity Funds Used During Construction	(226)		(173)
Mark-to-Market of Risk Management Contracts	(116)		(193)

Pension Contributions to Qualified Plan Trust	—		(95)
Property Taxes	564		541

Deferred Fuel Over/Under-Recovery, Net	133		165




Change in Other Noncurrent Assets	(838)		(720)
Change in Other Noncurrent Liabilities	673		134
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(528)		(212)
Fuel, Materials and Supplies	(162)		151
Accounts Payable	603		327
Accrued Taxes, Net	(899)		(687)

Other Current Assets	(81)		38
Other Current Liabilities	388		74
Net Cash Flows from Operating Activities	5,767		5,131

INVESTING ACTIVITIES
Construction Expenditures	(9,107)		(6,001)

Purchases of Investment Securities	(2,530)		(2,407)
Sales of Investment Securities	2,443		2,349
Acquisitions of Generation Facilities	(2,394)		(1,657)
Acquisitions of Nuclear Fuel	(97)		(89)




Contribution in Aid of Construction Advances	572		148
Other Investing Activities	(58)		(92)
Net Cash Flows Used for Investing Activities	(11,171)		(7,749)

FINANCING ACTIVITIES
Capital Contribution from Noncontrolling Interest	269		34
Issuance of Common Stock	417		187
Issuance of Long-term Debt	7,026		6,249
Issuance of Short-term Debt with Original Maturities greater than 90 Days	—		320
Change in Short-term Debt with Original Maturities less than 90 Days, Net	367		(1,008)
Retirement of Long-term Debt	(1,834)		(2,804)

Redemption of Short-term Debt with Original Maturities Greater than 90 Days	—		(678)

Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs	—		2,783
Dividends Paid on Common Stock	(1,558)		(1,498)
Dividends Paid to Noncontrolling Interest	(175)		(71)

Security Deposits	1,199		—
Other Financing Activities	(68)		(35)
Net Cash Flows from Financing Activities	5,643		3,479





Net Increase in Cash, Cash Equivalents and Restricted Cash	239		861
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	268		246
Cash, Cash Equivalents and Restricted Cash at End of Period	$	507	$	1,107










See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2026	2025	2026	2025
	(in millions of KWhs)
Retail:
Residential	4,608	4,135	10,306	10,326
Commercial	5,684	5,219	15,452	14,037
Industrial	4,477	3,489	12,348	10,159
Miscellaneous	195	186	481	477
Total Retail (a)	14,964	13,029	38,587	34,999

(a)Represents energy delivered to distribution customers.

Summary of Heating and Cooling Degree Days


	Three Months Ended September 30,		Nine Months Ended September 30,
	2026	2025	2026	2025
	(in degree days)
Actual – Heating	—	—	144	296
Normal – Heating	—	—	215	208

Actual – Cooling	1,611	1,367	2,735	2,520
Normal – Cooling	1,347	1,348	2,382	2,369


AEP Texas Inc. and Subsidiaries
Reconciliation of 2025 to 2026
Net Income
(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Net Income	$	166	$	389

Changes in Revenues:
Retail Revenues	38		31

Transmission Revenues	7		40
Other Revenues	(5)		10
Total Change in Revenues	40		81

Changes in Expenses and Other:
Other Operation and Maintenance	(24)		(46)
Depreciation and Amortization	(10)		(19)
Taxes Other Than Income Taxes	(3)		(3)

Interest Income	4		4

Allowance for Equity Funds Used During Construction	10		25
Non-Service Cost Components of Net Periodic Benefit Cost	—		1
Interest Expense	(13)		(23)
Total Change in Expenses and Other	(36)		(61)

Income Tax Expense	2		(4)

2026 Net Income	$	172	$	405

Third Quarter of 2026 Compared to Third Quarter of 2025

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

•Retail Revenues increased $38 million primarily due to the following:

•A $27 million increase in rider revenues.

•A $14 million increase in weather-related usage primarily due to an 18% increase in cooling degree days.

•Transmission Revenues increased $7 million primarily due to continued transmission investment.

•Other Revenues decreased $5 million primarily due to a reduction in the PUCT authorized cap on Texas energy efficiency utility incentives.

Expenses and Other changed between years as follows:

•Other Operation and Maintenance expenses increased $24 million primarily due to the following:

•A $14 million increase in transmission and distribution expenses.

•A $7 million increase due to recoverable Transmission Cost Recovery Factor expenses.

•Depreciation and Amortization expenses increased $10 million primarily due to a higher depreciable base.

•Allowance for Equity Funds Used During Construction increased $10 million primarily due to a higher AFUDC base.

•Interest Expense increased $13 million primarily due to the following:

•A $14 million increase due to higher long-term debt balances.

•A $10 million increase due to interest on customer deposits from ERCOT’s Batch Zero process.

These increases were partially offset by:

•A $6 million decrease due to an increase in the debt component of AFUDC.

•A $5 million decrease due to the deferral of eligible costs related to the UTM.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

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

•Retail Revenues increased $31 million primarily due to the following:

•A $34 million increase in rider revenues.

•A $13 million increase in weather-normalized revenues primarily in the residential and commercial classes.

These increases were partially offset by:

•A $7 million decrease due to Transition Funding customer refunds.

•A $6 million decrease in weather-related usage due to less extreme weather conditions in the first six months of 2026 compared to the same period in 2025.

•Transmission Revenues increased $40 million primarily due to continued transmission investment.

•Other Revenues increased $10 million primarily due to the following:

• A $16 million increase in the taxable portion of payments received from customers for large interconnection projects.

This increase was partially offset by:

•A $7 million decrease primarily due to a reduction in the PUCT authorized cap on Texas energy efficiency utility incentives.

Expenses and Other changed between years as follows:

•Other Operation and Maintenance expenses increased $46 million primarily due to the following:

•An $18 million increase due to the partial disallowance of regulatory assets associated with the UTM deferrals.

•A $14 million increase in transmission and distribution expenses.

•A $13 million increase in administrative and general expenses primarily due to employee-related expenses.

•Depreciation and Amortization expenses increased $19 million primarily due to the following:

•A $27 million increase due to a higher depreciable base.

This increase was partially offset by:

•A $5 million decrease primarily due to the amortization of regulatory liabilities related to Transition Funding customer refunds.

•A $4 million decrease due to the deferral of eligible costs related to the UTM.

•Allowance for Equity Funds Used During Construction increased $25 million primarily due to a higher AFUDC base.

•Interest Expense increased $23 million primarily due to the following:

•A $38 million increase due to higher long-term debt balances.

•A $10 million increase due to interest on customer deposits from ERCOT’s Batch Zero process.

These increases were partially offset by:

•A $15 million decrease due to an increase in the debt component of AFUDC.

•An $11 million decrease due to the deferral of eligible costs related to the UTM.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)



	Three Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
REVENUES
Electric Transmission and Distribution	$	655	$	616	$	1,728	$	1,664
Sales to AEP Affiliates	2		1		5		4
Other Revenues	2		2		21		5
TOTAL REVENUES	659		619		1,754		1,673

EXPENSES

Other Operation	207		187		563		517
Maintenance	28		24		79		79
Depreciation and Amortization	123		113		348		329
Taxes Other Than Income Taxes	49		46		134		131
TOTAL EXPENSES	407		370		1,124		1,056

OPERATING INCOME	252		249		630		617

Other Income (Expense):
Interest Income	4		—		5		1

Allowance for Equity Funds Used During Construction	23		13		62		37

Non-Service Cost Components of Net Periodic Benefit Cost	6		6		18		17
Interest Expense	(79)		(66)		(223)		(200)

INCOME BEFORE INCOME TAX EXPENSE	206		202		492		472

Income Tax Expense	34		36		87		83

NET INCOME	$	172	$	166	$	405	$	389

The common stock of AEP Texas is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
Net Income	$	172	$	166	$	405	$	389

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 for Three Months Ended September 30, 2026 and 2025, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2026 and 2025, Respectively	(1)		—		(1)		(1)




TOTAL COMPREHENSIVE INCOME	$	171	$	166	$	404	$	388

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2024	$	2,093	$	2,795	$	(3)	$	4,885



Net Income			102				102
Other Comprehensive Loss					(1)		(1)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2025	2,093		2,897		(4)		4,986

Capital Contribution from Parent	250						250

Net Income			121				121

TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2025	2,343		3,018		(4)		5,357

Capital Contribution from Parent	201						201


Net Income			166				166

TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2025	$	2,544	$	3,184	$	(4)	$	5,724

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2025	$	2,546	$	3,283	$	(3)	$	5,826


Net Income			120				120

TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2026	2,546		3,403		(3)		5,946

Capital Contribution from Parent	1						1

Net Income			113				113

TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2026	2,547		3,516		(3)		6,060


Return of Capital to Parent	(1)						(1)

Net Income			172				172
Other Comprehensive Loss					(1)		(1)
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2026	$	2,546	$	3,688	$	(4)	$	6,230

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2026 and December 31, 2025

(in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT ASSETS

Restricted Cash (September 30, 2026 and December 31, 2025 Amounts Include $9 and $14, Respectively, Related to Restoration Funding)	$	9	$	14
Advances to Affiliates	389		7
Accounts Receivable:
Customers	298		189
Affiliated Companies	14		15
Accrued Unbilled Revenues	130		101
Miscellaneous	1		—

Total Accounts Receivable	443		305

Materials and Supplies	240		168



Prepayments and Other Current Assets	27		15
TOTAL CURRENT ASSETS	1,108		509

PROPERTY, PLANT AND EQUIPMENT
Electric:

Transmission	8,584		8,229
Distribution	7,382		6,835
Other Property, Plant and Equipment	1,305		1,239
Construction Work in Progress	2,577		1,766
Total Property, Plant and Equipment	19,848		18,069
Accumulated Depreciation and Amortization	2,294		2,205
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	17,554		15,864

OTHER NONCURRENT ASSETS
Regulatory Assets	470		402
Securitized Assets (September 30, 2026 and December 31, 2025 Amounts Include $76 and $94, Respectively, Related to Restoration Funding)	76		94

Operating Lease Assets	47		52
Deferred Charges and Other Noncurrent Assets	203		154
TOTAL OTHER NONCURRENT ASSETS	796		702

TOTAL ASSETS	$	19,458	$	17,075

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

September 30, 2026 and December 31, 2025

(in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT LIABILITIES
Advances from Affiliates	$	—	$	188
Accounts Payable:
General	630		652
Affiliated Companies	45		60

Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2026 and December 31, 2025 Amounts Include $26 and $25, Respectively, Related to Restoration Funding)	26		75


Accrued Taxes	154		118
Accrued Interest	136		64
Security Deposits	1,151		87
Contribution in Aid of Construction Advances	247		67

Obligations Under Operating Leases	13		14


Other Current Liabilities	93		93
TOTAL CURRENT LIABILITIES	2,495		1,418

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated (September 30, 2026 and December 31, 2025 Amounts Include $52 and $78, Respectively, Related to Restoration Funding)	7,660		6,941

Deferred Income Taxes	1,560		1,430
Regulatory Liabilities and Deferred Investment Tax Credits	1,257		1,286

Obligations Under Operating Leases	36		40
Deferred Credits and Other Noncurrent Liabilities	220		134
TOTAL NONCURRENT LIABILITIES	10,733		9,831

TOTAL LIABILITIES	13,228		11,249

Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Paid-in Capital	2,546		2,546
Retained Earnings	3,688		3,283
Accumulated Other Comprehensive Income (Loss)	(4)		(3)
TOTAL COMMON SHAREHOLDER’S EQUITY	6,230		5,826

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	19,458	$	17,075

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Nine Months Ended September 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	405	$	389
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	348		329
Deferred Income Taxes	105		68
Allowance for Equity Funds Used During Construction	(62)		(37)

Pension Contributions to Qualified Plan Trust	—		(12)



Change in Other Noncurrent Assets	(164)		(116)
Change in Other Noncurrent Liabilities	62		49
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(117)		(77)
Materials and Supplies	(72)		20
Accounts Payable	66		39

Accrued Taxes, Net	36		16
Accrued Interest	72		47

Other Current Assets	(11)		—
Other Current Liabilities	(39)		(20)
Net Cash Flows from Operating Activities	629		695

INVESTING ACTIVITIES
Construction Expenditures	(2,133)		(1,332)
Change in Advances to Affiliates, Net	(382)		(418)

Contribution in Aid of Construction Advances	283		56
Other Investing Activities	(2)		—
Net Cash Flows Used for Investing Activities	(2,234)		(1,694)

FINANCING ACTIVITIES
Capital Contribution from Parent	1		451
Return of Capital to Parent	(1)		—
Issuance of Long-term Debt – Nonaffiliated	741		1,294

Change in Advances from Affiliates, Net	(188)		(285)
Retirement of Long-term Debt – Nonaffiliated	(75)		(475)


Security Deposits	1,127		—
Other Financing Activities	(5)		(3)
Net Cash Flows from Financing Activities	1,600		982

Net Decrease in Cash, Cash Equivalents and Restricted Cash	(5)		(17)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	14		24
Cash, Cash Equivalents and Restricted Cash at End of Period	$	9	$	7

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	163	$	143


Construction Expenditures Included in Current Liabilities as of September 30,	404		259
Contributions in Aid of Construction Advances Included in Current Assets as of September 30,	21		—

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

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 September 30,
	2026		2025
	(in millions)
Plant In Service	$	18,078	$	16,471
Construction Work in Progress	2,791		2,098
Accumulated Depreciation and Amortization	2,165		1,840
Total Transmission Property, Net	$	18,704	$	16,729


AEP Transmission Company, LLC and Subsidiaries

Reconciliation of 2025 to 2026

Earnings Attributable to AEP Member
(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Earnings Attributable to AEP Member	$	179	$	946

Changes in Transmission Revenues:
Transmission Revenues	36		(67)
Total Change in Transmission Revenues	36		(67)

Changes in Expenses and Other:
Other Operation and Maintenance	(9)		(37)
Depreciation and Amortization	(12)		(35)
Taxes Other Than Income Taxes	10		(14)
Interest Income	2		4
Allowance for Equity Funds Used During Construction	5		10
Interest Expense	(6)		(23)
Total Change in Expenses and Other	(10)		(95)

Income Tax Expense	(5)		(212)

Net Income Attributable to Noncontrolling Interest	(4)		(1)

2026 Earnings Attributable to AEP Member	$	196	$	571

Third Quarter of 2026 Compared to Third Quarter of 2025

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

•Transmission Revenues increased $36 million primarily due to continued transmission investment.

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

•Other Operation and Maintenance expenses increased $9 million primarily due to the following:

•A $7 million increase in employee-related costs.

•A $2 million increase in affiliated rent and shared services.

•A $2 million increase in vegetation management and facility compliance costs.

•Depreciation and Amortization expenses increased $12 million primarily due to a higher depreciable base.

•Taxes Other than Income Taxes decreased $10 million primarily due to prior period adjustments in Ohio, partially offset by higher property taxes associated with increased transmission investment.

•Allowance for Equity Funds Used During Construction increased $5 million primarily due to a higher CWIP base.

•Interest Expense increased $6 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $5 million primarily due to an increase in pretax book income.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

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

•Transmission Revenues decreased $67 million primarily due to the following:

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

This decrease was partially offset by:

•A $147 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:

•Operation and Maintenance expenses increased $37 million primarily due to the following:

•A $16 million increase in employee-related costs.

•A $12 million increase in vegetation management and facility compliance costs.

•A $7 million increase in affiliated rent and shared services.

•Depreciation and Amortization expenses increased $35 million due to a higher depreciable base.

•Taxes Other than Income Taxes increased $14 million primarily due to higher property taxes associated with increased transmission investment, partially offset by prior period adjustments in Ohio.

•Allowance for Equity Funds Used During Construction increased $10 million primarily due to a higher CWIP base and higher equity rates.

•Interest Expense increased $23 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $212 million primarily due to the following:

•A $254 million increase 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 increase was partially offset by:

•A $34 million decrease due to a decrease in pretax book income.

•A $5 million decrease due to a decrease in state taxes.

•Net Income Attributable to Noncontrolling Interest increased $1 million primarily due to the following:

•A $55 million increase due to the Midwest Transmission Holdings noncontrolling interest transaction that closed in June 2025.

This increase was partially offset by:

•A $54 million decrease due to higher 2025 earnings for Midwest Transmission Holdings due to the impact of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2026		2025		2026		2025
REVENUES
Transmission Revenues	$	115	$	108	$	335	$	325
Sales to AEP Affiliates	501		450		1,448		1,350
(Provision for)/Reversal of - Revenue Refund – Affiliated	(21)		—		(26)		120
(Provision for)/Reversal of - Revenue Refund – Nonaffiliated	(3)		—		(6)		32
Other Revenues	2		—		9		—
TOTAL REVENUES	594		558		1,760		1,827

EXPENSES
Other Operation	49		41		135		106
Maintenance	11		10		29		21
Depreciation and Amortization	133		121		389		354
Taxes Other Than Income Taxes	76		86		250		236
TOTAL EXPENSES	269		258		803		717

OPERATING INCOME	325		300		957		1,110

Other Income (Expense):
Interest Income – Affiliated	3		1		7		3
Allowance for Equity Funds Used During Construction	27		22		75		65

Interest Expense	(67)		(61)		(196)		(173)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	288		262		843		1,005

Income Tax Expense (Benefit)	62		57		184		(28)


NET INCOME	226		205		659		1,033

Net Income Attributable to Noncontrolling Interest	30		26		88		87

EARNINGS ATTRIBUTABLE TO AEP MEMBER	$	196	$	179	$	571	$	946

AEPTCo is wholly-owned by AEP Transmission Holdco.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Paid-in Capital		Retained Earnings		Noncontrolling Interest		Total
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2024	$	3,101	$	3,850	$	—	$	6,951

Capital Contribution from AEP Member	32						32
Dividends Paid to AEP Member			(42)				(42)
Net Income			211				211
TOTAL MEMBER'S EQUITY – MARCH 31, 2025	3,133		4,019		—		7,152

Capital Contribution from AEP Member	8						8

Dividends Paid to AEP Member			(2,836)				(2,836)
Midwest Transmission Holdings Noncontrolling Interest Transaction	1,791				992		2,783
Net Income			556		61		617
TOTAL MEMBER'S EQUITY – JUNE 30, 2025	4,932		1,739		1,053		7,724

Capital Contribution from AEP Member	2						2
Capital Contribution from Noncontrolling Interest					34		34
Dividends Paid to AEP Member			(184)				(184)
Dividends Paid to Noncontrolling Interest					(68)		(68)
Net Income			179		26		205
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2025	$	4,934	$	1,734	$	1,045	$	7,713

TOTAL MEMBER'S EQUITY – DECEMBER 31, 2025	$	4,962	$	1,651	$	1,030	$	7,643

Capital Contribution from AEP Member	233						233

Capital Contribution from Noncontrolling Interest					96		96

Dividends Paid to Noncontrolling Interest					(33)		(33)
Net Income			183		27		210
TOTAL MEMBER'S EQUITY – MARCH 31, 2026	5,195		1,834		1,120		8,149

Capital Contribution from AEP Member	16						16

Capital Contribution from Noncontrolling Interest					31		31
Dividends Paid to AEP Member			(141)				(141)
Dividends Paid to Noncontrolling Interest					(54)		(54)
Net Income			192		31		223
TOTAL MEMBER'S EQUITY – JUNE 30, 2026	5,211		1,885		1,128		8,224

Capital Contribution from AEP Member	137						137

Capital Contribution from Noncontrolling Interest					113		113

Dividends Paid to Noncontrolling Interest					(81)		(81)
Net Income			196		30		226
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2026	$	5,348	$	2,081	$	1,190	$	8,619

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2026 and December 31, 2025

(in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT ASSETS
Advances to Affiliates	$	193	$	71
Accounts Receivable:
Customers	127		94
Affiliated Companies	161		153

Total Accounts Receivable	288		247



Prepayments and Other Current Assets	20		4
TOTAL CURRENT ASSETS	501		322

TRANSMISSION PROPERTY
Transmission Property	17,481		16,542
Other Property, Plant and Equipment	597		571
Construction Work in Progress	2,791		2,005
Total Transmission Property	20,869		19,118
Accumulated Depreciation and Amortization	2,165		1,915
TOTAL TRANSMISSION PROPERTY – NET	18,704		17,203

OTHER NONCURRENT ASSETS

Regulatory Assets	87		73
Deferred Property Taxes	100		326
Deferred Charges and Other Noncurrent Assets	77		75
TOTAL OTHER NONCURRENT ASSETS	264		474

TOTAL ASSETS	$	19,469	$	17,999

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND MEMBER’S EQUITY

September 30, 2026 and December 31, 2025

(in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT LIABILITIES
Advances from Affiliates	$	269	$	143
Accounts Payable:
General	500		477
Affiliated Companies	166		164

Long-term Debt Due Within One Year – Nonaffiliated	425		425
Accrued Taxes	374		650
Accrued Interest	84		46
Contribution in Aid of Construction Advances	211		32
Obligations Under Operating Leases	1		1

Other Current Liabilities	15		9
TOTAL CURRENT LIABILITIES	2,045		1,947

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	6,412		6,174
Deferred Income Taxes	1,548		1,481
Regulatory Liabilities	815		708
Obligations Under Operating Leases	1		2
Deferred Credits and Other Noncurrent Liabilities	29		44
TOTAL NONCURRENT LIABILITIES	8,805		8,409

TOTAL LIABILITIES	10,850		10,356

Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)

MEMBER’S EQUITY
Paid-in Capital	5,348		4,962
Retained Earnings	2,081		1,651
TOTAL MEMBER’S EQUITY	7,429		6,613

Noncontrolling Interest	1,190		1,030

TOTAL EQUITY	8,619		7,643

TOTAL LIABILITIES AND EQUITY	$	19,469	$	17,999

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Nine Months Ended September 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	659	$	1,033
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	389		354
Deferred Income Taxes	52		(145)
Allowance for Equity Funds Used During Construction	(75)		(65)
Property Taxes	226		213

Change in Other Noncurrent Assets	(19)		(61)
Change in Other Noncurrent Liabilities	(14)		(151)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(13)		(3)

Accounts Payable	26		18
Accrued Taxes, Net	(276)		(265)

Other Current Assets	(15)		6
Other Current Liabilities	44		4
Net Cash Flows from Operating Activities	984		938

INVESTING ACTIVITIES
Construction Expenditures	(1,740)		(1,145)
Change in Advances to Affiliates, Net	(122)		(37)


Contribution in Aid of Construction Advances	204		19
Other Investing Activities	(5)		2
Net Cash Flows Used for Investing Activities	(1,663)		(1,161)

FINANCING ACTIVITIES
Capital Contribution from AEP Member	386		42
Capital Contribution from Noncontrolling Interest	240		34

Issuance of Long-term Debt – Nonaffiliated	859		560
Retirement of Long-term Debt – Nonaffiliated	(623)		(90)

Change in Advances from Affiliates, Net	126		24
Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs	—		2,783
Dividends Paid to AEP Member	(141)		(3,062)
Dividends Paid to Noncontrolling Interest	(168)		(68)

Net Cash Flows from Financing Activities	679		223

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	$	154	$	140

Construction Expenditures Included in Current Liabilities as of September 30,	342		223


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2026	2025	2026	2025
	(in millions of KWhs)
Retail:
Residential	2,613	2,516	8,210	8,202
Commercial	1,595	1,530	4,536	4,495
Industrial	2,105	2,117	6,278	6,397
Miscellaneous	211	202	621	621
Total Retail	6,524	6,365	19,645	19,715

Wholesale (a)	1,133	966	2,118	2,269

Total KWhs	7,657	7,331	21,763	21,984

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

Summary of Heating and Cooling Degree Days


	Three Months Ended September 30,		Nine Months Ended September 30,
	2026	2025	2026	2025
	(in degree days)
Actual – Heating	—	—	1,382	1,433
Normal – Heating	1	1	1,361	1,360

Actual – Cooling	932	748	1,386	1,176
Normal – Cooling	812	818	1,212	1,211


Appalachian Power Company and Subsidiaries
Reconciliation of 2025 to 2026

Net Income
(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Net Income	$	81	$	353

Changes in Revenues:
Retail Revenues	53		(3)
Off-system Sales	7		9
Transmission Revenues	10		32
Other Revenues	6		1
Total Change in Revenues	76		39

Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	24		81
Other Operation and Maintenance	(32)		(60)


Depreciation and Amortization	(28)		(26)
Taxes Other Than Income Taxes	(1)		(14)
Interest Income	1		—

Allowance for Equity Funds Used During Construction	—		(2)
Non-Service Cost Components of Net Periodic Benefit Cost	(1)		(4)
Interest Expense	(21)		(38)
Total Change in Expenses and Other	(58)		(63)

Income Tax Expense	25		40

2026 Net Income	$	124	$	369

Third Quarter of 2026 Compared to Third Quarter of 2025

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

•Retail Revenues increased $53 million primarily due to the following:

•A $53 million increase in base rate and rider revenues.

•A $21 million increase in weather-related usage due to a 25% increase in cooling degree days.

These increases were partially offset by:

•A $13 million decrease in fuel revenues.

•Off-system Sales increased $7 million primarily due to margins in July 2026 attributable to increased PJM prices.

•Transmission Revenues increased $10 million primarily due to continued transmission investment.

•Other Revenues increased $6 million due to an increase in sales of renewable energy credits.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $24 million primarily due to the following:

•A $40 million increase in Virginia FAC and West Virginia ENEC under-recoveries due to decreases in fuel revenues.

•A $39 million increase in West Virginia ENEC under-recoveries due to WVPSC orders for final recovery of West Virginia MRBC, Broadband and Vegetation Management under-recovery balances through ENEC rates.

These decreases were partially offset by:

•A $34 million decrease in Virginia FAC and West Virginia ENEC under-recoveries due to increased PJM revenues as a result of the performance of APCo’s generation during periods of high prices in July 2026.

•A $9 million increase in Virginia consumable expenses that were previously deferred prior to the Virginia SCC approving recovery of these costs through Virginia E-RAC rates starting in March 2026.

•A $4 million increase in Virginia renewable compliance expense.

•A $3 million increase in Virginia jurisdictional purchased power costs that are not recoverable through the Virginia FAC.

•Other Operation and Maintenance expenses increased $32 million primarily due to the following:

•An $8 million increase in employee-related costs.

•A $7 million increase in distribution expenses primarily due to vegetation management costs and storm restoration costs.

•A $6 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•A $5 million increase in steam generation expenses primarily due to increased plant maintenance.

•A $4 million increase in accretion expense related to AROs and the 2024 Legacy CCR Rule.

•Depreciation and Amortization expenses increased $28 million primarily due to a July 2026 order approving a final true-up to recover past West Virginia MRBC costs.

•Interest Expense increased $21 million primarily due to higher long-term debt balances.

•Income Tax Expense decreased $25 million primarily due to the following:

•A $12 million decrease due to an increase in flow-through benefits.

•A $7 million decrease due to a decrease in flow-through CAMT expense.

•A $4 million decrease due to an increase in PTCs.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

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

•Retail Revenues decreased $3 million primarily due to the following:

•A $114 million decrease in fuel revenues.

•A $21 million decrease in weather-normalized revenues primarily in the residential class.

These decreases were partially offset by:

•A $110 million increase in base rate and rider revenues.

•A $15 million increase in weather-related usage primarily due to an 18% increase in cooling degree days.

•Off-system Sales increased $9 million primarily due to margins in July 2026 attributable to increased PJM prices.

•Transmission Revenues increased $32 million primarily due to the following:

•A $37 million increase due to continued transmission investment.

This increase was partially offset by:

•A $6 million decrease 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 decreased $81 million primarily due to the following:

•A $152 million increase in Virginia FAC and West Virginia ENEC under-recoveries due to decreases in fuel revenues.

These decreases were partially offset by:

•A $57 million decrease in Virginia FAC and West Virginia ENEC under-recoveries due to increased PJM revenues as a result of the performance of APCo’s generation during periods of high prices in July 2026.

•A $21 million increase in Virginia consumable expenses that were previously deferred prior to the Virginia SCC approving recovery of these costs through Virginia E-RAC rates starting March 2026.

•A $14 million increase in Virginia jurisdictional purchased power costs that are not recoverable through the Virginia FAC.

•A $14 million decrease in West Virginia ENEC under-recovery as a result of the June 2025 FERC NOLC order.

•A $12 million increase in Virginia renewable compliance expense.

•Other Operation and Maintenance expenses increased $60 million primarily due to the following:

•A $33 million increase in distribution expenses primarily due to vegetation management costs and storm restoration costs.

•A $17 million increase in employee-related costs.

•A $15 million increase in steam generation expenses primarily due to increased plant maintenance.

•An $8 million increase in accretion expense related to AROs and the 2024 Legacy CCR Rule.

These increases were partially offset by:

•A $23 million gain from the sale of a non-utility investment in land.

•Depreciation and Amortization expenses increased $26 million primarily due to the cumulative regulatory deferral true-up for the impact of CAMT expense incurred related to IRS Notice 2026-07 allowing tax repair deductions in the calculation of CAMT.

•Taxes Other Than Income Taxes increased $14 million primarily due to the following:

•A $7 million increase due to higher business and occupation taxes.

•A $5 million increase in property taxes.

•Interest Expense increased $38 million primarily due to higher long-term debt balances.

•Income Tax Expense decreased $40 million primarily due to the following:

•A $25 million decrease due to the cumulative true-up of CAMT related to IRS Notice 2026-07 allowing tax repair deductions in the calculation of CAMT.

•An $18 million decrease due to an increase in PTCs.

•A $7 million decrease due to a decrease in state taxes.

•A $6 million decrease due to an increase in amortization of Excess ADIT.

•A $5 million decrease due to a decrease in pretax book income.

These decreases were partially offset by:

•A $23 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.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2026		2025		2026		2025
REVENUES
Electric Generation, Transmission and Distribution	$	1,047	$	981	$	2,951	$	2,955
Sales to AEP Affiliates	81		71		254		209
Other Revenues	5		5		11		13
TOTAL REVENUES	1,133		1,057		3,216		3,177

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	350		374		991		1,072



Other Operation	226		206		646		639
Maintenance	117		105		320		267


Depreciation and Amortization	180		152		512		486
Taxes Other Than Income Taxes	47		46		139		125
TOTAL EXPENSES	920		883		2,608		2,589

OPERATING INCOME	213		174		608		588

Other Income (Expense):
Interest Income	1		—		3		3

Allowance for Equity Funds Used During Construction	4		4		11		13
Non-Service Cost Components of Net Periodic Benefit Cost	4		5		12		16
Interest Expense	(91)		(70)		(246)		(208)

INCOME BEFORE INCOME TAX EXPENSE	131		113		388		412

Income Tax Expense	7		32		19		59

NET INCOME	$	124	$	81	$	369	$	353

The common stock of APCo is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2026		2025		2026		2025
Net Income	$	124	$	81	$	369	$	353

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2026 and 2025, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2026 and 2025, Respectively	—		—		(1)		(1)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2026 and 2025, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2026 and 2025, Respectively	—		—		—		—

TOTAL OTHER COMPREHENSIVE LOSS	—		—		(1)		(1)

TOTAL COMPREHENSIVE INCOME	$	124	$	81	$	368	$	352

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2024	$	260	$	1,945	$	3,532	$	11	$	5,748


Common Stock Dividends					(50)				(50)
Net Income					165				165

TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2025	260		1,945		3,647		11		5,863

Capital Contribution from Parent			7						7

Net Income					107				107
Other Comprehensive Loss							(1)		(1)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2025	260		1,952		3,754		10		5,976

Capital Contribution from Parent			1						1

Net Income					81				81

TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2025	$	260	$	1,953	$	3,835	$	10	$	6,058

TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2025	$	260	$	1,957	$	3,939	$	24	$	6,180

Capital Contribution from Parent			81						81

Net Income					195				195

TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2026	260		2,038		4,134		24		6,456


Common Stock Dividends					(700)				(700)
Net Income					50				50
Other Comprehensive Loss							(1)		(1)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2026	260		2,038		3,484		23		5,805




Net Income					124				124

TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2026	$	260	$	2,038	$	3,608	$	23	$	5,929

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2026 and December 31, 2025

(in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	4	$	5
Restricted Cash for Securitized Funding (September 30, 2026 and December 31, 2025 Amounts Include $60 and $18, Respectively, Related to Appalachian Consumer Rate Relief Funding and Appalachian Recovery Funding)	60		18
Advances to Affiliates	45		17
Accounts Receivable:
Customers	184		171
Affiliated Companies	176		142
Accrued Unbilled Revenues	57		112

Allowance for Credit Losses	(2)		(2)
Total Accounts Receivable	415		423
Fuel	191		229
Materials and Supplies	171		139
Risk Management Assets	188		81

Regulatory Asset for Under-Recovered Fuel Costs	160		83

Prepayments and Other Current Assets	92		38
TOTAL CURRENT ASSETS	1,326		1,033

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	5,724		7,886
Transmission	5,431		5,277
Distribution	6,119		5,938
Other Property, Plant and Equipment	1,254		1,175
Construction Work in Progress	851		802
Total Property, Plant and Equipment	19,379		21,078
Accumulated Depreciation and Amortization	5,195		6,365
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	14,184		14,713

OTHER NONCURRENT ASSETS
Regulatory Assets	1,378		1,439
Securitized Assets (September 30, 2026 and December 31, 2025 Amounts Include $1,406 and $78, Respectively, Related to Appalachian Consumer Rate Relief Funding and Appalachian Recovery Funding)	1,406		78
Employee Benefits and Pension Assets	260		251

Operating Lease Assets	101		95
Deferred Charges and Other Noncurrent Assets	177		183
TOTAL OTHER NONCURRENT ASSETS	3,322		2,046

TOTAL ASSETS	$	18,832	$	17,792

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

September 30, 2026 and December 31, 2025

(Unaudited)


	September 30,		December 31,
	2026		2025
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	—	$	209
Accounts Payable:
General	493		375
Affiliated Companies	158		173
Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2026 and December 31, 2025 Amounts Include $66 and $30, Respectively, Related to Appalachian Consumer Rate Relief Funding and Appalachian Recovery Funding)	1,316		1,131


Customer Deposits	98		94

Accrued Taxes	89		116

Obligations Under Operating Leases	16		15

Other Current Liabilities	370		271
TOTAL CURRENT LIABILITIES	2,540		2,384

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated (September 30, 2026 and December 31, 2025 Amounts Include $1,361 and $62, Respectively, Related to Appalachian Consumer Rate Relief Funding and Appalachian Recovery Funding)	6,106		5,128



Deferred Income Taxes	2,268		2,130
Regulatory Liabilities and Deferred Investment Tax Credits	1,092		1,111
Asset Retirement Obligations	744		707
Employee Benefits and Pension Obligations	26		26
Obligations Under Operating Leases	87		81
Deferred Credits and Other Noncurrent Liabilities	40		45
TOTAL NONCURRENT LIABILITIES	10,363		9,228

TOTAL LIABILITIES	12,903		11,612

Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 30,000,000 Shares
Outstanding – 13,499,500 Shares	260		260
Paid-in Capital	2,038		1,957
Retained Earnings	3,608		3,939
Accumulated Other Comprehensive Income (Loss)	23		24
TOTAL COMMON SHAREHOLDER’S EQUITY	5,929		6,180

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	18,832	$	17,792

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Nine Months Ended September 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	369	$	353
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	512		486
Deferred Income Taxes	77		25



Allowance for Equity Funds Used During Construction	(11)		(13)
Mark-to-Market of Risk Management Contracts	(91)		(57)


Deferred Fuel Over/Under-Recovery, Net	(64)		68

Change in Regulatory Assets	(95)		(153)
Change in Other Noncurrent Assets	(26)		33
Change in Other Noncurrent Liabilities	18		25
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	8		29
Fuel, Materials and Supplies	6		37

Accounts Payable	113		29
Accrued Taxes, Net	(38)		(80)
Other Current Assets	(37)		15
Other Current Liabilities	71		12
Net Cash Flows from Operating Activities	812		809

INVESTING ACTIVITIES
Construction Expenditures	(761)		(749)

Change in Advances to Affiliates, Net	(28)		(32)
Acquisitions of Assets	(352)		—

Other Investing Activities	42		13
Net Cash Flows Used for Investing Activities	(1,099)		(768)

FINANCING ACTIVITIES
Capital Contribution from Parent	81		8

Issuance of Long-term Debt – Nonaffiliated	1,364		593
Change in Advances from Affiliates, Net	(209)		(95)
Retirement of Long-term Debt – Nonaffiliated	(206)		(498)


Principal Payments for Finance Lease Obligations	(4)		(6)
Dividends Paid on Common Stock	(700)		(50)
Other Financing Activities	2		2
Net Cash Flows from (Used for) Financing Activities	328		(46)

Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash for Securitized Funding	41		(5)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period	23		20
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period	$	64	$	15

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	191	$	172


Noncash Acquisitions Under Finance Leases	4		3
Construction Expenditures Included in Current Liabilities as of September 30,	126		129

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2026	2025	2026	2025
	(in millions of KWhs)
Retail:
Residential	1,553	1,568	4,163	4,218
Commercial	2,699	1,866	7,221	4,552
Industrial	1,852	1,825	5,391	5,429
Miscellaneous	10	10	32	32
Total Retail	6,114	5,269	16,807	14,231

Wholesale (a)	1,874	1,423	5,425	5,366

Total KWhs	7,988	6,692	22,232	19,597

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

Summary of Heating and Cooling Degree Days


	Three Months Ended September 30,		Nine Months Ended September 30,
	2026	2025	2026	2025
	(in degree days)
Actual – Heating	—	—	2,233	2,335
Normal – Heating	6	6	2,363	2,371

Actual – Cooling	635	622	858	902
Normal – Cooling	581	582	866	867


Indiana Michigan Power Company and Subsidiaries

Reconciliation of 2025 to 2026
Net Income
(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Net Income	$	150	$	332

Changes in Revenues:
Retail Revenues	78		327
Off-system Sales	(2)		42
Transmission Revenues	1		(12)
Other Revenues	5		(2)
Total Change in Revenues	82		355

Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(4)		(80)
Purchased Electricity from AEP Affiliates	(21)		(14)
Other Operation and Maintenance	(60)		(110)

Depreciation and Amortization	(9)		(25)
Taxes Other Than Income Taxes	—		(2)
Other Income	2		9

Non-Service Cost Components of Net Periodic Benefit Cost	(2)		(5)
Interest Expense	(8)		(26)
Total Change in Expenses and Other	(102)		(253)

Income Tax Expense	(17)		(76)

2026 Net Income	$	113	$	358

Third Quarter of 2026 Compared to Third Quarter of 2025

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

•Retail Revenues increased $78 million primarily due to the following:

•A $69 million increase in weather-normalized revenues primarily in the commercial class.

•A $26 million increase in fuel revenues.

These increases were partially offset by:

•A $24 million decrease in rider revenues.

•Other Revenues increased $5 million primarily due to an increase in River Transportation Division barging revenues.

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

•Purchased Electricity from AEP Affiliates expenses increased $21 million primarily due to an increase in purchased electricity from AEGCo.

•Other Operation and Maintenance expenses increased $60 million primarily due to the following:

•A $17 million increase in distribution expenses primarily due to an increase in storm restoration costs and vegetation management costs.

•A $12 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•A $10 million increase in steam generation expenses primarily due to the acquisition of generation facilities.

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

•Depreciation and Amortization increased $9 million primarily due to the following:

•A $10 million increase due to a higher depreciable base.

•A $3 million increase due to the acquisition of generation facilities.

These increases were partially offset by:

•A $5 million decrease due to Michigan PTC deferral activity.

•Interest Expense increased $8 million primarily due to higher long-term debt balances.

•Income Tax Expense increased $17 million primarily due to a decrease in PTCs.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

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

•Retail Revenues increased $327 million primarily due to the following:

•A $193 million increase in weather-normalized revenues primarily in the commercial class.

•A $91 million increase in fuel revenues.

•A $31 million increase in rider revenues.

•A $19 million increase due to a decrease in regulatory provisions for refund.

These increases were partially offset by:

•An $8 million decrease in weather-related usage primarily due to a 5% decrease in cooling degree days and a 4% decrease in heating degree days.

•Off-system Sales increased $42 million primarily due to Rockport Plant, Unit 2 merchant sales during Winter Storm Fern in January 2026, partially offset by a decrease in merchant sales and economic hedging activity.

•Transmission Revenues decreased $12 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 $80 million primarily due to an increase in recoverable fuel and purchased power costs, partially offset by a decrease in Rockport Plant, Unit 2 merchant generation fuel costs.

•Purchased Electricity from AEP Affiliates expenses increased $14 million primarily due to an increase in purchased electricity from AEGCo.

•Other Operation and Maintenance expenses increased $110 million primarily due to the following:

•A $38 million increase in transmission expenses primarily due to a $29 million increase in recoverable PJM expenses and a $6 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $24 million increase in distribution expenses primarily due to an increase in storm restoration costs and vegetation management costs.

•A $15 million increase in steam generation expenses primarily due to acquisitions of generation facilities.

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

•Depreciation and Amortization expenses increased $25 million primarily due to the following:

•A $21 million increase due to a higher depreciable base.

•An $8 million increase due to NOLC-related Excess ADIT deferrals recorded in 2025 and the amortization of these deferrals recorded in 2026 for IURC-approved recovery through the Indiana tax rider.

•A $6 million increase due to acquisitions of generation facilities.

These increases were partially offset by:

•An $11 million decrease due to Michigan PTC deferral activity.

•Other Income increased $9 million primarily due to an increase in AFUDC driven by a higher AFUDC equity base and increased equity return rates.

•Interest Expense increased $26 million primarily due to higher long-term debt balances.

•Income Tax Expense increased $76 million primarily due to the following:

•A $32 million increase 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.

•A $22 million increase due to an increase in pretax book income.

•An $18 million increase due to a decrease in PTCs.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2026		2025		2026		2025
REVENUES
Electric Generation, Transmission and Distribution	$	917	$	841	$	2,689	$	2,336
Sales to AEP Affiliates	4		4		11		10
(Provision for)/Reversal of - Revenue Refund – Affiliated	(1)		—		(5)		8
Provision for Refund – Nonaffiliated	(48)		(51)		(119)		(135)
Other Revenues – Affiliated	20		17		47		47
Other Revenues – Nonaffiliated	2		1		4		6
TOTAL REVENUES	894		812		2,627		2,272

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	162		158		546		466

Purchased Electricity from AEP Affiliates	93		72		228		214
Other Operation	231		189		621		537
Maintenance	89		71		245		219

Depreciation and Amortization	142		133		411		386
Taxes Other Than Income Taxes	23		23		73		71
TOTAL EXPENSES	740		646		2,124		1,893

OPERATING INCOME	154		166		503		379

Other Income (Expense):
Other Income	8		6		24		15



Non-Service Cost Components of Net Periodic Benefit Cost	3		5		10		15
Interest Expense	(46)		(38)		(138)		(112)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	119		139		399		297

Income Tax Expense (Benefit)	6		(11)		41		(35)

NET INCOME	$	113	$	150	$	358	$	332

The common stock of I&M is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2026		2025		2026		2025
Net Income	$	113	$	150	$	358	$	332

OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2026 and 2025, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2026 and 2025, Respectively	—		—		—		—
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2026 and 2025, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2026 and 2025, Respectively	—		—		—		—

TOTAL OTHER COMPREHENSIVE INCOME	—		—		—		—

TOTAL COMPREHENSIVE INCOME	$	113	$	150	$	358	$	332

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2024	$	57	$	1,012	$	2,328	$	—	$	3,397


Common Stock Dividends					(50)				(50)
Net Income					58				58

TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2025	57		1,012		2,336		—		3,405

Capital Contribution from Parent			7						7

Net Income					124				124

TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2025	57		1,019		2,460		—		3,536

Capital Contribution from Parent			1						1


Net Income					150				150

TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2025	$	57	$	1,020	$	2,610	$	—	$	3,687

TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2025	$	57	$	1,033	$	2,692	$	2	$	3,784



Net Income					148				148

TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2026	57		1,033		2,840		2		3,932

Capital Contribution from Parent			25						25
Common Stock Dividends					(50)				(50)
Net Income					97				97

TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2026	57		1,058		2,887		2		4,004

Capital Contribution from Parent			3						3


Net Income					113				113

TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2026	$	57	$	1,061	$	3,000	$	2	$	4,120

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2026 and December 31, 2025

(in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	2	$	2
Advances to Affiliates	—		192
Accounts Receivable:
Customers	104		103
Affiliated Companies	102		90
Accrued Unbilled Revenues	—		17
Miscellaneous	19		2

Total Accounts Receivable	225		212
Fuel	54		61
Materials and Supplies	251		222
Risk Management Assets	26		10
Accrued Tax Benefits	47		32



Prepayments and Other Current Assets	77		53
TOTAL CURRENT ASSETS	682		784

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	6,353		5,483
Transmission	2,174		2,055
Distribution	4,012		3,823
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	1,604		1,058
Construction Work in Progress	701		403
Total Property, Plant and Equipment	14,844		12,822
Accumulated Depreciation, Depletion and Amortization	5,346		4,878
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	9,498		7,944

OTHER NONCURRENT ASSETS
Regulatory Assets	582		585
Spent Nuclear Fuel and Decommissioning Trusts	5,256		4,916

Operating Lease Assets	43		52
Deferred Charges and Other Noncurrent Assets	347		344
TOTAL OTHER NONCURRENT ASSETS	6,228		5,897

TOTAL ASSETS	$	16,408	$	14,625

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

September 30, 2026 and December 31, 2025

(dollars in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT LIABILITIES
Advances from Affiliates	$	284	$	—
Accounts Payable:
General	320		232
Affiliated Companies	121		125
Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2026 and December 31, 2025 Amounts Include $75 and $117, Respectively, Related to DCC Fuel)	75		117

Customer Deposits	45		55
Accrued Taxes	58		112
Accrued Interest	40		42

Obligations Under Operating Leases	14		17
Regulatory Liability for Over-Recovered Fuel Costs	155		19
Other Current Liabilities	228		230
TOTAL CURRENT LIABILITIES	1,340		949

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	4,043		3,444

Deferred Income Taxes	1,249		1,219
Regulatory Liabilities and Deferred Investment Tax Credits	3,346		2,938
Asset Retirement Obligations	2,230		2,165
Obligations Under Operating Leases	30		37
Deferred Credits and Other Noncurrent Liabilities	50		89
TOTAL NONCURRENT LIABILITIES	10,948		9,892

TOTAL LIABILITIES	12,288		10,841

Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 2,500,000 Shares
Outstanding – 1,400,000 Shares	57		57
Paid-in Capital	1,061		1,033
Retained Earnings	3,000		2,692
Accumulated Other Comprehensive Income (Loss)	2		2
TOTAL COMMON SHAREHOLDER’S EQUITY	4,120		3,784

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	16,408	$	14,625

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Nine Months Ended September 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	358	$	332
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	411		386

Deferred Income Taxes	7		(52)
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net	21		(40)


Allowance for Equity Funds Used During Construction	(20)		(13)
Mark-to-Market of Risk Management Contracts	(16)		8
Amortization of Nuclear Fuel	95		81

Deferred Fuel Over/Under-Recovery, Net	136		21
Change in Other Noncurrent Assets	(54)		(20)
Change in Other Noncurrent Liabilities	144		112
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	7		(1)
Fuel, Materials and Supplies	(15)		39

Accounts Payable	72		79

Accrued Taxes, Net	(69)		(19)


Other Current Assets	17		10
Other Current Liabilities	(26)		19
Net Cash Flows from Operating Activities	1,068		942

INVESTING ACTIVITIES
Construction Expenditures	(648)		(478)
Change in Advances to Affiliates, Net	192		(157)
Purchases of Investment Securities	(2,493)		(2,387)
Sales of Investment Securities	2,435		2,332
Acquisitions of Generation Facilities	(1,275)		—
Acquisitions of Nuclear Fuel	(97)		(89)

Other Investing Activities	12		31
Net Cash Flows Used for Investing Activities	(1,874)		(748)

FINANCING ACTIVITIES
Capital Contribution from Parent	28		8

Issuance of Long-term Debt – Nonaffiliated	640		249
Change in Advances from Affiliates, Net	284		(127)
Retirement of Long-term Debt – Nonaffiliated	(94)		(270)
Principal Payments for Finance Lease Obligations	(3)		(5)
Dividends Paid on Common Stock	(50)		(50)
Other Financing Activities	1		1
Net Cash Flows from (Used for) Financing Activities	806		(194)

Net Change in Cash and Cash Equivalents	—		—
Cash and Cash Equivalents at Beginning of Period	2		2
Cash and Cash Equivalents at End of Period	$	2	$	2

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	129	$	111

Noncash Acquisitions Under Finance Leases	3		2
Construction Expenditures Included in Current Liabilities as of September 30,	107		75
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,	—		1


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2026	2025	2026	2025
	(in millions of KWhs)
Retail:
Residential	4,118	4,121	11,071	11,240
Commercial	9,201	7,391	25,171	19,203
Industrial	3,607	3,520	10,712	10,654
Miscellaneous	23	23	74	76
Total Retail (a)	16,949	15,055	47,028	41,173

Wholesale (b)	2	552	901	1,683

Total KWhs	16,951	15,607	47,929	42,856

(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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2026	2025	2026	2025
	(in degree days)
Actual – Heating	—	—	1,996	2,077
Normal – Heating	2	3	1,993	1,996

Actual – Cooling	794	734	1,115	1,076
Normal – Cooling	704	707	1,032	1,032


Ohio Power Company and Subsidiaries
Reconciliation of 2025 to 2026
Net Income
(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Net Income	$	101	$	267

Changes in Revenues:
Retail Revenues	172		314
Off-system Sales	(32)		(14)
Transmission Revenues	6		26
Other Revenues	(8)		(14)
Total Change in Revenues	138		312

Changes in Expenses and Other:
Purchased Electricity for Resale	14		27
Purchased Electricity from AEP Affiliates	(8)		(13)
Other Operation and Maintenance	(117)		(215)

Depreciation and Amortization	(12)		(25)
Taxes Other Than Income Taxes	(8)		(33)


Other Income	—		(1)
Allowance for Equity Funds Used During Construction	1		—
Non-Service Cost Components of Net Periodic Benefit Cost	(1)		2
Interest Expense	—		1
Total Change in Expenses and Other	(131)		(257)

Income Tax Expense	5		18
Equity Earnings of Unconsolidated Subsidiaries	(1)		(2)

2026 Net Income	$	112	$	338

Third Quarter of 2026 Compared to Third Quarter of 2025

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

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

•A $114 million increase in rider revenues.

•A $40 million increase due to higher prices for purchased power to serve SSO customers.

•A $10 million increase in weather-normalized revenues primarily in the commercial and industrial classes.

•A $5 million increase in weather-related usage due to an 8% increase in cooling degree days.

•Off-system Sales decreased $32 million primarily due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

•Transmission Revenues increased $6 million primarily due to continued transmission investment.

•Other Revenues decreased $8 million primarily due to lower third-party Legacy Generation Resource Rider revenues 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 decreased $14 million primarily due to the following:

•A $34 million decrease in OVEC purchased power costs due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

•A $2 million decrease in recoverable alternative energy rider expenses.

These decreases were partially offset by:

•A $36 million increase in recoverable auction purchases to serve SSO customers.

•Purchased Electricity from AEP Affiliates increased $8 million primarily due to an increase in recoverable purchases to serve SSO customers.

•Other Operation and Maintenance expenses increased $117 million primarily due to the following:

•An $86 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•A $14 million increase in distribution expenses primarily related to recoverable storm restoration costs and recoverable vegetation management expenses.

•A $7 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.

•Depreciation and Amortization increased $12 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $8 million primarily due to higher property taxes.

•Income Tax Expense decreased $5 million primarily due to an increase in Excess ADIT credits refunded to customers as approved in the 2025 base rate case.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

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

•Retail Revenues increased $314 million primarily due to the following:

•A $198 million increase in rider revenues.

•A $99 million increase due to higher prices for purchased power to serve SSO customers.

•A $20 million increase in weather-normalized revenues primarily in the residential and commercial classes.

These increases were partially offset by:

•A $14 million decrease in weather-related usage driven by a 4% decrease in heating degree days.

•Off-system Sales decreased $14 million primarily due to the following:

•A $32 million decrease due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

This decrease was partially offset by:

•An $18 million increase due to increased sales of OVEC purchased power in the first half of 2026 driven by higher market prices and volumes.

•Transmission Revenues increased $26 million primarily due to continued transmission investment.

•Other Revenues decreased $14 million primarily due to the following:

•A $24 million decrease in third-party Legacy Generation Resource Rider revenues as a result of approved legislation in Ohio in May 2025, which ended the retail recovery of OVEC purchased power costs.

This decrease was partially offset by:

•A $4 million increase in affiliated rent revenue.

•A $3 million increase primarily due to customer-sited projects.

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

•Purchased Electricity for Resale expenses decreased $27 million primarily due to the following:

•A $57 million decrease in OVEC purchased power costs due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

These decreases were partially offset by:

•An $86 million increase in recoverable auction purchases to serve SSO customers.

•Purchased Electricity from AEP Affiliates expenses increased $13 million primarily due to an increase in recoverable purchases to serve SSO customers.

•Other Operation and Maintenance expenses increased $215 million primarily due to the following:

•A $151 million increase in transmission expenses primarily due to a $134 million increase in recoverable PJM transmission expenses and a $12 million increase in recoverable transmission storm restoration costs and vegetation management expenses.

•A $28 million increase in distribution expenses primarily related to recoverable vegetation management expenses and recoverable storm restoration costs.

•A $22 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.

•Depreciation and Amortization expenses increased $25 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $33 million primarily due to the following:

•A $25 million increase due to higher property taxes.

•An $8 million increase in state excise taxes due to increased billed KWhs.

•Income Tax Expense decreased $18 million primarily due to the following:

•A $30 million decrease due to an increase in Excess ADIT credits refunded to customers as approved in the 2025 base rate case.

This decrease was partially offset by:

•An $11 million increase due to an increase in pretax book income.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2026		2025		2026		2025
REVENUES
Electricity, Transmission and Distribution	$	1,190	$	1,059	$	3,253	$	2,959
Sales to AEP Affiliates	13		8		40		24
Other Revenues	5		3		12		10
TOTAL REVENUES	1,208		1,070		3,305		2,993

EXPENSES
Purchased Electricity for Resale	231		245		654		681
Purchased Electricity from AEP Affiliates	26		18		62		49

Other Operation	449		341		1,132		958
Maintenance	81		72		228		187

Depreciation and Amortization	108		96		310		285
Taxes Other Than Income Taxes	153		145		457		424
TOTAL EXPENSES	1,048		917		2,843		2,584

OPERATING INCOME	160		153		462		409

Other Income (Expense):


Other Income	—		—		—		1
Allowance for Equity Funds Used During Construction	6		5		19		19
Non-Service Cost Components of Net Periodic Benefit Cost	3		4		15		13
Interest Expense	(40)		(40)		(117)		(118)

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	129		122		379		324

Income Tax Expense	17		22		41		59
Equity Earnings of Unconsolidated Subsidiaries	—		1		—		2

NET INCOME	$	112	$	101	$	338	$	267

The common stock of OPCo is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Common Stock		Paid-in Capital		Retained Earnings		Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2024	$	321	$	1,020	$	2,543	$	3,884

Common Stock Dividends					(46)		(46)
Net Income					63		63

TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2025	321		1,020		2,560		3,901

Capital Contribution from Parent			2				2
Common Stock Dividends					(25)		(25)
Net Income					103		103

TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2025	321		1,022		2,638		3,981



Net Income					101		101

TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2025	$	321	$	1,022	$	2,739	$	4,082

TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2025	$	321	$	1,030	$	2,800	$	4,151

Capital Contribution from Parent			39				39

Net Income					117		117

TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2026	321		1,069		2,917		4,307

Capital Contribution from Parent			65				65

Net Income					109		109

Noncash Distribution to Parent					(2)		(2)
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2026	321		1,134		3,024		4,479

Capital Contribution from Parent			5				5
Common Stock Dividends					(150)		(150)
Net Income					112		112

TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2026	$	321	$	1,139	$	2,986	$	4,446

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2026 and December 31, 2025

(in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	7	$	5

Accounts Receivable:
Customers	183		109
Affiliated Companies	126		132
Accrued Unbilled Revenues	3		29


Total Accounts Receivable	312		270
Materials and Supplies	220		191




Prepayments and Other Current Assets	31		25
TOTAL CURRENT ASSETS	570		491

PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission	4,069		3,916
Distribution	8,237		7,661
Other Property, Plant and Equipment	1,288		1,289
Construction Work in Progress	863		811
Total Property, Plant and Equipment	14,457		13,677
Accumulated Depreciation and Amortization	3,059		2,993
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	11,398		10,684

OTHER NONCURRENT ASSETS
Regulatory Assets	362		326

Operating Lease Assets	46		50
Deferred Charges and Other Noncurrent Assets	340		659
TOTAL OTHER NONCURRENT ASSETS	748		1,035

TOTAL ASSETS	$	12,716	$	12,210

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

September 30, 2026 and December 31, 2025

(dollars in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025

CURRENT LIABILITIES
Advances from Affiliates	$	240	$	79
Accounts Payable:
General	542		391
Affiliated Companies	222		197

Risk Management Liabilities	3		5
Customer Deposits	123		108
Accrued Taxes	458		858


Obligations Under Operating Leases	13		13
Other Current Liabilities	304		239
TOTAL CURRENT LIABILITIES	1,905		1,890

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	3,721		3,718
Long-term Risk Management Liabilities	19		28
Deferred Income Taxes	1,377		1,268
Regulatory Liabilities and Deferred Investment Tax Credits	876		893


Obligations Under Operating Leases	33		37
Deferred Credits and Other Noncurrent Liabilities	339		225
TOTAL NONCURRENT LIABILITIES	6,365		6,169

TOTAL LIABILITIES	8,270		8,059

Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 40,000,000 Shares
Outstanding – 27,952,473 Shares	321		321
Paid-in Capital	1,139		1,030
Retained Earnings	2,986		2,800

TOTAL COMMON SHAREHOLDER’S EQUITY	4,446		4,151

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	12,716	$	12,210

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Nine Months Ended September 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	338	$	267
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	310		285
Deferred Income Taxes	52		34


Allowance for Equity Funds Used During Construction	(19)		(19)
Mark-to-Market of Risk Management Contracts	(11)		(3)

Property Taxes	321		306
Customer Deposits	79		49
Change in Regulatory Assets	(45)		28
Change in Other Noncurrent Assets	(69)		11
Change in Other Noncurrent Liabilities	61		(60)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(26)		48
Materials and Supplies	(29)		(10)
Accounts Payable	176		131

Accrued Taxes, Net	(391)		(416)
Other Current Assets	(10)		3
Other Current Liabilities	(18)		(8)
Net Cash Flows from Operating Activities	719		646

INVESTING ACTIVITIES
Construction Expenditures	(963)		(747)
Change in Advances to Affiliates, Net	—		115
Contribution in Aid of Construction Advances	50		40
Other Investing Activities	6		5
Net Cash Flows Used for Investing Activities	(907)		(587)

FINANCING ACTIVITIES
Capital Contribution from Parent	109		2

Change in Advances from Affiliates, Net	161		13

Principal Payments for Finance Lease Obligations	(3)		(3)
Dividends Paid on Common Stock	(150)		(71)
Security Deposits	72		—
Other Financing Activities	1		1
Net Cash Flows from (Used for) Financing Activities	190		(58)

Net Increase in Cash and Cash Equivalents	2		1
Cash and Cash Equivalents at Beginning of Period	5		4
Cash and Cash Equivalents at End of Period	$	7	$	5

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	90	$	91


Construction Expenditures Included in Current Liabilities as of September 30,	140		119


See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2026	2025	2026	2025
	(in millions of KWhs)
Retail:
Residential	2,459	2,027	5,229	4,938
Commercial	1,842	1,706	4,702	4,512
Industrial	1,583	1,567	4,496	4,427
Miscellaneous	406	360	1,019	964
Total Retail	6,290	5,660	15,446	14,841

Wholesale (a)	96	168	150	253

Total KWhs	6,386	5,828	15,596	15,094

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

Summary of Heating and Cooling Degree Days


	Three Months Ended September 30,		Nine Months Ended September 30,
	2026	2025	2026	2025
	(in degree days)
Actual – Heating	—	—	761	1,193
Normal – Heating	—	—	1,092	1,081

Actual – Cooling	1,913	1,353	2,763	1,982
Normal – Cooling	1,421	1,425	2,147	2,154


Public Service Company of Oklahoma
Reconciliation of 2025 to 2026
Net Income
(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Net Income	$	130	$	221

Changes in Revenues:
Retail Revenues (a)	173		276

Transmission Revenues	7		3
Other Revenues	(6)		(8)
Total Change in Revenues	174		271

Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	64		21
Other Operation and Maintenance	(4)		(67)
Depreciation and Amortization	(69)		(80)
Taxes Other Than Income Taxes	(3)		(10)
Interest Income	1		(1)

Allowance for Equity Funds Used During Construction	3		2

Non-Service Cost Components of Net Periodic Benefit Cost	(1)		(6)
Interest Expense	(8)		(35)
Total Change in Expenses and Other	(17)		(176)

Income Tax Benefit	(53)		(13)

2026 Net Income	$	234	$	303

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

Third Quarter of 2026 Compared to Third Quarter of 2025

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

•Retail Revenues increased $173 million primarily due to the following:

•A $148 million increase in rider revenues, inclusive of $75 million of 2026 interim rate rider revenue.

•A $56 million increase in weather-related usage primarily due to a 41% increase in cooling degree days.

•A $6 million increase in weather-normalized revenues primarily in the industrial class, partially offset by a decrease in the residential class.

These increases were partially offset by:

•A $36 million decrease in fuel revenue primarily due to lower authorized fuel rates.

•Transmission Revenues increased $7 million primarily due to continued transmission investment.

•Other Revenues decreased $6 million primarily due to lower associated business development revenues and lower gains on the sale of environmental credits.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $64 million primarily due to a $37 million decrease related to the impact on deferred fuel costs from decreased fuel revenues and a $25 million decrease in recoverable PTCs.

•Depreciation and Amortization expenses increased $69 million primarily due to a higher depreciable base.

•Interest Expense increased $8 million primarily due to higher long-term debt balances.

•Income Tax Benefit decreased $53 million primarily due to the following:

•A $33 million decrease due to an increase in pretax book income.

•A $17 million decrease due to a decrease in PTCs.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

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

•Retail Revenues increased $276 million primarily due to the following:

•A $274 million increase in rider revenues, inclusive of $75 million of 2026 interim rate rider revenue.

•A $62 million increase in weather-related usage primarily due to a 39% increase in cooling degree days.

These increases were partially offset by:

•A $48 million decrease in fuel revenue primarily due to lower authorized fuel rates.

•An $11 million decrease in weather-normalized revenues primarily in the residential class, partially offset by an increase in industrial class.

•Other Revenues decreased $8 million primarily due to lower associated business development revenues and lower gains on the sale of environmental credits.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $21 million primarily due to a $47 million decrease related to the impact on deferred fuel costs from decreased fuel and other revenues, partially offset by a $28 million increase in recoverable PTCs.

•Other Operation and Maintenance expenses increased $67 million primarily due to the following:

•A $30 million increase in generation expenses primarily due to acquisitions of generation facilities.

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

•An $11 million increase in distribution expenses primarily due to overhead line maintenance.

•A $7 million increase in transmission expenses primarily due to:

•A $33 million increase in SPP expenses.

This increase was partially offset by:

•A $19 million decrease due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $12 million decrease due to the refund of SPP upgrade costs.

•Depreciation and Amortization expenses increased $80 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $10 million primarily due to property taxes on acquired generation facilities.

•Interest Expense increased $35 million primarily due to higher long-term debt balances.

•Income Tax Benefit decreased $13 million primarily due to the following:

•A $20 million decrease due to an increase in pretax book income.

•A $13 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.

These decreases were partially offset by:

•A $21 million increase due to an increase in PTCs.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2026		2025		2026		2025
REVENUES
Electric Generation, Transmission and Distribution	$	864	$	686	$	1,815	$	1,542
Sales to AEP Affiliates	2		4		10		6
Other Revenues	2		4		3		9
TOTAL REVENUES	868		694		1,828		1,557

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	231		295		575		596


Other Operation	145		139		410		363
Maintenance	35		37		115		95
Depreciation and Amortization	136		67		283		203
Taxes Other Than Income Taxes	24		21		69		59
TOTAL EXPENSES	571		559		1,452		1,316

OPERATING INCOME	297		135		376		241

Other Income (Expense):
Interest Income	1		—		1		2

Allowance for Equity Funds Used During Construction	4		1		9		7

Non-Service Cost Components of Net Periodic Benefit Cost	1		2		—		6
Interest Expense	(48)		(40)		(134)		(99)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	255		98		252		157

Income Tax Expense (Benefit)	21		(32)		(51)		(64)

NET INCOME	$	234	$	130	$	303	$	221

The common stock of PSO is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2026		2025		2026		2025
Net Income	$	234	$	130	$	303	$	221

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2026 and 2025, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2026 and 2025, Respectively.	—		—		—		(1)

TOTAL COMPREHENSIVE INCOME	$	234	$	130	$	303	$	220

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2024	$	157	$	1,042	$	1,484	$	3	$	2,686




Net Income					28				28
Other Comprehensive Loss							(1)		(1)
TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2025	157		1,042		1,512		2		2,713

Capital Contribution from Parent			300						300

Net Income					63				63

TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2025	157		1,342		1,575		2		3,076

Capital Contribution from Parent			375						375

Net Income					130				130

TOTAL COMMON SHAREHOLDER'S EQUITY – SEPTEMBER 30, 2025	$	157	$	1,717	$	1,705	$	2	$	3,581

TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2025	$	157	$	1,718	$	1,736	$	2	$	3,613




Net Income					15				15

TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2026	157		1,718		1,751		2		3,628

Capital Contribution from Parent			113						113

Net Income					54				54

TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2026	157		1,831		1,805		2		3,795



Net Income					234				234

TOTAL COMMON SHAREHOLDER'S EQUITY – SEPTEMBER 30, 2026	$	157	$	1,831	$	2,039	$	2	$	4,029

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED BALANCE SHEETS

ASSETS

September 30, 2026 and December 31, 2025

(in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	4	$	2
Advances to Affiliates	70		—
Accounts Receivable:
Customers	108		109
Affiliated Companies	53		45
Miscellaneous	17		4

Total Accounts Receivable	178		158
Fuel	2		3
Materials and Supplies	157		119
Risk Management Assets	41		42

Accrued Tax Benefits	105		8
Regulatory Asset for Under-Recovered Fuel Costs	23		37
Prepayments and Other Current Assets	37		14
TOTAL CURRENT ASSETS	617		383

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	4,789		4,365
Transmission	1,511		1,433
Distribution	4,211		3,987
Other Property, Plant and Equipment	1,313		1,292
Construction Work in Progress	1,168		635
Total Property, Plant and Equipment	12,992		11,712
Accumulated Depreciation and Amortization	2,556		2,748
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	10,436		8,964

OTHER NONCURRENT ASSETS
Regulatory Assets	683		637

Employee Benefits and Pension Assets	96		95
Operating Lease Assets	140		126
Deferred Charges and Other Noncurrent Assets	34		13
TOTAL OTHER NONCURRENT ASSETS	953		871

TOTAL ASSETS	$	12,006	$	10,218

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

September 30, 2026 and December 31, 2025

(in millions, except per-share and share amounts)

(Unaudited)


	September 30,		December 31,
	2026		2025

CURRENT LIABILITIES
Advances from Affiliates	$	—	$	171
Accounts Payable:
General	386		339
Affiliated Companies	58		87
Long-term Debt Due Within One Year – Nonaffiliated	—		51
Risk Management Liabilities	29		27
Customer Deposits	355		115
Accrued Taxes	88		37
Accrued Interest	48		67
Obligations Under Operating Leases	12		11


Other Current Liabilities	133		104
TOTAL CURRENT LIABILITIES	1,109		1,009

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	4,462		3,475

Deferred Income Taxes	1,208		1,113
Regulatory Liabilities and Deferred Investment Tax Credits	746		717
Asset Retirement Obligations	165		136

Obligations Under Operating Leases	137		122
Deferred Credits and Other Noncurrent Liabilities	150		33
TOTAL NONCURRENT LIABILITIES	6,868		5,596

TOTAL LIABILITIES	7,977		6,605

Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)

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	1,831		1,718
Retained Earnings	2,039		1,736
Accumulated Other Comprehensive Income (Loss)	2		2
TOTAL COMMON SHAREHOLDER’S EQUITY	4,029		3,613

TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	12,006	$	10,218

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Nine Months Ended September 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	303	$	221
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	283		203
Deferred Income Taxes	83		31

Allowance for Equity Funds Used During Construction	(9)		(7)
Mark-to-Market of Risk Management Contracts	7		(34)

Property Taxes	(19)		(16)
Deferred Fuel Over/Under-Recovery, Net	14		42

Change in Other Regulatory Assets	(12)		(57)
Change in Other Noncurrent Assets	(41)		(35)
Change in Other Noncurrent Liabilities	156		14
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(20)		(34)
Fuel, Materials and Supplies	(37)		4
Accounts Payable	31		142
Customer Deposits	238		42
Accrued Taxes, Net	(46)		76
Other Current Assets	(16)		(2)
Other Current Liabilities	(23)		(19)
Net Cash Flows from Operating Activities	892		571

INVESTING ACTIVITIES
Construction Expenditures	(1,089)		(534)
Change in Advances to Affiliates, Net	(70)		232

Acquisitions of Generation Facilities	(608)		(1,657)
Other Investing Activities	1		7
Net Cash Flows Used for Investing Activities	(1,766)		(1,952)

FINANCING ACTIVITIES
Capital Contribution from Parent	113		675

Issuance of Long-term Debt – Nonaffiliated	986		793
Change in Advances from Affiliates, Net	(171)		40
Retirement of Long-term Debt – Nonaffiliated	(50)		(125)



Other Financing Activities	(2)		(1)
Net Cash Flows from Financing Activities	876		1,382

Net Increase in Cash and Cash Equivalents	2		1
Cash and Cash Equivalents at Beginning of Period	2		2
Cash and Cash Equivalents at End of Period	$	4	$	3

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	152	$	96



Construction Expenditures Included in Current Liabilities as of September 30,	187		91

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2026	2025	2026	2025
	(in millions of KWhs)
Retail:
Residential	2,267	2,016	5,114	4,984
Commercial	1,783	1,699	4,486	4,359
Industrial	1,376	1,375	3,959	3,883
Miscellaneous	17	16	50	50
Total Retail	5,443	5,106	13,609	13,276

Wholesale (a)	1,795	1,562	4,174	4,305

Total KWhs	7,238	6,668	17,783	17,581

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

Summary of Heating and Cooling Degree Days


	Three Months Ended September 30,		Nine Months Ended September 30,
	2026	2025	2026	2025
	(in degree days)
Actual – Heating	—	—	496	726
Normal – Heating	—	—	720	714

Actual – Cooling	1,771	1,545	2,809	2,589
Normal – Cooling	1,405	1,404	2,236	2,220


Southwestern Electric Power Company Consolidated

Reconciliation of 2025 to 2026
Earnings Attributable to SWEPCo Common Shareholder
(in millions)

	Three Months Ended September 30,		Nine Months Ended September 30,
2025 Earnings Attributable to Common Shareholder	$	189	$	353

Changes in Revenues:
Retail Revenues (a)	63		105
Off-system Sales	—		1
Transmission Revenues	(16)		(6)
Other Revenues	(1)		4
Total Change in Revenues	46		104

Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(13)		43
Other Operation and Maintenance	(3)		(60)
Asset Impairments and Other Related Charges	—		(31)
Depreciation and Amortization	(2)		(40)
Taxes Other Than Income Taxes	2		(6)
Interest Income	(2)		(4)
Allowance for Equity Funds Used During Construction	1		9
Non-Service Cost Components of Net Periodic Benefit Cost	—		(1)

Interest Expense	(25)		(61)
Total Change in Expenses and Other	(42)		(151)

Income Tax Benefit	(6)		23
Equity Earnings of Unconsolidated Subsidiary	1		—
Net Income Attributable to Noncontrolling Interest	—		1

2026 Earnings Attributable to Common Shareholder	$	188	$	330

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

Third Quarter of 2026 Compared to Third Quarter of 2025

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

•Retail Revenues increased $63 million primarily due to the following:

•A $31 million increase due to the Arkansas base rate case.

•A $29 million increase in rider revenues primarily in the Louisiana jurisdiction.

•A $20 million increase in weather-related usage primarily due to a 15% increase in cooling degree days.

These increases were partially offset by:

•An $18 million decrease due to a credit to certain existing wholesale generation customers.

•A $7 million decrease in weather-normalized revenues across all classes.

•Transmission Revenues decreased $16 million primarily due to a $12 million repayment of SPP upgrade credits, offset by an equal amount of incremental SPP upgrade costs in Other Operation and Maintenance expenses.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $13 million primarily due to increased gas generation and higher coal prices.

•Interest Expense increased $25 million primarily due to the following:

•A $19 million increase due to higher long-term debt balances.

•A $4 million increase attributable to the interest portion of credits owed to wholesale customers.

•Income Tax Benefit decreased $6 million primarily due to a decrease in PTCs.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

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

•Retail Revenues increased $105 million primarily due to the following:

•An $82 million increase in rider revenues primarily in the Louisiana jurisdiction.

•A $64 million increase due to the Arkansas base rate case.

•A $39 million increase in weather-normalized revenues across all classes.

These increases were partially offset by:

•A $53 million decrease in fuel revenue due to a $43 million refund of the Texas over-recovered fuel balance and a $10 million decrease primarily due to lower authorized rates in Arkansas and Louisiana.

•A $41 million decrease due to a credit to certain existing wholesale generation customers.

•Transmission Revenues decreased $6 million primarily due to the following:

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

•A $12 million decrease due to the repayment of SPP upgrade credits, offset by lower SPP upgrade costs in Other Operation and Maintenance expenses.

These decreases were partially offset by:

•A $34 million increase due to continued transmission investment.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $43 million primarily due to the following:

•A $53 million decrease due to a decrease in the deferred fuel costs related to a $43 million Texas fuel refund and a $10 million decrease primarily due to lower authorized rates in Arkansas and Louisiana.

•An $8 million decrease due to prior year Louisiana and Texas fuel disallowances.

These decreases were partially offset by:

•A $14 million increase in recoverable PTCs.

•An $11 million increase in non-recoverable fuel costs primarily in Louisiana.

•Other Operation and Maintenance expenses increased $60 million primarily due to the following:

•A $28 million increase in generation expenses primarily due to a $16 million increase related to the acquisition of the Wagon Wheel Wind Facility.

•A $17 million increase in distribution expenses primarily due to overhead line maintenance.

•A $9 million increase in employee-related costs.

•A $6 million increase due to the partial write-off of previously capitalized vegetation management costs as a result of SWEPCo’s FERC audit.

These increases were partially offset by:

•A $4 million decrease in transmission expenses primarily due to:

•A $12 million decrease due to the refund of SPP upgrade costs.

•A $12 million decrease in vegetation management costs.

•A $10 million decrease due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

These decreases were partially offset by:

•A $32 million increase in SPP expenses.

100

•Asset Impairments and Other Related Charges increased $31 million due to the probable, partial disallowance of the Pirkey Plant net book value in the 2025 Texas Base Rate Case.

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

•A $44 million increase due to a higher depreciable base including the Wagon Wheel Wind Facility.

This increase was partially offset by:

•A $5 million decrease primarily due to higher over-recovery of costs and allowable returns associated with generation rider recovery.

•Taxes Other Than Income Taxes increased $6 million primarily due to an increase in property taxes.

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

•Interest Expense increased $61 million primarily due to the following:

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

•A $7 million increase related to the Texas tax normalization rider amortization.

•A $4 million increase attributable to the interest portion of credits owed to wholesale customers.

•Income Tax Benefit increased $23 million primarily due to the following:

•A $48 million increase due to an increase in PTCs.

•A $10 million increase due to a decrease in pretax book income.

•A $7 million increase due to a decrease in state taxes.

These increases were partially offset by:

•A $42 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.

101

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2026		2025		2026		2025
REVENUES
Electric Generation, Transmission and Distribution	$	769	$	694	$	1,906	$	1,761
Sales to AEP Affiliates	24		28		71		63

Provision for Refund – Nonaffiliated	(25)		(4)		(53)		(9)
Other Revenues	2		6		5		10
TOTAL REVENUES	770		724		1,929		1,825

EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	205		192		532		575


Other Operation	128		122		372		327
Maintenance	52		55		155		140
Asset Impairments and Other Related Charges	—		—		31		—
Depreciation and Amortization	130		128		374		334
Taxes Other Than Income Taxes	34		36		106		100
TOTAL EXPENSES	549		533		1,570		1,476

OPERATING INCOME	221		191		359		349

Other Income (Expense):
Interest Income	2		4		5		9
Allowance for Equity Funds Used During Construction	8		7		23		14
Non-Service Cost Components of Net Periodic Benefit Cost	1		1		4		5

Interest Expense	(62)		(37)		(171)		(110)

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS	170		166		220		267

Income Tax Expense (Benefit)	(18)		(24)		(111)		(88)
Equity Earnings of Unconsolidated Subsidiary	1		—		1		1

NET INCOME	189		190		332		356

Net Income Attributable to Noncontrolling Interest	1		1		2		3

EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	188	$	189	$	330	$	353

The common stock of SWEPCo is wholly-owned by Parent.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

102

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2026		2025		2026		2025
Net Income	$	189	$	190	$	332	$	356

OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $1 and $0 for the Three Months Ended September 30, 2026 and 2025, Respectively, and $1 and $0 for the Nine Months Ended September 30, 2026 and 2025, Respectively	5		—		5		—




TOTAL COMPREHENSIVE INCOME	194		190		337		356

Total Comprehensive Income Attributable to Noncontrolling Interest	1		1		2		3

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	193	$	189	$	335	$	353

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

103

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	SWEPCo Common Shareholder
	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interest		Total
TOTAL EQUITY – DECEMBER 31, 2024	$	—	$	1,550	$	2,352	$	3	$	—	$	3,905



Common Stock Dividends – Nonaffiliated									(1)		(1)

Net Income					48				1		49

TOTAL EQUITY – MARCH 31, 2025	—		1,550		2,400		3		—		3,953

Capital Contribution from Parent			450								450

Common Stock Dividends – Nonaffiliated									(1)		(1)
Net Income					116				1		117

TOTAL EQUITY – JUNE 30, 2025	—		2,000		2,516		3		—		4,519




Common Stock Dividends – Nonaffiliated									(1)		(1)
Net Income					189				1		190

TOTAL EQUITY – SEPTEMBER 30, 2025	$	—	$	2,000	$	2,705	$	3	$	—	$	4,708

TOTAL EQUITY – DECEMBER 31, 2025	$	—	$	2,151	$	2,740	$	8	$	—	$	4,899

Capital Contribution from Parent			128								128

Common Stock Dividends – Nonaffiliated									(1)		(1)

Net Income					56				1		57

TOTAL EQUITY – MARCH 31, 2026	—		2,279		2,796		8		—		5,083

Capital Contribution from Parent			81								81


Net Income					86				—		86

TOTAL EQUITY – JUNE 30, 2026	—		2,360		2,882		8		—		5,250

Capital Contribution from Parent			37								37


Common Stock Dividends – Nonaffiliated									(1)		(1)
Net Income					188				1		189
Other Comprehensive Income							5				5
TOTAL EQUITY – SEPTEMBER 30, 2026	$	—	$	2,397	$	3,070	$	13	$	—	$	5,480





See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

104

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

September 30, 2026 and December 31, 2025

(in millions)

(Unaudited)


	September 30,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	3	$	2
Restricted Cash (September 30, 2026 and December 31, 2025 Amounts Include $6 and $15, Respectively, Related to Storm Recovery Funding)	6		15
Advances to Affiliates	494		23
Accounts Receivable:
Customers	46		63
Affiliated Companies	84		91
Miscellaneous	15		10

Total Accounts Receivable	145		164
Fuel	75		83
Materials and Supplies (September 30, 2026 and December 31, 2025 Amounts Include $1 and $1, Respectively, Related to Sabine)	104		88
Risk Management Assets	43		35

Accrued Tax Benefits	149		17
Regulatory Asset for Under-Recovered Fuel Costs	68		115
Prepayments and Other Current Assets	32		14
TOTAL CURRENT ASSETS	1,119		556

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	6,612		6,621
Transmission	3,437		3,302
Distribution	3,421		3,242
Other Property, Plant and Equipment (September 30, 2026 and December 31, 2025 Amounts Include $0 and $125, Respectively, Related to Sabine)	947		942
Construction Work in Progress	1,210		712
Total Property, Plant and Equipment	15,627		14,819
Accumulated Depreciation and Amortization (September 30, 2026 and December 31, 2025 Amounts Include $0 and $125, Respectively, Related to Sabine)	3,580		3,478
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	12,047		11,341

OTHER NONCURRENT ASSETS
Regulatory Assets	913		903
Securitized Assets (September 30, 2026 and December 31, 2025 Amounts Include $303 and $315, Respectively, Related to Storm Recovery Funding)	303		315


Deferred Charges and Other Noncurrent Assets	448		409
TOTAL OTHER NONCURRENT ASSETS	1,664		1,627

TOTAL ASSETS	$	14,830	$	13,524

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

105

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

September 30, 2026 and December 31, 2025

(in millions, except per-share and share amounts)

(Unaudited)


	September 30,		December 31,
	2026		2025

CURRENT LIABILITIES

Accounts Payable:
General	$	484	$	392
Affiliated Companies	34		89
Short-term Debt – Nonaffiliated	—		3
Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2026 and December 31, 2025 Amounts Include $17 and $17, Respectively, Related to Storm Recovery Funding)	417		917
Risk Management Liabilities	10		9
Customer Deposits	78		79
Accrued Taxes	132		68
Accrued Interest	83		49

Obligations Under Operating Leases	4		7

Provision for Refund	90		81

Other Current Liabilities	188		191
TOTAL CURRENT LIABILITIES	1,520		1,885

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated (September 30, 2026 and December 31, 2025 Amounts Include $287 and $304, Respectively, Related to Storm Recovery Funding)	5,174		3,057
Long-term Debt – Affiliated	—		1,000

Deferred Income Taxes	1,547		1,458
Regulatory Liabilities and Deferred Investment Tax Credits	513		531
Asset Retirement Obligations	226		252
Employee Benefits and Pension Obligations	43		39

Obligations Under Operating Leases	193		195
Provision for Refund	8		47
Storm Reserve	62		108
Deferred Credits and Other Noncurrent Liabilities	64		53
TOTAL NONCURRENT LIABILITIES	7,830		6,740

TOTAL LIABILITIES	9,350		8,625

Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)

EQUITY
Common Stock – Par Value – $18 Per Share:
Authorized – 3,680 Shares
Outstanding – 3,680 Shares	—		—
Paid-in Capital	2,397		2,151
Retained Earnings	3,070		2,740
Accumulated Other Comprehensive Income (Loss)	13		8
TOTAL COMMON SHAREHOLDER’S EQUITY	5,480		4,899

Noncontrolling Interest	—		—

TOTAL EQUITY	5,480		4,899

TOTAL LIABILITIES AND EQUITY	$	14,830	$	13,524

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

106

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2026 and 2025

(in millions)

(Unaudited)


	Nine Months Ended September 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	332	$	356
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	374		334
Deferred Income Taxes	51		23
Asset Impairments and Other Related Charges	31		—
Allowance for Equity Funds Used During Construction	(23)		(14)
Mark-to-Market of Risk Management Contracts	(7)		(37)

Property Taxes	(26)		(23)
Deferred Fuel Over/Under-Recovery, Net	75		91
Change in Regulatory Assets	(81)		(44)

Change in Other Noncurrent Assets	(39)		(7)
Change in Other Noncurrent Liabilities	(43)		(104)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	19		(23)
Fuel, Materials and Supplies	(8)		6
Accounts Payable	(2)		136
Accrued Taxes, Net	(68)		69


Other Current Assets	(10)		1
Other Current Liabilities	31		(11)
Net Cash Flows from Operating Activities	606		753

INVESTING ACTIVITIES
Construction Expenditures	(1,022)		(654)
Change in Advances to Affiliates, Net	(471)		(267)

Other Investing Activities	23		11
Net Cash Flows Used for Investing Activities	(1,470)		(910)

FINANCING ACTIVITIES
Capital Contribution from Parent	246		450

Issuance of Long-term Debt – Nonaffiliated	2,134		1

Change in Short-term Debt – Nonaffiliated	(3)		2
Change in Advances from Affiliates, Net	—		(275)
Retirement of Long-term Debt – Nonaffiliated	(517)		(11)
Retirement of Long-term Debt – Affiliated	(1,000)		—


Dividends Paid on Common Stock – Nonaffiliated	(2)		(3)
Other Financing Activities	(2)		(1)
Net Cash Flows from Financing Activities	856		163

Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(8)		6
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	17		5
Cash, Cash Equivalents and Restricted Cash at End of Period	$	9	$	11

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	139	$	119



Construction Expenditures Included in Current Liabilities as of September 30,	261		116

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 108.

107

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANTS

The condensed notes to condensed 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

Significant Accounting Matters

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

109

New Accounting Standards

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

111

Comprehensive Income

AEP

112

Rate Matters

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

114

Commitments, Guarantees and Contingencies

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

133

Acquisitions, Dispositions and Impairments

AEP, AEPTCo, APCo, I&M, PSO, SWEPCo

137

Benefit Plans

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

141

Business Segments

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

144

Derivatives and Hedging

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

150

Fair Value Measurements

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

159

Income Taxes

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

173

Financing Activities

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

176

Variable Interest Entities

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

184

Property, Plant and Equipment

AEP, PSO, SWEPCo

187

Revenue from Contracts with Customers

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

188

108

1. SIGNIFICANT ACCOUNTING MATTERS

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

General

The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair statement of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and nine months ended September 30, 2026 is not necessarily indicative of results that may be expected for the year ending December 31, 2026. The condensed financial statements are unaudited and should be read in conjunction with the audited 2025 financial statements and notes thereto, which are included in the 2025 Annual Reports.

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 12 - 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:


	Three Months Ended September 30,
	2026				2025
	(in millions, except per share data)
			$/share				$/share
Earnings Attributable to AEP Common Shareholders	$	1,187			$	972

Weighted-Average Number of Basic AEP Common Shares Outstanding	544.4		$	2.18	534.9		$	1.82
Weighted-Average Dilutive Effect	5.7		(0.02)		3.1		(0.01)
Weighted-Average Number of Diluted AEP Common Shares Outstanding	550.1		$	2.16	538.0		$	1.81


	Nine Months Ended September 30,
	2026				2025
	(in millions, except per share data)
			$/share				$/share


Earnings Attributable to AEP Common Shareholders	$	2,774			$	2,998

Weighted-Average Number of Basic AEP Common Shares Outstanding	543.6		$	5.10	534.2		$	5.61
Weighted-Average Dilutive Effect	5.7		(0.05)		2.2		(0.02)
Weighted-Average Number of Diluted AEP Common Shares Outstanding	549.3		$	5.05	536.4		$	5.59

109

Upon settlement of the ATM Forward maturing December 2026, the Company will issue three million shares of common stock. However, as the forward price was greater than the average market price of the common shares as of September 30, 2026, the shares were not included in the computation of diluted EPS because to do so would be antidilutive. There were no antidilutive shares outstanding as of September 30, 2025.

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 statements of cash flows:


	September 30, 2026
	AEP		AEP Texas		APCo		SWEPCo
	(in millions)
Cash and Cash Equivalents	$	418	$	—	$	4	$	3
Restricted Cash	89		9		60		6
Total Cash, Cash Equivalents and Restricted Cash	$	507	$	9	$	64	$	9


	December 31, 2025
	AEP		AEP Texas		APCo		SWEPCo
	(in millions)
Cash and Cash Equivalents	$	197	$	—	$	5	$	2
Restricted Cash	71		14		18		15
Total Cash, Cash Equivalents and Restricted Cash	$	268	$	14	$	23	$	17

Supplementary Cash Flow Information (Applies to AEP)


	Nine Months Ended September 30,
Cash Flow Information	2026		2025
	(in millions)
Cash Paid for:
Interest, Net of Capitalized Amounts	$	1,548	$	1,315


Noncash Investing and Financing Activities:

Construction Expenditures Included in Current Liabilities as of September 30,	1,813		1,169
Contribution in Aid of Construction Advances in Current Assets as of September 30,	69		—


Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,	—		1

110

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. In May 2026, the SEC formally proposed to rescind its climate-related disclosure rules. The proposal is subject to notice-and-comment rulemaking before a final rule can be approved.

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 did not have a material impact on the results of operations, statements of financial position or cash flows.

ASU 2026-02 “Environmental Credits and Environmental Credit Obligations” (ASU 2026-02)

In May 2026, the FASB issued ASU 2026-02, the intent of which is to improve the financial accounting for and disclosure of environmental credits and environmental credit obligations. The new standard establishes guidance on the recognition, measurement, presentation, and disclosure requirements for all public business entities that generate, purchase, or receive environmental credits or have a regulatory compliance obligation that may be settled with environmental credits.

The amendments in the new standard are effective for annual reporting periods beginning after December 15, 2027, and interim reporting periods within those annual reporting periods. Early adoption is permitted as of the beginning of an annual reporting period and should be applied on a retrospective basis. Management is currently evaluating the impact of this ASU on its consolidated financial statements and related disclosures.

111

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. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 - Benefit Plans for additional information.



	Cash Flow Hedges				Pension
Three Months Ended September 30, 2026	Commodity		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of June 30, 2026	$	85	$	(1)	$	(39)	$	45
Change in Fair Value Recognized in AOCI, Net of Tax	16		5		—		21
Amount of (Gain) Loss Reclassified from AOCI

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)	(20)		—		—		(20)


Amortization of Actuarial (Gains) Losses	—		—		1		1
Reclassifications from AOCI, before Income Tax (Expense) Benefit	(20)		—		1		(19)
Income Tax (Expense) Benefit	(4)		—		—		(4)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(16)		—		1		(15)
Net Current Period Other Comprehensive Income	—		5		1		6
Balance in AOCI as of September 30, 2026	$	85	$	4	$	(38)	$	51



	Cash Flow Hedges				Pension
Three Months Ended September 30, 2025	Commodity		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of June 30, 2025	$	92	$	—	$	(104)	$	(12)
Change in Fair Value Recognized in AOCI, Net of Tax	(17)		—		—		(17)
Amount of (Gain) Loss Reclassified from AOCI

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)	3		—		—		3
Interest Expense (a)	—		(1)		—		(1)


Reclassifications from AOCI, before Income Tax (Expense) Benefit	3		(1)		—		2
Income Tax (Expense) Benefit	1		—		—		1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	2		(1)		—		1
Net Current Period Other Comprehensive Loss	(15)		(1)		—		(16)
Balance in AOCI as of September 30, 2025	$	77	$	(1)	$	(104)	$	(28)

112



	Cash Flow Hedges				Pension
Nine Months Ended September 30, 2026	Commodity		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2025	$	78	$	(1)	$	(41)	$	36
Change in Fair Value Recognized in AOCI, Net of Tax	61		5		—		66
Amount of (Gain) Loss Reclassified from AOCI

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)	(68)		—		—		(68)


Amortization of Actuarial (Gains) Losses	—		—		4		4
Reclassifications from AOCI, before Income Tax (Expense) Benefit	(68)		—		4		(64)
Income Tax (Expense) Benefit	(14)		—		1		(13)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(54)		—		3		(51)
Net Current Period Other Comprehensive Income	7		5		3		15
Balance in AOCI as of September 30, 2026	$	85	$	4	$	(38)	$	51



	Cash Flow Hedges				Pension
Nine Months Ended September 30, 2025	Commodity		Interest Rate		and OPEB		Total
	(in millions)
Balance in AOCI as of December 31, 2024	$	99	$	3	$	(105)	$	(3)
Change in Fair Value Recognized in AOCI, Net of Tax	(15)		(1)		—		(16)
Amount of (Gain) Loss Reclassified from AOCI

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)	(9)		—		—		(9)
Interest Expense (a)	—		(3)		—		(3)

Amortization of Actuarial (Gains) Losses	—		—		1		1
Reclassifications from AOCI, before Income Tax (Expense) Benefit	(9)		(3)		1		(11)
Income Tax (Expense) Benefit	(2)		—		—		(2)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit	(7)		(3)		1		(9)
Net Current Period Other Comprehensive Income (Loss)	(22)		(4)		1		(25)
Balance in AOCI as of September 30, 2025	$	77	$	(1)	$	(104)	$	(28)

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

113

4. RATE MATTERS

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

As discussed in the 2025 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2025 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2026 and updates the 2025 Annual Report.

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 September 30, 2026, SWEPCo’s share of the net investment in the Pirkey Plant was $167 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.

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 the July 2023 PFD conclusion. 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. In April 2026, a unanimous settlement in principle was reached related to the 2025 Texas Base Rate Case. In September 2026, a unanimous stipulation and settlement agreement was filed with the PUCT. The agreement provides for partial recovery of the remaining net book value of the Pirkey Plant over 19 years with no return on the unamortized balance. Due to the settlement in principle reached in April, in the first quarter of 2026, SWEPCo recorded approximately $31 million for a probable, partial regulatory disallowance of the Pirkey Plant. See the “2025 Texas Base Rate Case” section below for additional information. As of September 30, 2026, the Texas jurisdictional share of the net book value of the Pirkey Plant was $47 million. To the extent the PUCT does not accept the settlement and any costs included in this filing are not approved for recovery as a result of the final PUCT order, it could reduce future net income and cash flows and impact financial condition.

114

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, which the Federal EPA has proposed to approve. In anticipation of approval from the Federal EPA, PSO began operating Northeastern Plant, Unit 3 on natural gas in January 2026. In the first quarter of 2026, PSO retired $325 million of coal-related assets at Northeastern Plant, Unit 3, resulting in a decrease to both Total Property, Plant and Equipment and Accumulated Depreciation and Amortization. As of September 30, 2026, the unrecovered value of these assets was $152 million, inclusive of ARO costs, which PSO is currently collecting in rates.

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. In February 2026, the APSC issued an order approving the application for a CCN. In July 2026, SWEPCo, PUCT staff and certain intervenors filed an unopposed stipulation and settlement agreement with the PUCT agreeing the application for a CCN should be approved. In September 2026, the PUCT issued an order approving the stipulation and settlement agreement with a modification establishing a seven-year validity period for the order. Additionally, in July 2026, SWEPCo and the LPSC staff filed a joint stipulation agreement and term sheet with the LPSC agreeing the application for a CCN should be approved. In October, the LPSC issued an order approving the joint stipulation agreement.

The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of September 30, 2026, 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	$	50	$	259	$	22	(b)	2026		(c)	$	8

Welsh Plant, Units 1 and 3	220		264		56		(d)	2028	(e)	(f)	43

(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.

115

Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except OPCo)


	AEP
	September 30,		December 31,
	2026		2025
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Welsh Plant, Units 1 and 3 Accelerated Depreciation	$	264	$	220
UTM Deferred Costs	89		56
System Resiliency Plan Deferred Costs - Texas	73		17
Plant Retirement Costs - Unrecovered Plant, Pirkey - Texas, FERC	61		93








Storm-Related Costs	46		43

Other Regulatory Assets Pending Final Regulatory Approval	7		6
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs (a) (b)	376		363
Plant Retirement Costs – Asset Retirement Obligation Costs (c)	289		257
NOLC Costs (d)	83		89

Deferred Pension and OPEB Costs	40		27
Vegetation Management Costs	37		—
Other Regulatory Assets Pending Final Regulatory Approval	169		136
Total Regulatory Assets Pending Final Regulatory Approval	$	1,534	$	1,307

(a)In March 2026, the WVPSC issued a financing order approving a securitization that included $40 million of West Virginia jurisdictional storm operation and maintenance costs that are subject to a final review by the WVPSC after bond pricing.

(b)In May 2026, APCo issued securitization bonds that included $141 million of Virginia storm operation and maintenance costs.

(c)Includes ARO adjustment related to the revised CCR Rule to be addressed in future regulatory proceedings. See the “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.

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


	AEP Texas
	September 30,		December 31,
	2026		2025
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
UTM Deferred Costs	$	89	$	56
Storm-Related Costs	41		41

System Resiliency Plan Deferred Costs	34		17

Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	51		31
Deferred Pension and OPEB Costs	40		27




Other Regulatory Assets Pending Final Regulatory Approval	9		9
Total Regulatory Assets Pending Final Regulatory Approval	$	264	$	181

116


	AEPTCo
	September 30,		December 31,
	2026		2025
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Income Taxes, Net	$	9	$	9









Total Regulatory Assets Pending Final Regulatory Approval	$	9	$	9


	APCo
	September 30,		December 31,
	2026		2025
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return


Other Regulatory Assets Pending Final Regulatory Approval	$	2	$	2
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs – Asset Retirement Obligation Costs (a)	188		169
Storm-Related Costs – West Virginia (b)	70		39
Storm-Related Costs - Virginia (c)	69		172
Vegetation Management Costs	17		—
Pension Settlement	15		16
Virginia Corporate Alternative Minimum Tax	—		13
West Virginia Corporate Alternative Minimum Tax	—		11

Other Regulatory Assets Pending Final Regulatory Approval	35		18
Total Regulatory Assets Pending Final Regulatory Approval	$	396	$	440

(a)Includes ARO adjustment related to the revised CCR Rule to be addressed in a future regulatory proceeding. See the “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.

(b)In March 2026, the WVPSC issued a financing order approving a securitization that included $40 million of West Virginia jurisdictional storm operation and maintenance costs that are subject to a final review by the WVPSC after bond pricing.

(c)In May 2026, APCo issued securitization bonds that included $141 million of Virginia storm operation and maintenance costs. See the “2025 Virginia Securitization Filing” section below for additional information.


	I&M
	September 30,		December 31,
	2026		2025
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return

Other Regulatory Assets Pending Final Regulatory Approval	$	5	$	4
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs – Asset Retirement Obligation Costs (a)	82		78
Storm-Related Costs – Indiana	57		29



Other Regulatory Assets Pending Final Regulatory Approval	9		7
Total Regulatory Assets Pending Final Regulatory Approval	$	153	$	118

117


	PSO
	September 30,		December 31,
	2026		2025
Noncurrent Regulatory Assets	(in millions)




Regulatory Assets Currently Not Earning a Return


Storm-Related Costs	$	38	$	25
Oklahoma Senate Bill 998 Deferral	28		9
Generation PBA and Delayed Retirement Deferral	27		13

NOLC Costs (a)	17		23
Plant Retirement Costs – Asset Retirement Obligation Costs (b)	12		6
Other Regulatory Assets Pending Final Regulatory Approval	1		8
Total Regulatory Assets Pending Final Regulatory Approval	$	123	$	84

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

(b)Includes ARO adjustment related to the revised CCR Rule to be addressed in PSO’s 2026 Oklahoma Base Rate Case regulatory proceeding. See the “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.


	SWEPCo
	September 30,		December 31,
	2026		2025
Noncurrent Regulatory Assets	(in millions)

Regulatory Assets Currently Earning a Return
Welsh Plant, Units 1 and 3 Accelerated Depreciation	$	264	$	220
Plant Retirement Costs - Unrecovered Plant, Pirkey - Texas, FERC	61		93


System Resiliency Plan Deferred Costs - Texas	39		1

Income Taxes, Net	7		—
Other Regulatory Assets Pending Final Regulatory Approval	5		2
Regulatory Assets Currently Not Earning a Return


NOLC Costs (a)	65		66
Storm-Related Costs - Louisiana, Texas	59		43
Other Regulatory Assets Pending Final Regulatory Approval	17		20
Total Regulatory Assets Pending Final Regulatory Approval	$	517	$	445

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

If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.

118

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

AEP Texas Interim Transmission and Distribution Rates

Through September 30, 2026, AEP Texas’ cumulative revenues from transmission and distribution interim base rate increases that are subject to review are estimated to be approximately $287 million. AEP Texas recognized a $12 million provision for refund related to the 2025 UTM filing for amounts collected through the third quarter of 2026. 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.

2025 UTM Filing

UTM Regulatory Assets

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

2021-2023 ENEC Remand Cases

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.

In February 2024, the Companies filed briefs with the 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.

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2026 ENEC Update Filing

In April 2026, the Companies submitted their annual ENEC update filing with the WVPSC for the annual review period ended February 28, 2026, proposing a $21 million annual increase in ENEC rates when compared to existing ENEC rates. The Companies proposed that this increase in ENEC rates become effective September 1, 2026 with the increase in ENEC rates based on the Companies’ projected costs for period September 2026 through August 2027. The Companies’ ENEC update filing also included a projected August 31, 2026 ENEC under-recovery balance of $597 million ($285 million related to APCo). This projected ENEC under-recovery balance included recovery of final true-ups of the Companies’ West Virginia Modified Rate Base Cost (MRBC), Vegetation Management and Broadband surcharges as well as continued deferral of the Companies’ West Virginia base rate increase that was ordered by the WVPSC in August 2025 and February 2026. See the “West Virginia Modified Rate Base Cost (MRBC) Surcharge Update Filing” section below for further details. The Companies proposed that this projected August 31, 2026 ENEC under-recovery balance of $597 million be included in the final combined balance approved by the WVPSC for securitization in late 2026.

In May 2026, the Companies submitted supplemental testimony that adjusted the original requested annual increase in ENEC rates from a $21 million annual increase to a $9 million annual decrease. This modification was the result of a revised forecast of ENEC costs for the period September 2026 through August 2027.

In June 2026, the Companies, WVPSC staff and intervening parties filed a settlement with the WVPSC which recommended a projected August 31, 2026 ENEC under-recovery balance of $594 million ($275 million related to APCo) to be eligible for securitization. The settlement further recommended that the ENEC annual review period ending February 28, 2026 remain open until the Companies’ next ENEC proceeding.

In July 2026, the WVPSC issued an order on the June 2026 settlement, approving a $593 million projected August 31, 2026 ENEC under-recovery balance ($274 million related to APCo) that will be included in the Companies’ overall balance to be securitized. This WVPSC-approved projected ENEC under-recovery balance included the Companies’ proposed final true-ups of MRBC, Vegetation Management and Broadband surcharges as well as ongoing regulatory deferral until securitization of the West Virginia base rate increase that was originally approved in August 2025. The WVPSC’s order also approved an updated $2.7 billion overall balance to be securitized ($1.7 billion related to APCo) as further described in the “2025 West Virginia Securitization Filing” section below. It is currently estimated that this securitization will take place in the fourth quarter of 2026.

In August 2026, the WVPSC issued an order approving a $9 million annual decrease in ENEC rates effective September 1, 2026.

2024 West Virginia Base Rate Case

In September 2025, and in response to the WVPSC’s August 2025 order on the Companies’ 2024 West Virginia Base Rate Case, petitions for reconsideration were filed with the WVPSC to explain the financial consequences of the order and seek clarification on certain issues. In February 2026, the WVPSC issued an order upon reconsideration approving a revised ROE of 9.75%. This approved change in ROE results in a revision to the approved annual increase in base rates from $76 million ($67 million related to APCo) to $91 million ($79 million related to APCo) effective February 20, 2026. All other requests for reconsideration were rejected by the WVPSC.

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’ 2024 West Virginia Base Rate Case filing 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.

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In April 2026, the WVPSC issued an order that adjudicated the Companies’ 2024 MRBC surcharge update filing. This order affirms previously approved MRBC revenue requirements and allows the Companies to perform a final true-up in an ENEC filing to recover past MRBC costs that were not reflected in MRBC surcharge rates in a timely manner during the four-year existence of the surcharge. This order also allows the Companies to recognize carrying charges on revised MRBC under-recovery balances starting September 2024 to recover the updated MRBC under-recovery with carrying charges through current ENEC surcharge rates over a period to be determined in the Companies’ 2026 ENEC proceeding. The April 2026 order also noted that collection of revenue requirement related to inclusion of a stand-alone NOLC deferred tax asset in MRBC rates may be subject to refund, pending the future issuance of a PLR or other guidance by the IRS.

In July 2026, the WVPSC issued an order on the Companies’ June 2026 ENEC update filing, approving a $593 million projected August 31, 2026 ENEC under-recovery balance ($274 million related to APCo) that will be included in the Companies’ overall balance to be securitized. The WVPSC’s order approves the Companies’ proposed recovery of the remaining MRBC under-recovery balance of $34 million ($28 million related to APCo) as part of the $593 million ENEC under-recovery balance approved for securitization.

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

West Virginia Inflation-Based Rate Adjustment

An intervening party submitted an appeal to the WVSC regarding the Inflation-Based Rate Adjustment alleging that the WVPSC: (a) failed to carry its burden of proving that the Companies’ existing rates were unreasonable and needed to be changed, (b) failed to adequately support its order with evidence of record and (c) violated the due process rights of the intervening party and the customers that it represents. A statement of reasons is due from the WVPSC and a brief is due from APCo in November 2026 while reply briefs are due in December 2026. Oral arguments will be held in the first half of 2027.

If the Companies are ordered to issue future refunds associated with the Inflation-Based Rate Adjustment, it would reduce future net income and cash flows and impact financial condition.

2025 West Virginia Securitization Filing

In March 2026, the WVPSC issued a final financing order approving the Companies’ proposed securitization of the following: (a) remaining combined unrecovered ENEC balances, (b) undepreciated West Virginia jurisdictional plant balances as of December 31, 2022 for the Amos, Mitchell and Mountaineer Plants, (c) undepreciated environmental costs previously approved for recovery through a separate West Virginia surcharge and (d) West Virginia jurisdictional deferred major storm operation and maintenance costs.

In July 2026, the WVPSC issued an order on the June 2026 settlement agreement in the Companies’ 2026 ENEC update filing, approving a modified $593 million projected August 31, 2026 ENEC under-recovery balance ($274 million related to APCo) and an overall securitization balance of $2.7 billion ($1.7 billion related to APCo) as reflected in the table below:

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Eligible Costs Approved by the WVPSC for Securitization	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	274		319		593
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 (a)	10		6		16
Total	$	1,672	$	1,036	$	2,708

(a)Amounts represent estimates. The WVPSC may update these estimates prior to securitization bond marketing.

In accordance with the West Virginia statutory requirements and the financing order, the issuance of the securitization bonds is subject to final review by the WVPSC after bond pricing. The Companies will proceed with the securitization bond issuance process and plan to complete the securitization in the fourth quarter 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 May 2026, APCo issued 20-year securitization bonds to finance approximately $1.4 billion of jurisdictional costs, including: (a) $1.2 billion of certain Virginia jurisdictional Property, Plant and Equipment balances for the Amos and Mountaineer Plants, (b) $141 million of Virginia jurisdictional major storm other operation and maintenance expenses deferred to Regulatory Assets during the 2024-2025 biennial period and (c) $11 million of up-front financing costs. After issuing the securitization bonds, APCo implemented a rider to recover annual securitization debt financing costs and the Base Rate Reduction (BRR) Rider to credit customers for the recovery of, and return on, the Amos and Mountaineer Plant costs currently included in APCo Virginia base rates.

2026 Virginia Base Rate Case

In May 2026, APCo filed a request with the Virginia SCC for a net $105 million annual decrease in distribution and generation base rates. Approximately $166 million of the proposed decrease to base rates is currently credited to customers through the BRR Rider associated with the securitization of certain Virginia jurisdictional Amos and Mountaineer Plant balances as described in the “2025 Virginia Securitization Filing” section above, resulting in an estimated net $61 million increase to base rates. The BRR Rider will expire upon the implementation of new base rates. The proposed $61 million annual increase in base rates is based on a 10.5% ROE and an actual capital structure of 50.3% debt and 49.7% common equity. The $61 million requested base rate increase is primarily due to general inflation, increased investment in distribution and generation, increased capital costs and the costs of required programs to support electric vehicles and low-income solar.

In August 2026, intervenors submitted testimony recommending a $1 million annual increase in base rates based on a recommended 9.325% ROE. Included in this proposed revenue requirement is a proposed denial of recovery of a $9 million regulatory asset related to APCo’s targeted circuits program that was previously approved for deferral by the Virginia SCC. Intervenor testimony also proposed the disallowance of alleged above-market purchased power expense from OVEC.

In September 2026, Virginia SCC staff issued testimony recommending a $6 million annual decrease in base rates based on a recommended 9.65% ROE, the removal of $37 million of vegetation management costs from base rates for recovery through a separate surcharge and modifications to APCo’s forecasted capital expenditures, retirements and accumulated depreciation for 2026 and 2027. For purposes of Virginia retail ratemaking, Virginia SCC staff testimony recommended continued capitalization of certain vegetation management costs impacted by the recent FERC Audit of SWEPCo.

In September 2026, APCo filed rebuttal testimony supporting a revised annual increase in base rates of $16 million. The change in APCo’s proposal is based primarily on the recommended removal of $37 million of vegetation management costs to be recovered through a separate rider and $12 million of ARO costs that are also recommended to be recovered through a separate rider.

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In October 2026, APCo, Virginia SCC staff and intervening parties entered into a settlement agreement that includes an estimated first year $4 million reduction to base revenues and a net $0 second year change in base revenues based on a 9.80% ROE and a capital structure of 50.2% debt and 49.8% common equity. The settlement agreement also includes: (a) an agreement for APCo to prospectively recover vegetation management capital and operation and maintenance costs through a separate rate adjustment clause, (b) an agreement for APCo to prospectively recover generation-related ARO costs through a separate rate adjustment clause, (c) approval for APCo to recover $8 million of deferred costs related to APCo’s targeted circuits program and (d) authority for APCo to defer PJM ancillary services costs using an $11 million band above or below the level approved for recovery in base rates. For purposes of Virginia retail ratemaking, the settlement agreement also provides for continued capitalization of certain vegetation management costs impacted by the recent FERC Audit of SWEPCo. See the “FERC Audit” section below for additional information. A hearing was held in October 2026.

The Virginia SCC’s final order is required to be issued no later than January 2027 with updated base rates to be implemented in March 2027. If any costs in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

ETT Rate Matters (Applies to AEP)

2026 ETT Base Rate Case

In April 2026, ETT filed a request with the PUCT for a $42 million annual base rate increase over its adjusted test year revenues which includes interim transmission rate updates. ETT’s request is based upon a proposed 10.5% ROE with a capital structure of 55% debt and 45% common equity. The rate case seeks a prudence review determination on cumulative capital additions included in interim rates.

In July 2026, ETT filed a motion on behalf of the parties to the proceeding to implement interim rates based on a settlement in principle. The motion for interim rates was approved by an ALJ and became effective August 1, 2026. In August 2026, a unanimous and unopposed settlement was filed with the PUCT. The settlement terms included a base rate increase of approximately $8 million, based on a 9.6% ROE 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. In October 2026, the ALJ filed a proposed order recommending approval of the settlement. If any of the costs in the case are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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

2024 Michigan Power Supply Cost Recovery (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 Inter-Company Power Agreement (ICPA) and the Rockport UPA with AEGCo ranging from $259 thousand to $14 million. In July 2026, the MPSC ordered a $1 million cost disallowance associated with the OVEC ICPA and no cost disallowance associated with the Rockport UPA with AEGCo.

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.

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 the one-year periods ending May and November. The credit is determined as 50% of the one-year earnings above the authorized level. 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 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. In June 2026, the IURC issued an order approving the jurisdictional cost allocation modifications and the $53 million over-earnings customer credit.

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In August 2026, I&M submitted its earnings test evaluation for the period ended May 2026 with a proposed over-earnings credit to customers through the FAC of $66 million. In September 2026, an intervening party submitted testimony agreeing with I&M’s proposed over-earnings credit of $66 million for the period ending May 2026. Beginning March 2026 and as approved by the IURC, I&M reflects costs associated with the Oregon Clean Energy Center and other plants approved by the IURC for acquisition under I&M’s Expedited Generation Resource (EGR) Plan either as eligible costs for recovery through existing I&M Indiana riders or in I&M’s ongoing Indiana earnings test evaluation. See the "Oregon Clean Energy Center" and the "Big Sandy Peaker Plant" sections of Note 6. I&M Indiana jurisdictional over-earnings up to the amount of revenue from large load customers are now accumulated in a separate regulatory liability for refund to customers over a time period to be determined in a future proceeding at the IURC. As of September 30, 2026, the balance of this regulatory liability was $97 million. Any over-earnings that exceed the amount of revenue from large load customers will continue to be credited to customers through the FAC. See the “2026 Indiana Base Rate Case” section below for discussion of I&M’s proposed Reduce-and-Freeze mechanism (RAF). The IURC is expected to issue an order in the fourth quarter of 2026.

2026 Indiana Base Rate Case

In August 2026, in accordance with a settlement agreement previously approved by the IURC and consistent with HEA 1002, I&M submitted a base rate filing with the IURC based on a MYRP for the forecasted years 2027 through 2029. The proposed MYRP includes a RAF rate mechanism with an overall $42 million decrease in I&M Indiana base and rider rates based on a 10.1% ROE and a capital structure of 48.8% debt and 51.2% equity. I&M’s MYRP proposes to freeze base rates and most rider rates, with limited exceptions primarily related to large load customers. The RAF will repurpose I&M’s existing Indiana Earnings Test. Under the RAF, I&M will continue to measure its actual earnings compared to its authorized earnings and record a regulatory liability for I&M Indiana jurisdictional earnings that exceed I&M’s authorized net operating income (NOI) and ROE thresholds. During the MYRP, I&M requested accounting authority to recover its increasing cost of service and earn up to its IURC-authorized Indiana jurisdictional NOI and ROE by amortizing existing regulatory liabilities or establishing a regulatory asset for recovery in a future MYRP proceeding.

I&M’s MYRP and authorized ROE will be subject to specific performance metrics and PIMs ordered by the IURC.

I&M’s Indiana base rate update filing also describes I&M’s intent to submit a Subsequent License Renewal Application (SLRA) filing with the Nuclear Regulatory Commission (NRC) in the first quarter of 2027 that will request an extension of the current licenses of Cook Plant Units 1 and 2 from 2034 and 2037 as currently authorized, to 2054 and 2057, respectively. I&M is requesting recovery of related costs expected to be incurred during the MYRP and proposed depreciation rates reflect this anticipated license extension.

For I&M’s MYRP base rate case, intervenor testimony is due in December 2026 and a hearing is scheduled for February 2027 . It is currently estimated that a final order from the IURC will be issued in June 2027 with changes to rates effective in July 2027. If any costs in this filing are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

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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.

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 the “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 the “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. In September 2026, the WVPSC entered an order conditionally granting WPCo’s request, allowing the revised billing procedures and cost equalization to proceed, but deferred final determination of the appropriate amounts to be equalized until APCo’s and WPCo’s next base rate case. As of September 30, 2026, 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 $514 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.

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The proposed annual rate increase also included a $20 million annual revenue requirement related to KPCo’s investment in the Mitchell Plant. See the “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.

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, the KPSC issued an order modifying the January 2026 settlement agreement and approving an annual increase of $55 million in Kentucky retail rates based upon a 9.75% base rate ROE effective March 1, 2026. This increase is inclusive of a $36 million increase in base rates and a $19 million increase due to the new generation rider. The order reduced the settlement revenue requirement by $22 million primarily due to a $10 million reduction related to FERC transmission expense and a $9 million reduction in incentive and other compensation. Additionally, the KPSC ordered that $47 million of certain vegetation management costs previously incurred and capitalized from January 2018 through May 2025 should be reclassified as a regulatory asset to be recovered over a 30 year period with no carrying costs, and that prospective vegetation management costs incurred should no longer be capitalized but instead be treated as operating expense.

In March 2026, KPCo filed a request with the KPSC seeking rehearing on the vegetation management finding in the base case order in addition to certain other denied costs. In April 2026, the KPSC issued an order approving KPCo’s request for rehearing. Additionally, the order authorized KPCo to defer $18 million of certain vegetation management costs previously incurred and capitalized from June 2025 through February 2026 to a regulatory asset, pending the KPSC’s final decision on rehearing. If any costs included in the request for rehearing 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.

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In December 2024, intervenors filed appeals with the Supreme Court of Ohio on the PUCO’s denial for rehearing. In April 2026 and June 2026, the Supreme Court of Ohio affirmed the PUCO’s August 2024 orders finding that costs incurred by OPCo during the 2018-2019 audit period and 2020 audit period, respectively, were prudent.

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.

In October 2026, as part of OVEC cost recovery audits pending before the PUCO, intervenors filed positions claiming that costs incurred by OPCo during the 2024–2025 audit period were imprudent and should be disallowed. Management disagrees with these assertions and is unable to predict the impact of these disputes. If any costs are disallowed or refunds are ordered, it could reduce future net income and cash flows and impact financial condition.

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.

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 and a capital structure of 49.1% debt and 50.9% common equity 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. Additionally, the agreement proposed increased revenue caps for the Distribution Investment Rider, annual cost cap increases in the Enhanced Service Reliability Rider and would result in no material disallowances. In April 2026, the PUCO issued an order approving the joint stipulation and settlement agreement and rates went into effect. In May 2026, the PUCO denied applications for rehearing submitted by two intervenors.

March and August 2026 Storm Costs

In March 2026, OPCo’s service territory was impacted by strong winds from an isolated storm resulting in power outages and damage to the transmission and distribution infrastructure. In August 2026, OPCo’s service territory was impacted by severe winds from another storm resulting in power outages and damage to the transmission and distribution infrastructure. As of September 30, 2026, OPCo had incurred approximately $27 million and $30 million in incremental operation and maintenance costs related to service restoration efforts for March 2026 and August 2026 storms, respectively. These incremental storm restoration costs have been deferred as a regulatory asset and OPCo expects to seek future recovery of those costs through its approved storm cost recovery mechanism.

PSO Rate Matters (Applies to AEP and PSO)

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.

In May 2026, various intervenors and staff filed testimony supporting an annual base rate increase ranging from $10 million to $109 million based on a recommended ROE ranging from 8.3% to 9.38%. The primary differences between PSO’s requested annual increase in base rates and staff and intervenors’ recommendations include: (a) a reduction in the proposed ROE, (b) modifications to PSO’s previously approved treatment of a stand-alone NOLC deferred tax asset in rate base, (c) treatment of storm costs and (d) adjustments to PSO's proposed depreciation and amortization.

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In June 2026, PSO, OCC staff and certain intervening parties filed a non-unanimous partial joint stipulation and settlement agreement for a $73 million revenue increase based upon a 9.375% ROE utilizing PSO’s filed actual capital structure of 50.1% debt and 49.9% common equity that included: (a) a requirement for PSO to provide a credit over a two-year period for deferred tax liabilities related to tax repairs which will then be recovered over the life of the underlying plant after the credit period, (b) PSO to expand its SPP Transmission Cost Rider as requested, (c) no change in the treatment of PSO’s NOLC, and (d) PSO to recover vegetation management costs consistent with the amount in PSO’s filed request and defer $13 million of eligible vegetation management costs in the first year of implemented rates, and $4 million each year thereafter. All issues related to PSO's proposed large load tariffs would be an open issue at hearing. Certain intervening parties did not sign the settlement agreement and contested certain of its provisions. Interim rates were implemented, subject to refund, on July 1, 2026 reflecting the terms of this settlement. A hearing was held and an order is expected in the fourth quarter of 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.

SWEPCo Rate Matters (Applies to AEP and SWEPCo)

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.

In March 2026, various intervenors filed testimony supporting a reduction to SWEPCo's net request ranging from $36 million to $64 million based on a recommended ROE ranging from 9.25% to 9.44%. In March 2026, PUCT staff filed testimony supporting a reduction to SWEPCo's net request of $26 million based on an ROE of 9.6%. The primary differences between SWEPCo’s requested annual increase in base rates and staff and intervenors’ recommendations include: (a) recovery of the Pirkey Plant, (b) modifications to SWEPCo’s previously approved treatment of a stand-alone NOLC deferred tax asset in rate base and (c) a reduction in the proposed ROE.

In April 2026, a unanimous settlement in principle was reached and SWEPCo filed a motion to abate the hearing. In September 2026, a unanimous stipulation and settlement agreement was filed with the PUCT. The agreement provides: (a) a 9.53% ROE and a capital structure of 48.02% debt and 51.98% common equity resulting in a $48 million annual increase, (b) partial recovery of the remaining net book value of the Pirkey Plant over 19 years with no return on the unamortized balance and (c) $11 million annually to recover deferred storm costs and fund the utility’s self-insurance reserve. A PUCT order on the settlement is expected in the fourth quarter of 2026, with rates implemented retroactively back to March 2026. If the PUCT does not accept the settlement and 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.

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SPP OATT Upgrade Costs

Under the SPP OATT, costs of sponsor-funded transmission upgrades may be recovered, in part, from SPP customers whose transmission service is dependent upon capacity enabled by the upgrades. In 2016, SPP billed transmission service customers, including PSO and SWEPCo, for upgrade costs incurred since 2008. SPP then credited the qualifying transmission owners, including SWEPCo, for the use of these upgrades. In July 2026, as a result of a FERC order, the amounts billed relating to the period 2008 to 2015 were required to be refunded. In the third quarter of 2026, PSO recognized a net favorable impact of approximately $12 million while SWEPCo had no net impact related to this matter. SPP is currently analyzing impacts related to costs of sponsor-funded transmission upgrades for the period subsequent to 2015. 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.

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. The Pennsylvania Attorney General subsequently petitioned to intervene, which the United States Court of Appeals for the Third Circuit denied. The Pennsylvania Attorney General sought review of the United States Court of Appeals for the Third Circuit’s decision at the United States Supreme Court, which was denied in June 2026.

In May 2026, the Maryland Public Service Commission approved an extension of the construction commencement deadline to June 2027. In May 2026, Transource Energy filed its siting application for a CPCN to provide utility service in Franklin County, Pennsylvania, a petition for exemption from certain local zoning regulations and a motion to consolidate the three filings.

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 September 30, 2026, AEP’s share of IEC capital expenditures was approximately $73 million, located in Total Property, Plant and Equipment - Net on AEP’s balance sheets related to the continuing portion of the IEC project. In addition, AEP’s share of IEC capital expenditures located in Regulatory Assets on AEP’s balance sheets as of September 30, 2026 was approximately $20 million related to the portion of the project that is excluded from the modified scope and not continuing. Transource Energy intends to seek recovery of the regulatory asset through the abandonment incentive previously granted by the FERC for this project which allows for the recovery of prudently incurred costs if the project is canceled for reasons outside the control of Transource Energy. The modified IEC project is pending regulatory approvals in Pennsylvania as mentioned above. 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 provided refunds for the 2021 rate year, primarily through 2025 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 the 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 briefs were filed by the various parties in the third quarter of 2026. In October 2026, the court issued an order scheduling oral arguments for the fourth quarter of 2026.

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. In March and April 2026, the FERC approved the AEP transmission owning subsidiaries’ compliance filings related to PJM and SPP, respectively.

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:

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	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

FERC 2025 PJM Transmission Formula Rate Challenge (Applies to AEP, AEPTCo, APCo, I&M and OPCo)

In March 2026, an intervenor filed a formal challenge and complaint regarding the NOLC adjustments in the 2025 annual update covering the transmission formula rates for 2024 in PJM. In July 2026, the FERC rejected and denied the formal challenge and complaint. In August 2026, the intervenor filed a request for rehearing of the FERC’s July 2026 rejection and denial. In September 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.

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 March 2026, the FERC denied the request for rehearing on the merits of the request, continuing to find that the KPSC and Attorney General of Kentucky had not met their burden of proof. 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 and in June 2026, filed their brief. The parties completed briefing in the appeal in the third quarter of 2026. 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 all Registrant Subsidiaries)

The FERC Division of Audits and Accounting initiated an audit of SWEPCo in April 2024 evaluating 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. In March 2026, the FERC issued a final audit report which included, among other things, findings and recommendations related to SWEPCo's policy for the capitalization of certain vegetation management costs.

As a result of the final audit report, beginning in the first quarter of 2026, AEP will no longer capitalize the vegetation management costs identified in the FERC finding on a prospective basis. AEP's PJM and SPP transmission formula rates will provide recovery of these costs as an expense effective with the 2026 rate year. Retail ratemaking for these costs will be determined in current or future ratemaking proceedings in each jurisdiction which may allow the continued capitalization of these costs as property, plant and equipment or deferral as regulatory assets. Management is unable to predict the outcome in any current or future ratemaking proceeding. If any refund liabilities are imposed by any retail commission or any disallowances occur, it would reduce future net income and cash flows and impact financial condition.

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SWEPCo continues to hold discussions with FERC audit staff to finalize the resolution of all findings noted in the final audit report. 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 for SWEPCo.

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5. 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. The Commitments, Guarantees and Contingencies note within the 2025 Annual Report should be read in conjunction with this report.

COMMITMENTS

In June 2026, OPCo completed the transfer of its 4.3% ownership in OVEC to Parent and its 19.93% OVEC power participation entitlement to AGR. Parent remains responsible for the financial and other obligations of AGR under the intercompany power agreement. As a result, OPCo's remaining energy and capacity purchase contract commitments are immaterial.

During the third quarter of 2026, management concluded that I&M’s $782 million agreement to purchase gas- and steam-powered turbines met the definition of an unconditional purchase obligation in accordance with the accounting guidance for “Commitments.” Remaining spend on the contract is as follows: $31 million through 2026, $497 million in 2027, $145 million in 2028 and $31 million in 2030.

During the third quarter of 2026, management concluded that PSO’s $349 million agreement to purchase gas- and steam-powered turbines met the definition of an unconditional purchase obligation in accordance with the accounting guidance for “Commitments.” Remaining spend on the contract is as follows: $54 million through 2026, $129 million in 2027 and $9 million in 2028 and 2029.

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.

In April 2026, AEP increased its $5 billion revolving credit facility to $6.5 billion and extended the due date from March 2029 to April 2031. Also, in April 2026, AEP increased its $1 billion revolving credit facility to $1.5 billion and extended the due date from March 2027 to April 2029. AEP may issue up to $1.2 billion as letters of credit under these revolving credit facilities on behalf of subsidiaries. As of September 30, 2026, no letters of credit were issued under either revolving credit facility.

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Company

Amount

Maturity

(in millions)

AEP

525

October 2026 to September 2027

During the second quarter of 2026, AEP issued an additional $131 million of letters of credit under existing uncommitted facilities with maturity dates ranging from April 2027 to June 2027.

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 September 30, 2026, 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.

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 September 30, 2026, 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	$	34
AEP Texas	7
APCo	5
I&M	3
OPCo	6
PSO	3
SWEPCo	4

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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 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 by May 2028. 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 will provide additional information on the planned closure method. In the second quarter of 2024, AEP evaluated the applicability of the rule to current and former plant sites and recorded a $674 million increase in ARO, 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.

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, the Federal EPA revisions to the rule, 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.

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.

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

NUCLEAR CONTINGENCIES (Applies to AEP and I&M)

I&M owns and operates the Cook Plant under licenses granted by the Nuclear Regulatory Commission. I&M has a significant future financial commitment 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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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.

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, 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 Environmental Protection Agency 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 granted the Federal EPA’s Motion to Dismiss the complaint and the Court dismissed the case in December 2025. 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.

Wholesale Generating Contracts (Applies to SWEPCo)

AEP’s subsidiaries within the Vertically Integrated Utilities and Generation & Marketing segments engage in generation supply contracts with certain wholesale customers as part of the normal course of business. These contracts have been entered into with various municipalities and cooperatives and are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued-up to actual costs annually.

During the second quarter of 2026, SWEPCo reached agreements with certain existing wholesale customers resulting in credits to these wholesale customers. During the third quarter of 2026, an agreement was reached with the remaining wholesale customer resulting in an additional $22 million credit being recorded within revenues on the statement of income for the three months ended September 30, 2026, resulting in a total year to date accrual of $45 million. All amounts have been paid in 2026.

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6. ACQUISITIONS, DISPOSITIONS AND IMPAIRMENTS

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

ACQUISITIONS

Lazbuddie Wind Energy (Applies to AEP and PSO)

In August 2026, PSO completed the acquisition of 100% of the equity interests in Lazbuddie Wind Energy, LLC, the owner of Lazbuddie Wind, a wind generation facility located in Parmer and Castro Counties, Texas. This facility, placed in service in August 2026, serves both retail and wholesale customers in Oklahoma. Oklahoma’s jurisdictional share of the Lazbuddie Wind revenue requirement, net of PTC benefit, is recoverable through existing riders until the amounts are reflected in base rates. The acquisition of Lazbuddie Wind 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 Lazbuddie Wind Energy, LLC, represented an asset acquisition. An asset acquisition is 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. The table below summarizes the impact at acquisition on PSO’s balance sheets:

Plant Name

State

Fuel Type

Net Maximum Capacity

Property, Plant and Equipment,
Net

Operating Lease Assets

Asset Retirement Obligations

(MWs)

(in millions)

Lazbuddie

Wind

265

637

Big Sandy Peaker Plant (Applies to AEP and I&M)

In August 2026, I&M completed the acquisition of 100% of the equity interests in Big Sandy Peaker Plant, LLC, the owner of the Big Sandy Peaker Plant, a natural gas-fired, simple-cycle electric generation facility located in Kenova, West Virginia. The Big Sandy Peaker Plant began commercial operations in 2001. I&M acquired the Big Sandy Peaker Plant to provide capacity and energy to both I&M Indiana and FERC jurisdictional customers. As approved by the IURC in September 2026 and prior to incorporation into the development of Indiana base rates, I&M reflects costs associated with the Big Sandy Peaker Plant either as eligible costs for recovery through existing I&M Indiana riders or in I&M’s ongoing Indiana earnings test evaluation.

In accordance with the guidance for “Business Combinations,” management determined the acquisition of the Big Sandy Peaker Plant, LLC, represented an asset acquisition. An asset acquisition is 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. The table below summarizes the impact at acquisition on I&M’s balance sheets:


Plant Name	State	Fuel Type	Net Maximum Capacity	Property, Plant and Equipment, Net		Materials and Supplies		Accounts Receivable		Accounts Payable


			(MWs)	(in millions)
Big Sandy Peaker	WV	Natural Gas	318	$	300	$	3	$	11	$	4

Wolf Hills Energy Facility (Applies to AEP and AGR)

In August 2026, AGR completed the acquisition of 100% of the equity interests in Wolf Hills Energy, LLC, the owner of the Wolf Hills Energy Facility (Wolf Hills), a natural gas-fired, simple-cycle electric generation facility located in Bristol, Virginia. Wolf Hills, a competitive generation asset operating within the PJM market, began commercial operations in 2001. As AGR is not a regulated electric utility, Wolf Hills is not currently subject to regulatory rate recovery approvals.

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In accordance with the guidance for “Business Combinations,” management determined the acquisition of Wolf Hills Energy, LLC, represented an asset acquisition. An asset acquisition is 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. The table below summarizes the impact at acquisition on AGR’s balance sheets:


Plant Name	State	Fuel Type	Net Maximum Capacity	Property, Plant and Equipment, Net		Materials and Supplies		Accounts Receivable		Accounts Payable


			(MWs)	(in millions)
Wolf Hills	VA	Natural Gas	263	$	85	$	2	$	7	$	3

Grover Hill Wind Project (Applies to AEP and APCo)

In May 2026, APCo completed the acquisition of 100% of the equity interests in Grover Hill Wind, LLC, the owner of the Grover Hill wind facility located in Paulding County, Ohio. This facility, placed in service in May 2026, serves both retail and wholesale customers in Virginia and West Virginia. The Virginia and West Virginia jurisdictional shares of the Grover Hill revenue requirement, net of PTC benefits, are recoverable through existing riders until the amounts are reflected in base rates. The acquisition of Grover Hill resulted in the recognition of operating leases for easement and access rights to the land on which the facility is located, as well as the associated ARO. In accordance with the guidance for “Business Combinations,” management determined the acquisition represented an asset acquisition. The table below summarizes the impact at acquisition on APCo’s balance sheets:

Plant Name

State

Fuel Type

Net Maximum Capacity

Property, Plant and Equipment,
Net

Operating Lease Assets

Asset Retirement Obligations

(MWs)

(in millions)

Grover Hill

Wind

143

361

Oregon Clean Energy Center (Applies to AEP and I&M)

In March 2026, I&M completed the acquisition of 100% of the equity interests in Oregon Clean Energy, LLC, the owner of the Oregon Clean Energy Center (Oregon Plant), a natural gas-powered, combined-cycle electric generation facility located in Oregon, Ohio. The Oregon Plant began commercial operations in 2017. I&M acquired the Oregon Plant to provide capacity and energy to both I&M Indiana and FERC jurisdictional customers. As approved by the IURC in November 2025 and prior to incorporation into the development of Indiana base rates, I&M reflects costs associated with the Oregon Plant either as eligible costs for recovery through existing I&M Indiana riders or in I&M’s ongoing Indiana earnings test evaluation.

In accordance with the guidance for “Business Combinations,” management determined the acquisition of the Oregon Plant represented an asset acquisition. An asset acquisition is 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. The table below summarizes the impact at acquisition on I&M’s balance sheets:


Plant Name	State	Fuel Type	Net Maximum Capacity	Property, Plant and Equipment, Net		Prepayments and Other Current Assets		Materials and Supplies		Accounts Receivable		Accounts Payable


			(MWs)	(in millions)
Oregon Plant	OH	Natural Gas	870	$	918	$	35	$	5	$	16	$	9

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

138

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 represented asset acquisitions.

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 represented 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. 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 represented 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	Property, Plant and Equipment, Net		Operating Lease Assets		Asset Retirement Obligations		Other Liabilities


			(MWs)	(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.

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.

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IMPAIRMENTS

2025 Texas Base Rate Case (Applies to AEP and SWEPCo)

During the first quarter of 2026, SWEPCo recorded a pretax disallowance of $31 million in Asset Impairments and Other Related Charges on the statements of income due to a probable, partial regulatory disallowance of recovery of the Pirkey Plant net book value in the 2025 Texas Base Rate Case. See the “2025 Texas Base Rate Case” section of Note 4 for additional information.

140

7. BENEFIT PLANS

The disclosures in this note apply 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.

Components of Net Periodic Benefit Cost (Credit)

Pension Plans


Three Months Ended September 30, 2026	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Service Cost	$	24	$	2	$	2	$	5	$	2	$	2	$	2
Interest Cost	51		5		6		6		5		3		3
Expected Return on Plan Assets	(63)		(5)		(9)		(10)		(8)		(4)		(4)

Amortization of Net Actuarial Loss	11		—		2		1		1		1		1
Settlements (a)	(1)		(5)		—		—		1		1		—
Net Periodic Benefit Cost (Credit)	$	22	$	(3)	$	1	$	2	$	1	$	3	$	2


Three Months Ended September 30, 2025	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Service Cost	$	24	$	3	$	2	$	4	$	2	$	2	$	2
Interest Cost	53		4		6		6		5		3		3
Expected Return on Plan Assets	(70)		(6)		(9)		(10)		(7)		(4)		(4)

Amortization of Net Actuarial Loss	4		—		1		—		—		—		1
Net Periodic Benefit Cost	$	11	$	1	$	—	$	—	$	—	$	1	$	2


Nine Months Ended September 30, 2026	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Service Cost	$	75	$	7	$	7	$	10	$	7	$	5	$	7
Interest Cost	154		13		18		18		14		8		9
Expected Return on Plan Assets	(191)		(15)		(25)		(26)		(20)		(11)		(11)

Amortization of Net Actuarial Loss	32		2		4		3		3		2		2
Settlements (a)	(8)		(13)		—		—		(5)		5		—
Net Periodic Benefit Cost (Credit)	$	62	$	(6)	$	4	$	5	$	(1)	$	9	$	7


Nine Months Ended September 30, 2025	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Service Cost	$	72	$	7	$	6	$	9	$	7	$	5	$	6
Interest Cost	159		13		19		19		14		8		9
Expected Return on Plan Assets	(211)		(17)		(28)		(29)		(22)		(12)		(11)

Amortization of Net Actuarial Loss	12		1		2		1		1		1		1
Net Periodic Benefit Cost (Credit)	$	32	$	4	$	(1)	$	—	$	—	$	2	$	5

(a)Represents deferrals of regulatory activity.

141

OPEB


Three Months Ended September 30, 2026	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Service Cost	$	1	$	—	$	—	$	—	$	—	$	—	$	—
Interest Cost	8		1		1		1		2		—		1
Expected Return on Plan Assets	(29)		(2)		(4)		(4)		(4)		(2)		(2)
Amortization of Prior Service Credit	(1)		—		—		—		—		—		—
Amortization of Net Actuarial Gain	(1)		—		—		—		—		—		—
Net Periodic Benefit Credit	$	(22)	$	(1)	$	(3)	$	(3)	$	(2)	$	(2)	$	(1)


Three Months Ended September 30, 2025	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Service Cost	$	1	$	—	$	—	$	—	$	—	$	—	$	—
Interest Cost	9		1		1		1		1		1		1
Expected Return on Plan Assets	(29)		(2)		(4)		(3)		(3)		(2)		(2)
Amortization of Prior Service Credit	(1)		—		—		—		—		—		—

Net Periodic Benefit Credit	$	(20)	$	(1)	$	(3)	$	(2)	$	(2)	$	(1)	$	(1)


Nine Months Ended September 30, 2026	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Service Cost	$	3	$	—	$	—	$	—	$	—	$	—	$	—
Interest Cost	23		2		3		3		2		1		2
Expected Return on Plan Assets	(88)		(7)		(12)		(11)		(9)		(5)		(6)
Amortization of Prior Service Credit	(2)		—		—		—		—		—		—
Amortization of Net Actuarial Gain	(2)		—		—		—		—		—		—
Net Periodic Benefit Credit	$	(66)	$	(5)	$	(9)	$	(8)	$	(7)	$	(4)	$	(4)


Nine Months Ended September 30, 2025	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Service Cost	$	3	$	—	$	—	$	—	$	—	$	—	$	—
Interest Cost	26		2		4		3		3		1		2
Expected Return on Plan Assets	(85)		(7)		(13)		(10)		(9)		(4)		(6)
Amortization of Prior Service Credit	(2)		—		—		—		—		—		—
Amortization of Net Actuarial Gain	(1)		—		—		—		—		—		—
Net Periodic Benefit Credit	$	(59)	$	(5)	$	(9)	$	(7)	$	(6)	$	(3)	$	(4)

142

Qualified Pension Contribution (Applies to all Registrants except AEPTCo and OPCo)

For the qualified pension plan, discretionary contributions may be made to maintain the funded status of the plan. In the second quarter of 2025, AEP made a discretionary contribution to the qualified pension plan. The following table provides details of the contribution by Registrant:


Company	Qualified Pension Plan
	(in millions)
AEP	$	95
AEP Texas	12

APCo	—
I&M	2

PSO	1
SWEPCo	9

143

8. BUSINESS SEGMENTS

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

AEP’s Reportable Segments

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 ROEs, FERC-approved ROEs or are engaged in settlement proceedings at the FERC to establish an authorized ROE.

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.

144

The tables below represent AEP’s reportable segment income statement information for the three and nine months ended September 30, 2026 and 2025 and reportable segment balance sheet information as of September 30, 2026 and December 31, 2025. The significant expenses disclosed below align with the segment-level information that is regularly provided to the CODM.



	Three Months Ended September 30, 2026
	VIU		T&D		AEPTHCo		G&M		Total Reportable Segments		Corporate and Other (a)		Reconciling Adjustments			Consolidated
	(in millions)
Revenues from:
External Customers	$	3,923	$	1,853	$	133	$	922	$	6,831	$	1	$	—		$	6,832
Other Operating Segments	78		15		482		28		603		37		(640)		(b)	—
Total Revenues	4,001		1,868		615		950		7,434		38		(640)			6,832

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	1,121		258		—		792		2,171		—		(84)			2,087
Other Operation and Maintenance	1,118		765		65		48		1,996		41		(562)			1,475

Depreciation and Amortization	659		231		136		4		1,030		(5)		—			1,025
Taxes Other Than Income Taxes	146		202		77		1		426		1		6			433
Allowance for Equity Funds Used During Construction	25		29		27		—		81		—		—			81
Interest Expense	280		119		71		2		472		176		(42)			606
Income Tax Expense (Benefit)	20		51		69		26		166		(41)		—			125
Equity Earnings of Unconsolidated Subsidiaries	—		—		24		—		24		1		—			25
Other Segment Items (c)	(15)		(13)		29		(19)		(18)		(24)		42			—
Earnings (Loss) Attributable to AEP Common Shareholders	$	697	$	284	$	219	$	96	$	1,296	$	(109)	$	—		$	1,187

Gross Property Additions	$	2,442	$	1,029	$	878	$	97	$	4,446	$	170	$	(36)		$	4,580



	Three Months Ended September 30, 2025
	VIU		T&D		AEPTHCo		G&M		Total Reportable Segments		Corporate and Other (a)		Reconciling Adjustments			Consolidated
	(in millions)
Revenues from:
External Customers	$	3,511	$	1,680	$	120	$	694	$	6,005	$	6	$	—		$	6,011
Other Operating Segments	75		10		453		18		556		30		(586)		(b)	—
Total Revenues	3,586		1,690		573		712		6,561		36		(586)			6,011

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	1,168		264		—		625		2,057		—		(76)			1,981
Other Operation and Maintenance	998		624		53		35		1,710		8		(515)			1,203

Depreciation and Amortization	547		210		124		3		884		(5)		—			879
Taxes Other Than Income Taxes	142		191		87		1		421		—		5			426
Allowance for Equity Funds Used During Construction	20		17		22		—		59		—		—			59
Interest Expense	219		107		63		1		390		140		(21)			509
Income Tax Expense (Benefit)	(25)		57		61		16		109		30		—			139
Equity Earnings of Unconsolidated Subsidiaries	—		1		20		—		21		—		—			21
Other Segment Items (c)	(21)		(12)		27		(14)		(20)		(19)		21			(18)
Earnings (Loss) Attributable to AEP Common Shareholders	$	578	$	267	$	200	$	45	$	1,090	$	(118)	$	—		$	972

Gross Property Additions	$	1,203	$	711	$	368	$	3	$	2,285	$	18	$	(24)		$	2,279

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	Nine Months Ended September 30, 2026
	VIU		T&D		AEPTHCo		G&M		Total Reportable Segments		Corporate and Other (a)		Reconciling Adjustments			Consolidated
	(in millions)
Revenues from:
External Customers	$	10,338	$	5,015	$	389	$	2,546	$	18,288	$	9	$	—		$	18,297
Other Operating Segments	223		45		1,434		65		1,767		90		(1,857)		(b)	—
Total Revenues	10,561		5,060		1,823		2,611		20,055		99		(1,857)			18,297

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	3,096		716		—		2,234		6,046		—		(238)			5,808
Other Operation and Maintenance	3,190		2,000		175		63		5,428		106		(1,640)			3,894
Asset Impairments and Other Related Charges	31		—		—		—		31		—		—			31
Depreciation and Amortization	1,787		658		397		14		2,856		(14)		—			2,842
Taxes Other Than Income Taxes	433		592		254		2		1,281		1		21			1,303
Allowance for Equity Funds Used During Construction	69		82		75		—		226		—		—			226
Interest Expense	789		341		208		5		1,343		512		(112)			1,743
Income Tax Expense (Benefit)	(92)		128		199		77		312		(91)		—			221
Equity Earnings of Unconsolidated Subsidiaries	1		—		73		—		74		5		—			79
Other Segment Items (c)	(46)		(36)		85		(52)		(49)		(77)		112			(14)
Earnings (Loss) Attributable to AEP Common Shareholders	$	1,443	$	743	$	653	$	268	$	3,107	$	(333)	$	—		$	2,774

Gross Property Additions	$	6,050	$	3,094	$	1,782	$	176	$	11,102	$	453	$	(54)		$	11,501


	Nine Months Ended September 30, 2025
	VIU		T&D		AEPTHCo		G&M		Total Reportable Segments		Corporate and Other (a)		Reconciling Adjustments			Consolidated
	(in millions)
Revenues from:
External Customers	$	9,531	$	4,638	$	391	$	1,976	$	16,536	$	25	$	—		$	16,561
Other Operating Segments	208		28		1,481		49		1,766		85		(1,851)		(b)	—
Total Revenues	9,739		4,666		1,872		2,025		18,302		110		(1,851)			16,561

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	3,164		730		—		1,701		5,595		—		(220)			5,375
Other Operation and Maintenance	2,863		1,742		136		65		4,806		44		(1,648)			3,202

Depreciation and Amortization	1,594		614		361		12		2,581		(15)		—			2,566
Taxes Other Than Income Taxes	398		555		240		2		1,195		1		17			1,213
Allowance for Equity Funds Used During Construction	52		55		66		—		173		—		—			173
Interest Expense	621		318		179		5		1,123		438		(68)			1,493
Income Tax Expense (Benefit)	(117)		142		(11)		70		84		(71)		—			13
Equity Earnings of Unconsolidated Subsidiaries	1		2		66		—		69		11		—			80
Other Segment Items (c)	(66)		(34)		86		(39)		(53)		(61)		68			(46)
Earnings (Loss) Attributable to AEP Common Shareholders	$	1,335	$	656	$	1,013	$	209	$	3,213	$	(215)	$	—		$	2,998

Gross Property Additions	$	4,356	$	2,079	$	1,182	$	10	$	7,627	$	54	$	(23)		$	7,658

146


	September 30, 2026
	VIU		T&D		AEPTHCo		G&M		Total Reportable Segments		Corporate and Other (a)			Reconciling Adjustments			Consolidated
	(in millions)
Total Assets	$	67,958	$	32,162	$	21,285	$	3,130	$	124,535	$	7,136	(d)	$	(5,976)	(e)	$	125,695

Investments in Equity Method Investees	$	8	$	2	$	1,112	$	—	$	1,122	$	282		$	—		$	1,404


	December 31, 2025
	VIU		T&D		AEPTHCo		G&M		Total Reportable Segments		Corporate and Other (a)			Reconciling Adjustments			Consolidated
	(in millions)
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

(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 Periodic 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 earnings (loss) attributable to common shareholders and 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. Earnings (loss) attributable to common shareholders and net income (loss) include 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.

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.

147

The tables below present AEPTCo’s reportable segment income statement information for the three and nine months ended September 30, 2026 and 2025 and reportable segment balance sheet information as of September 30, 2026 and December 31, 2025. The significant expenses disclosed below align with the segment-level information that is regularly provided to the CODM.



	Three Months Ended September 30, 2026
	State Transcos		AEPTCo Parent			Reconciling Adjustments			AEPTCo Consolidated
	(in millions)
Revenues from:
External Customers	$	112	$	—		$	—		$	112
Sales to AEP Affiliates	480		—			—			480
Other Revenues	2		—			—			2
Total Revenues	594		—			—			594

Other Operation and Maintenance	60		—			—			60
Depreciation and Amortization	133		—			—			133
Taxes Other Than Income Taxes	76		—			—			76
Interest Income	—		78			(75)		(a)	3
Allowance for Equity Funds Used During Construction	27		—			—			27
Interest Expense	68		74			(75)		(a)	67
Income Tax Expense	60		2			—			62
Other Segment Items (b)	—		30			—			30
Earnings (Loss) Attributable to AEPTCo Common Shareholders	$	224	$	(28)	(c)	$	—		$	196

Gross Property Additions	$	875	$	—		$	—		$	875



	Three Months Ended September 30, 2025
	State Transcos		AEPTCo Parent			Reconciling Adjustments			AEPTCo Consolidated
	(in millions)
Revenues from:
External Customers	$	108	$	—		$	—		$	108
Sales to AEP Affiliates	450		—			—			450

Total Revenues	558		—			—			558

Other Operation and Maintenance	51		—			—			51
Depreciation and Amortization	121		—			—			121
Taxes Other Than Income Taxes	86		—			—			86
Interest Income	1		66			(66)		(a)	1
Allowance for Equity Funds Used During Construction	22		—			—			22
Interest Expense	62		65			(66)		(a)	61
Income Tax Expense	56		1			—			57
Other Segment Items (b)	—		26			—			26
Earnings (Loss) Attributable to AEPTCo Common Shareholders	$	205	$	(26)	(c)	$	—		$	179

Gross Property Additions	$	358	$	—		$	—		$	358

148


	Nine Months Ended September 30, 2026
	State Transcos		AEPTCo Parent			Reconciling Adjustments			AEPTCo Consolidated
	(in millions)
Revenues from:
External Customers	$	329	$	—		$	—		$	329
Sales to AEP Affiliates	1,422		—			—			1,422
Other Revenues	9		—			—			9
Total Revenues	1,760		—			—			1,760

Other Operation and Maintenance	164		—			—			164
Depreciation and Amortization	389		—			—			389
Taxes Other Than Income Taxes	250		—			—			250
Interest Income	1		224			(218)		(a)	7
Allowance for Equity Funds Used During Construction	75		—			—			75
Interest Expense	196		218			(218)		(a)	196
Income Tax Expense	182		2			—			184
Other Segment Items (b)	—		88			—			88
Earnings (Loss) Attributable to AEPTCo Common Shareholders	$	655	$	(84)	(c)	$	—		$	571

Gross Property Additions	$	1,740	$	—		$	—		$	1,740


	Nine Months Ended September 30, 2025
	State Transcos		AEPTCo Parent			Reconciling Adjustments			AEPTCo Consolidated
	(in millions)
Revenues from:
External Customers	$	357	$	—		$	—		$	357
Sales to AEP Affiliates	1,470		—			—			1,470

Total Revenues	1,827		—			—			1,827

Other Operation and Maintenance	127		—			—			127
Depreciation and Amortization	354		—			—			354
Taxes Other Than Income Taxes	236		—			—			236
Interest Income	2		239			(238)		(a)	3
Allowance for Equity Funds Used During Construction	65		—			—			65
Interest Expense	223		188			(238)		(a)	173
Income Tax Expense (Benefit)	(39)		11			—			(28)
Other Segment Items (b)	—		87			—			87
Earnings (Loss) Attributable to AEPTCo Common Shareholders	$	993	$	(47)	(c)	$	—		$	946

Gross Property Additions	$	1,145	$	—		$	—		$	1,145


	September 30, 2026
	State Transcos		AEPTCo Parent			Reconciling Adjustments			AEPTCo Consolidated
	(in millions)








Total Assets	$	19,391	$	7,111	(d)	$	(7,033)	(e)	$	19,469


	December 31, 2025
	State Transcos		AEPTCo Parent			Reconciling Adjustments			AEPTCo Consolidated
	(in millions)








Total Assets	$	17,983	$	6,766	(d)	$	(6,750)	(e)	$	17,999

(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.

149

9. 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

	September 30, 2026														December 31, 2025
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)	336		—		34		18		2		6		6		327		—		23		8		2		8		6

Natural Gas (MMBtus)	204		—		43		5		—		72		18		166		—		48		—		—		44		26
Heating Oil and Gasoline (Gallons)	12		2		1		4		2		1		1		8		2		1		2		1		1		1
Interest Rate (USD)	$	38	$	—	$	—	$	—	$	—	$	—	$	—	$	40	$	—	$	—	$	—	$	—	$	—	$	—

Interest Rate on Long-term Debt (USD)	$	500	$	—	$	—	$	—	$	—	$	—	$	—	$	500	$	—	$	—	$	—	$	—	$	—	$	—

150

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.

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 risks.

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 $116 million and $83 million as of September 30, 2026 and December 31, 2025, respectively. The amount of cash collateral received from third-parties netted against short-term and long-term risk management assets was not material for the Registrant Subsidiaries as of September 30, 2026. 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. 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 September 30, 2026 and December 31, 2025.

151

Location and Fair Value of Derivative Assets and Liabilities Recognized On 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.


	September 30, 2026
	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Assets:	(in millions)
Current Risk Management Assets
Risk Management Contracts - Commodity	$	1,473	$	2	$	190	$	51	$	1	$	42	$	44
Hedging Contracts - Commodity	76		—		—		—		—		—		—

Total Current Risk Management Assets	1,549		2		190		51		1		42		44

Long-term Risk Management Assets
Risk Management Contracts - Commodity	630		—		1		—		—		—		—
Hedging Contracts - Commodity	54		—		—		—		—		—		—

Total Long-term Risk Management Assets	684		—		1		—		—		—		—

Total Assets	$	2,233	$	2	$	191	$	51	$	1	$	42	$	44

Liabilities:
Current Risk Management Liabilities
Risk Management Contracts - Commodity	$	1,091	$	—	$	19	$	33	$	3	$	29	$	10
Hedging Contracts - Commodity	14		—		—		—		—		—		—
Hedging Contracts - Interest Rate	18		—		—		—		—		—		—
Total Current Risk Management Liabilities	1,123		—		19		33		3		29		10

Long-term Risk Management Liabilities
Risk Management Contracts - Commodity	549		—		1		—		19		5		2
Hedging Contracts - Commodity	9		—		—		—		—		—		—
Hedging Contracts - Interest Rate	12		—		—		—		—		—		—
Total Long-term Risk Management Liabilities	570		—		1		—		19		5		2

Total Liabilities	$	1,693	$	—	$	20	$	33	$	22	$	34	$	12

Total MTM Derivative Contract Net Assets (Liabilities) Recognized	$	540	$	2	$	171	$	18	$	(21)	$	8	$	32

152



	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

153

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.


	September 30, 2026
	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
Assets:	(in millions)
Current Risk Management Assets
Gross Amounts Recognized	$	1,549	$	2	$	190	$	51	$	1	$	42	$	44
Gross Amounts Offset	(961)		(2)		(2)		(25)		(1)		(1)		(1)
Net Amounts Presented	588		—		188		26		—		41		43

Long-term Risk Management Assets
Gross Amounts Recognized	684		—		1		—		—		—		—
Gross Amounts Offset	(418)		—		(1)		—		—		—		—
Net Amounts Presented	266		—		—		—		—		—		—

Total Assets	$	854	$	—	$	188	$	26	$	—	$	41	$	43

Liabilities:
Current Risk Management Liabilities
Gross Amounts Recognized	$	1,123	$	—	$	19	$	33	$	3	$	29	$	10
Gross Amounts Offset	(914)		—		(1)		(32)		—		—		—
Net Amounts Presented	209		—		18		1		3		29		10

Long-term Risk Management Liabilities
Gross Amounts Recognized	570		—		1		—		19		5		2
Gross Amounts Offset	(356)		—		(1)		—		—		—		—
Net Amounts Presented	214		—		—		—		19		5		2

Total Liabilities	$	423	$	—	$	18	$	1	$	22	$	34	$	12

Total MTM Derivative Contract Net Assets (Liabilities)	$	431	$	—	$	170	$	25	$	(22)	$	7	$	31


	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

154

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

Amount of Gain (Loss) Recognized on Risk Management Contracts


	Three Months Ended September 30, 2026
Location of Gain (Loss)	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Vertically Integrated Utilities Revenues	$	(10)	$	—	$	—	$	—	$	—	$	—	$	—

Generation & Marketing Revenues	59		—		—		—		—		—		—
Electric Generation, Transmission and Distribution Revenues	—		—		1		(11)		—		—		—


Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	7		—		7		—		—		—		—
Other Operation	1		1		—		—		—		—		—
Maintenance	2		—		—		—		—		1		1
Regulatory Assets (a)	13		—		—		—		7		(4)		10
Regulatory Liabilities (a)	155		1		62		13		2		25		34
Total Gain on Risk Management Contracts	$	227	$	2	$	70	$	2	$	9	$	22	$	45



	Three Months Ended September 30, 2025
Location of Gain (Loss)	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Vertically Integrated Utilities Revenues	$	6	$	—	$	—	$	—	$	—	$	—	$	—

Generation & Marketing Revenues	11		—		—		—		—		—		—
Electric Generation, Transmission and Distribution Revenues	—		—		—		6		—		—		—


Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	1		—		1		—		—		—		—


Regulatory Assets (a)	(4)		—		—		1		3		(12)		3
Regulatory Liabilities (a)	59		—		18		7		1		17		12
Total Gain on Risk Management Contracts	$	73	$	—	$	19	$	14	$	4	$	5	$	15



	Nine Months Ended September 30, 2026
Location of Gain (Loss)	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Vertically Integrated Utilities Revenues	$	(39)	$	—	$	—	$	—	$	—	$	—	$	—

Generation & Marketing Revenues	169		—		—		—		—		—		—
Electric Generation, Transmission and Distribution Revenues	—		—		2		(41)		—		—		—


Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	20		—		20		—		—		—		—
Other Operation	3		1		—		—		—		—		—
Maintenance	4		1		1		—		1		1		1
Regulatory Assets (a)	15		—		—		—		12		(3)		6
Regulatory Liabilities (a)	503		2		220		27		5		99		90
Total Gain (Loss) on Risk Management Contracts	$	675	$	4	$	243	$	(14)	$	18	$	97	$	97

155



	Nine Months Ended September 30, 2025
Location of Gain (Loss)	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Vertically Integrated Utilities Revenues	$	(14)	$	—	$	—	$	—	$	—	$	—	$	—

Generation & Marketing Revenues	71		—		—		—		—		—		—
Electric Generation, Transmission and Distribution Revenues	—		—		—		(15)		—		—		—

Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	5		—		5		—		—		—		—


Regulatory Assets (a)	(9)		—		—		—		3		(14)		1
Regulatory Liabilities (a)	283		—		78		22		1		84		83
Total Gain on Risk Management Contracts	$	336	$	—	$	83	$	7	$	4	$	70	$	84

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

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
	September 30, 2026		December 31, 2025		September 30, 2026		December 31, 2025
	(in millions)
Long-term Debt (a) (b)	$	(479)	$	(484)	$	21	$	15

(a)Amounts included within Long-term Debt on the balance sheet.

(b)Amounts include $(9) million and $(14) million as of September 30, 2026 and December 31, 2025, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued.

156

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
	(in millions)
Gain (Loss) on Interest Rate Contracts:
Fair Value Hedging Instruments (a)	$	(3)	$	(1)	$	—	$	23
Fair Value Portion of Long-term Debt (a)	3		1		—		(23)

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

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 three and nine months ended September 30, 2026 and 2025, 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 three and nine months ended September 30, 2026, SWEPCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not. During the three and nine months ended September 30, 2025, the Registrants did not apply cash flow hedging to outstanding interest rate derivatives.

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

	September 30, 2026								December 31, 2025
					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	$	85	$	4	$	49	$	1	$	78	$	(1)	$	31	$	—
AEP Texas	—		5		—		1		—		6		—		1
APCo	—		4		—		1		—		4		—		1
I&M	—		(4)		—		—		—		(5)		—		—

PSO	—		2		—		—		—		2		—		—
SWEPCo	—		6		—		1		—		1		—		—

As of September 30, 2026, 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.

157

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 September 30, 2026 and December 31, 2025. The Registrant Subsidiaries had no derivative contracts with collateral triggering events in a net liability position as of September 30, 2026 and December 31, 2025.

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 $30 million as of September 30, 2026 and December 31, 2025, respectively. There was no cash collateral posted as of September 30, 2026 and December 31, 2025, 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 September 30, 2026 and December 31, 2025.

Cross-Default Triggers (Applies to AEP, APCo, I&M, 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 $207 million and $183 million and no cash collateral posted as of September 30, 2026 and December 31, 2025, respectively, after considering contractual netting arrangements. APCo, I&M, PSO and SWEPCo had derivative contracts with cross-default provisions in a net liability position of $15 million, $1 million, $31 million and $10 million, respectively, and no cash collateral posted as of September 30, 2026. 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. If a cross-default provision would have been triggered, settlement at fair value would have been required. The other Registrant Subsidiaries had immaterial derivative contracts with cross-default provisions in a net liability position as of September 30, 2026 and December 31, 2025.

158

10. FAIR VALUE MEASUREMENTS

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

Fair Value Hierarchy and Valuation Techniques

The accounting guidance for “Fair Value Measurement” 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.

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 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 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.

159

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:


	September 30, 2026				December 31, 2025
Company	Book Value		Fair Value		Book Value		Fair Value
	(in millions)
AEP	$	52,541	$	47,152	$	47,322	$	44,930
AEP Texas	7,686		6,748		7,016		6,586
AEPTCo	6,837		5,553		6,599		5,812
APCo	7,422		6,928		6,259		6,147
I&M	4,118		3,542		3,561		3,288
OPCo	3,721		3,121		3,718		3,331
PSO	4,462		4,003		3,526		3,349
SWEPCo	5,591		4,906		4,974		4,603

Fair Value Measurements of Other Temporary Investments and Restricted Cash (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.

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


	September 30, 2026
			Gross		Gross
			Unrealized		Unrealized		Fair
Other Temporary Investments and Restricted Cash	Cost		Gains		Losses		Value
	(in millions)
Restricted Cash (a)	$	89	$	—	$	—	$	89
Other Cash Deposits	15		—		—		15
Fixed Income Securities – Mutual Funds (b)	198		—		(7)		191
Equity Securities – Mutual Funds	13		33		—		46
Total Other Temporary Investments and Restricted Cash	$	315	$	33	$	(7)	$	341


	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

(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.

160

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
	(in millions)
Proceeds from Investment Sales	$	1	$	—	$	8	$	17
Purchases of Investments	22		13		37		20
Gross Realized Gains on Investment Sales	—		—		1		4
Gross Realized Losses on Investment Sales	—		—		—		1

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (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.

The following is a summary of nuclear trust fund investments:


	September 30, 2026								December 31, 2025
			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	$	35	$	—	$	—	$	—	$	29	$	—	$	—	$	—
Fixed Income Securities:
United States Government	1,440		—		(21)		(30)		1,351		22		(1)		(15)
Corporate Debt	383		—		(33)		(24)		376		6		(7)		(6)

Subtotal Fixed Income Securities	1,823		—		(54)		(54)		1,727		28		(8)		(21)
Equity Securities - Domestic	3,398		2,880		(1)		—		3,160		2,621		(1)		—
Spent Nuclear Fuel and Decommissioning Trusts	$	5,256	$	2,880	$	(55)	$	(54)	$	4,916	$	2,649	$	(9)	$	(21)

161

The following table provides the securities activity within the decommissioning and SNF trusts:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
	(in millions)
Proceeds from Investment Sales	$	1,226	$	1,038	$	2,435	$	2,332
Purchases of Investments	1,244		1,057		2,493		2,387
Gross Realized Gains on Investment Sales	126		113		134		117
Gross Realized Losses on Investment Sales	23		1		30		4

The base cost of fixed income securities was $1.9 billion and $1.7 billion as of September 30, 2026 and December 31, 2025, respectively. The base cost of equity securities was $518 million and $540 million as of September 30, 2026 and December 31, 2025, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2026 was as follows:


	Fair Value of Fixed
	Income Securities
	(in millions)
Within 1 year	$	462
After 1 year through 5 years	730
After 5 years through 10 years	273
After 10 years	358
Total	$	1,823

162

Fair Value Measurements of Financial Assets and Liabilities

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 Measurement,” 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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

September 30, 2026


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)



Other Temporary Investments and Restricted Cash
Restricted Cash	$	75	$	—	$	—	$	14	$	89
Other Cash Deposits (a)	—		—		—		15		15
Fixed Income Securities – Mutual Funds	191		—		—		—		191
Equity Securities – Mutual Funds (b)	46		—		—		—		46
Total Other Temporary Investments and Restricted Cash	312		—		—		29		341

Risk Management Assets
Risk Management Commodity Contracts (c) (d)	10		1,519		556		(1,345)		740
Cash Flow Hedges:
Commodity Hedges (c)	—		111		19		(16)		114


Total Risk Management Assets	10		1,630		575		(1,361)		854

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	18		—		—		17		35
Fixed Income Securities:
United States Government	—		1,440		—		—		1,440
Corporate Debt	—		383		—		—		383

Subtotal Fixed Income Securities	—		1,823		—		—		1,823
Equity Securities – Domestic (b)	3,398		—		—		—		3,398
Total Spent Nuclear Fuel and Decommissioning Trusts	3,416		1,823		—		17		5,256



Total Assets	$	3,738	$	3,453	$	575	$	(1,315)	$	6,451

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (d)	$	5	$	1,415	$	202	$	(1,236)	$	386
Cash Flow Hedges:
Commodity Hedges (c)	—		23		—		(16)		7

Fair Value Hedges	—		30		—		—		30
Total Risk Management Liabilities	$	5	$	1,468	$	202	$	(1,252)	$	423

163

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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) (f)	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) (f)	$	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

164

AEP Texas

Assets and Liabilities Measured at Fair Value on a Recurring Basis

September 30, 2026


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Restricted Cash for Securitized Funding	$	9	$	—	$	—	$	—	$	9

Risk Management Assets
Risk Management Commodity Contracts (c)	—		2		—		(2)		—




Total Assets	$	9	$	2	$	—	$	(2)	$	9

December 31, 2025


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Restricted Cash for Securitized Funding	$	14	$	—	$	—	$	—	$	14

165

APCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

September 30, 2026


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Restricted Cash for Securitized Funding	$	60	$	—	$	—	$	—	$	60

Risk Management Assets
Risk Management Commodity Contracts (c)	—		7		183		(2)		188




Total Assets	$	60	$	7	$	183	$	(2)	$	248

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	19	$	—	$	(1)	$	18

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

166

I&M

Assets and Liabilities Measured at Fair Value on a Recurring Basis

September 30, 2026


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Risk Management Assets
Risk Management Commodity Contracts (c)	$	—	$	16	$	28	$	(18)	$	26

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)	18		—		—		17		35
Fixed Income Securities:
United States Government	—		1,440		—		—		1,440
Corporate Debt	—		383		—		—		383

Subtotal Fixed Income Securities	—		1,823		—		—		1,823
Equity Securities - Domestic (b)	3,398		—		—		—		3,398
Total Spent Nuclear Fuel and Decommissioning Trusts	3,416		1,823		—		17		5,256

Total Assets	$	3,416	$	1,839	$	28	$	(1)	$	5,282

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	21	$	5	$	(25)	$	1

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)	$	—

167

OPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

September 30, 2026


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)



Risk Management Assets
Risk Management Commodity Contracts (c)	$	—	$	1	$	—	$	(1)	$	—



Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	—	$	22	$	—	$	22

December 31, 2025


	Level 1		Level 2		Level 3		Other		Total









Liabilities:	(in millions)

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	—	$	33	$	—	$	33

PSO

Assets and Liabilities Measured at Fair Value on a Recurring Basis

September 30, 2026


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Risk Management Assets
Risk Management Commodity Contracts (c)	$	—	$	1	$	41	$	(1)	$	41

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	34	$	—	$	—	$	34

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

168

SWEPCo

Assets and Liabilities Measured at Fair Value on a Recurring Basis

September 30, 2026


	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)



Restricted Cash for Securitized Funding	$	6	$	—	$	—	$	—	$	6

Risk Management Assets
Risk Management Commodity Contracts (c)	—		1		43		(1)		43

Total Assets	$	6	$	1	$	43	$	(1)	$	49

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c)	$	—	$	12	$	—	$	—	$	12

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

(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 September 30, 2026 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 2026 and $3 million in periods 2027-2029; Level 2 matures $(5) million in 2026, $107 million in periods 2027-2029 and $2 million in periods 2030-2031; Level 3 matures $119 million in 2026, $251 million in periods 2027-2029, $(2) million in periods 2030-2031 and $(13) million in periods 2032-2035. Risk management commodity contracts are substantially comprised of power 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, 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 power contracts.

169

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:


Three Months Ended September 30, 2026	AEP		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Balance as of June 30, 2026	$	380	$	171	$	22	$	(28)	$	43	$	42
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	123		44		6		—		25		33
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)	(28)		—		—		—		—		—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)	4		—		—		—		—		—
Settlements	(192)		(69)		(8)		—		(42)		(48)
Transfers into Level 3 (d) (e)	5		—		—		—		—		—
Transfers out of Level 3 (e)	—		—		—		—		—		—
Changes in Fair Value Allocated to Regulated Jurisdictions (f)	81		37		3		6		15		16

Balance as of September 30, 2026	$	373	$	183	$	23	$	(22)	$	41	$	43


Three Months Ended September 30, 2025	AEP		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Balance as of June 30, 2025	$	383	$	108	$	12	$	(48)	$	97	$	69
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	45		15		4		—		14		10
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)	13		—		—		—		—		—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)	1		—		—		—		—		—
Settlements	(132)		(34)		(7)		1		(45)		(30)
Transfers into Level 3 (d) (e)	7		—		—		—		—		—
Transfers out of Level 3 (e)	(5)		—		—		—		—		—
Changes in Fair Value Allocated to Regulated Jurisdictions (f)	15		2		2		3		(1)		8

Balance as of September 30, 2025	$	327	$	91	$	11	$	(44)	$	65	$	57

170



Nine Months Ended September 30, 2026	AEP		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Balance as of December 31, 2025	$	259	$	81	$	9	$	(33)	$	41	$	35
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)	245		162		12		1		47		18
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)	(24)		—		—		—		—		—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)	14		—		—		—		—		—
Settlements	(463)		(243)		(21)		3		(88)		(52)
Transfers into Level 3 (d) (e)	3		—		—		—		—		—
Transfers out of Level 3 (e)	(2)		—		—		—		—		—
Changes in Fair Value Allocated to Regulated Jurisdictions (f)	341		183		23		7		41		42

Balance as of September 30, 2026	$	373	$	183	$	23	$	(22)	$	41	$	43



Nine Months Ended September 30, 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)	155		49		13		—		38		42
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)	31		—		—		—		—		—
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)	14		—		—		—		—		—
Settlements	(277)		(84)		(19)		5		(58)		(59)
Transfers into Level 3 (d) (e)	1		—		—		—		—		—
Transfers out of Level 3 (e)	(3)		—		—		—		—		—
Changes in Fair Value Allocated to Regulated Jurisdictions (f)	240		91		11		(2)		65		57

Balance as of September 30, 2025	$	327	$	91	$	11	$	(44)	$	65	$	57

(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.

171

The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions:

Significant Unobservable Inputs

September 30, 2026


							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	$	230	$	181	Discounted Cash Flow	Forward Market Price	$	0.70	$	235.15	$	56.21

AEP	FTRs	345		21		Discounted Cash Flow	Forward Market Price	(78.84)		104.78		2.08





APCo	FTRs	183		—		Discounted Cash Flow	Forward Market Price	(2.15)		35.03		5.51

I&M	FTRs	28		5		Discounted Cash Flow	Forward Market Price	(8.24)		35.03		1.44
OPCo	Energy Contracts	—		22		Discounted Cash Flow	Forward Market Price	13.09		150.37		55.59
PSO	FTRs	41		—		Discounted Cash Flow	Forward Market Price	(20.83)		6.06		(7.01)


SWEPCo	FTRs	43		—		Discounted Cash Flow	Forward Market Price	(20.83)		6.06		(7.01)

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)

(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 and FTRs for the Registrants as of September 30, 2026 and December 31, 2025:

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)

172

11. INCOME TAXES

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

Effective Tax Rates (ETR)

The Registrants’ interim ETR reflect the estimated annual ETR for 2026 and 2025, adjusted for tax expense associated with certain discrete items.

The ETR for each of the Registrants are included in the following tables:


	Three Months Ended September 30, 2026
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
U.S. Federal Statutory Rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (Decrease) due to:
State and Local Income Taxes, Net	(0.6)	%	0.3	%	2.3	%	(3.4)	%	(0.4)	%	1.1	%	1.7	%	(5.5)	%
Tax Reform Excess ADIT Reversal	(2.4)	%	(0.7)	%	0.2	%	(4.9)	%	(2.2)	%	(8.9)	%	(1.0)	%	(2.1)	%

Production and Investment Tax Credits	(6.7)	%	(0.1)	%	—	%	(3.1)	%	(13.1)	%	—	%	(12.7)	%	(22.4)	%
Reversal of Origination Flow-Through	(0.4)	%	—	%	(0.3)	%	(3.3)	%	(1.0)	%	(0.8)	%	—	%	(0.3)	%
AFUDC Equity	(1.4)	%	(3.9)	%	(1.8)	%	(0.6)	%	(0.1)	%	0.8	%	(0.8)	%	(1.0)	%



Other	(0.2)	%	(0.1)	%	0.1	%	(0.4)	%	0.8	%	—	%	—	%	(0.2)	%
Effective Income Tax Rate	9.3	%	16.5	%	21.5	%	5.3	%	5.0	%	13.2	%	8.2	%	(10.5)	%


	Three Months Ended September 30, 2025
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
U.S. Federal Statutory Rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (Decrease) due to:
State and Local Income Taxes, Net	1.2	%	0.6	%	2.5	%	(1.2)	%	2.8	%	1.0	%	3.0	%	(3.9)	%
Tax Reform Excess ADIT Reversal	(2.5)	%	(2.3)	%	0.2	%	(3.5)	%	(5.5)	%	(2.7)	%	(4.8)	%	(3.2)	%

Production and Investment Tax Credits	(7.9)	%	(0.1)	%	—	%	0.1	%	(26.6)	%	—	%	(50.6)	%	(27.5)	%
Reversal of Origination Flow-Through	1.3	%	0.1	%	0.3	%	6.7	%	2.2	%	0.6	%	0.2	%	0.7	%
AFUDC Equity	(1.6)	%	(1.8)	%	(2.5)	%	(0.5)	%	(1.1)	%	(1.8)	%	(1.2)	%	(1.1)	%


Flow-Through of CAMT	0.6	%	—	%	—	%	6.2	%	—	%	—	%	—	%	—	%
Other	0.1	%	0.1	%	—	%	(0.7)	%	(0.8)	%	(0.3)	%	0.1	%	—	%
Effective Income Tax Rate	12.2	%	17.6	%	21.5	%	28.1	%	(8.0)	%	17.8	%	(32.3)	%	(14.0)	%

173


	Nine Months Ended September 30, 2026
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
U.S. Federal Statutory Rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (Decrease) due to:
State and Local Income Taxes, Net	1.0	%	0.5	%	2.4	%	(1.3)	%	2.5	%	1.0	%	1.7	%	(7.2)	%
Tax Reform Excess ADIT Reversal	(2.9)	%	(1.1)	%	0.2	%	(4.9)	%	(2.4)	%	(10.5)	%	(1.8)	%	(3.1)	%

Production and Investment Tax Credits	(9.5)	%	(0.1)	%	—	%	(4.8)	%	(11.0)	%	—	%	(40.1)	%	(59.4)	%

AFUDC Equity	(1.5)	%	(2.5)	%	(1.8)	%	(0.8)	%	(0.6)	%	(0.9)	%	(1.0)	%	(1.8)	%


Flow-Through of CAMT	(0.8)	%	—	%	—	%	(4.5)	%	—	%	—	%	—	%	—	%
Other	(0.1)	%	(0.1)	%	—	%	0.2	%	0.8	%	0.2	%	—	%	0.3	%
Effective Income Tax Rate	7.2	%	17.7	%	21.8	%	4.9	%	10.3	%	10.8	%	(20.2)	%	(50.2)	%


	Nine Months Ended September 30, 2025
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
U.S. Federal Statutory Rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (Decrease) due to:
State and Local Income Taxes, Net	1.0	%	0.6	%	2.5	%	0.4	%	2.4	%	1.2	%	3.0	%	(3.3)	%
Tax Reform Excess ADIT Reversal	(1.8)	%	(2.6)	%	0.4	%	(2.7)	%	(2.5)	%	(3.0)	%	(4.1)	%	(2.0)	%
Remeasurement of Excess ADIT	(12.4)	%	—	%	(25.5)	%	(5.9)	%	(12.8)	%	—	%	(8.8)	%	(17.2)	%
Production and Investment Tax Credits	(7.1)	%	(0.1)	%	—	%	—	%	(20.9)	%	—	%	(50.9)	%	(31.0)	%
Reversal of Origination Flow-Through	0.6	%	0.1	%	0.2	%	0.5	%	2.0	%	0.6	%	0.2	%	0.7	%
AFUDC Equity	(1.2)	%	(1.4)	%	(1.5)	%	(0.7)	%	(0.9)	%	(1.7)	%	(1.1)	%	(1.3)	%

Flow-Through of CAMT	0.2	%	—	%	—	%	1.7	%	—	%	—	%	—	%	—	%
Other	0.1	%	—	%	0.1	%	—	%	(0.3)	%	—	%	—	%	0.2	%
Effective Income Tax Rate	0.4	%	17.6	%	(2.8)	%	14.3	%	(12.0)	%	18.1	%	(40.7)	%	(32.9)	%

Income Taxes Paid

The following tables show the amount of income taxes paid or (received) on an interim basis, for each Registrant:


Nine Months Ended September 30, 2026	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Income Taxes Paid/(Received)	$	26	$	(20)	$	124	$	(49)	$	116	$	(21)	$	(32)	$	(34)
Transfer Credits	(63)		—		—		(4)		(50)		—		(6)		(3)
Total Cash Paid/(Received)	$	(37)	$	(20)	$	124	$	(53)	$	66	$	(21)	$	(38)	$	(37)


Nine Months Ended September 30, 2025	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Income Taxes Paid/(Received)	$	60	$	33	$	115	$	76	$	1	$	53	$	(86)	$	(61)
Transfer Credits	(102)		—		—		—		—		—		(48)		(54)
Total Cash Paid/(Received)	$	(42)	$	33	$	115	$	76	$	1	$	53	$	(134)	$	(115)

174

Federal and State Income Tax Audit Status

The statute of limitations (SOL) for the IRS to examine AEP and subsidiaries’ originally filed federal income tax returns has expired for tax years prior to 2023. In July 2026, AEP received notification that its 2023 federal income tax return would no longer be audited and only remains open for potential items identified in subsequent year exams. In the second quarter of 2026, AEP received notification that its 2024 federal income tax return was selected for IRS examination. That examination began in July 2026.

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 2023. In addition, management is monitoring and continues to evaluate the potential impact of federal legislation and corresponding state conformity.

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, influence or assistance 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 not expected to have a material impact on the Registrants.

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. Notice 2025-42 was vacated in Oregon Environmental Council v. IRS, No. CV-25-4400 (D.D.C. June 6, 2026), which restored the availability of the 5% safe harbor. There is, however, uncertainty as to whether a court would overturn the ruling on appeal. Neither the ruling nor any related subsequent decision is expected to have a material impact on the Registrants.

On February 18, 2026, the Department of Treasury and the IRS issued additional interim guidance on the application of CAMT, Notice 2026-7. This guidance allows taxpayers to deduct certain tax-deductible repairs when determining adjusted financial statement income for CAMT purposes. This guidance is expected to result in a reduction to applicable Registrants’ prior and future CAMT liabilities.

175

12. FINANCING ACTIVITIES

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

Common Stock (Applies to AEP)

ATM Program

In November 2025, AEP filed a prospectus supplement under which it may sell up to $3.5 billion of its common stock through an ATM program. In first quarter 2026, two million shares of common stock were issued for $264 million in net proceeds. In addition to these issuances and sales of shares of common stock, AEP also may use the ATM program to enter into forward sale agreements. See below for information regarding shares issued or expected to be issued under forward sale agreements.

Forward Equity Agreements

AEP has entered into the following forward sales under its ATM program and its March 2025 and May 2026 forward sale of equity agreements as follows:


	Final Maturity	Common Shares into Forward (Number of Shares)	Settled (Number of Shares) (a)	Net Proceeds from Settlement (a)		Common Shares Remaining in Forward (Number of Shares)	Expected Proceeds (b)
		(shares and dollars in millions)
March 2025 Forward Sale	December 2026	23	5	$	500	18	$	1,729
ATM Forward (c)	December 2026/July 2028	6	—	—		6	684

May 2026 Forward Sale	May 2028	24	—	—		24	2,945

(a)The five million shares were settled in 2025.

(b)Actual cash proceeds will be impacted by the timing of settlement. Forward prices are based on the public offering price (net of underwriting fees), increased for the overnight bank funding rate, less a spread and less expected dividends on AEP’s common stock during the period the agreements are outstanding.

(c)Includes three million shares with a final maturity in December 2026 and expected proceeds of $374 million and three million shares with a final maturity in July 2028 and expected proceeds of $310 million.

Long-term Debt Outstanding (Applies to AEP)

The following table details long-term debt outstanding, net of issuance costs and premiums or discounts:


Type of Debt	September 30, 2026		December 31, 2025
	(in millions)
Senior Unsecured Notes	$	41,626	$	37,190
Pollution Control Bonds	1,637		1,637
Notes Payable	574		683
Securitization Bonds	2,262		984
Spent Nuclear Fuel Obligation (a)	339		330
Junior Subordinated Notes	4,683		4,681
Other Long-term Debt	1,420		1,817
Total Long-term Debt Outstanding	52,541		47,322
Long-term Debt Due Within One Year	2,677		3,194
Long-term Debt	$	49,864	$	44,128

(a)Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for SNF disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $393 million and $381 million as of September 30, 2026 and December 31, 2025, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.

176

Long-term Debt Activity

Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2026 are shown in the following tables:


		Principal		Interest
Company	Type of Debt	Amount (a)		Rate	Due Date
Issuances:		(in millions)		(%)
AEP	Pollution Control Bonds	$	50	3.50	2030
AEP Texas	Senior Unsecured Notes	750		5.20	2036
AEPTCo	Other Long-term Debt	214		Variable	2028
AEPTCo	Senior Unsecured Notes	650		5.25	2036
APCo	Securitization Bonds	450		4.96	2035
APCo	Securitization Bonds	326		5.37	2040
APCo	Securitization Bonds	600		5.84	2046
I&M	Senior Unsecured Notes	650		5.60	2056
PSO	Senior Unsecured Notes	450		5.40	2034
PSO	Senior Unsecured Notes	550		6.30	2056
SWEPCo	Senior Unsecured Notes	300		5.30	2033
SWEPCo	Senior Unsecured Notes	600		5.20	2036
SWEPCo	Senior Unsecured Notes	750		6.00	2037
SWEPCo	Senior Unsecured Notes	500		5.90	2056




Non-Registrant:
KPCo	Other Long-term Debt	150		Variable	2028
KPCo	Pollution Control Bonds	65		3.75	2030
Transource Energy	Other Long-term Debt	37		Variable	2028





Total Issuances		$	7,092

(a)Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not agree with the issuance amounts.

177


		Principal		Interest
Company	Type of Debt	Amount Paid (a)		Rate	Due Date
Retirements and Principal Payments:		(in millions)		(%)
AEP	Pollution Control Bonds	$	50	3.20	2026

AEP Texas	Securitization Bonds	25		2.29	2029
AEP Texas	Senior Unsecured Notes	50		3.81	2026
AEPTCo	Other Long-term Debt	623		Variable	2028
APCo	Other Long-term Debt	175		Variable	2026
APCo	Other Long-term Debt	1		13.72	2026

APCo	Securitization Bonds	30		3.77	2028
I&M	Notes Payable	3		3.44	2026
I&M	Notes Payable	3		5.93	2027
I&M	Notes Payable	16		6.01	2028
I&M	Notes Payable	13		6.41	2028
I&M	Notes Payable	29		4.89	2029
I&M	Notes Payable	30		Variable	2030
PSO	Senior Unsecured Notes	50		3.05	2026
SWEPCo	Securitization Bonds	17		4.88	2039
SWEPCo	Senior Unsecured Notes	500		1.65	2026



Non-Registrant:


KPCo	Pollution Control Bonds	65		4.70	2026
KPCo	Securitization Bonds	16		5.30	2045
KPCo	Senior Unsecured Notes	120		4.18	2026
Transource Energy	Senior Unsecured Notes	3		2.75	2050
WPCo	Notes Payable	15		6.89	2034

Total Retirements and Principal Payments		$	1,834

(a)In March 2026, SWEPCo retired $1 billion of 4.24% Affiliated Notes Payable due in 2028.

Financing Activities Subsequent Events

In October 2026, AEP made capital contributions of $450 million and $210 million to AEP Texas and OPCo, respectively.

In October 2026, AEPTCo issued $270 million of variable rate Other Long-term Debt due in 2028.

In October 2026, I&M issued $110 million of 5.51% Notes Payable due in 2031.

In October 2026, I&M retired $7 million of Notes Payable related to DCC Fuel.

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 1.4% of consolidated tangible net assets as of September 30, 2026. 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 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.

178

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 Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings.

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.

Corporate Borrowing Program (Applies to all 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 September 30, 2026 and December 31, 2025 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 for the nine months ended September 30, 2026 are described in the following table:


	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		September 30, 2026		Limit
	(in millions)
AEP Texas	$	624	$	540	$	313	$	295	$	382	$	750
AEPTCo	474		342		137		56		(196)		1,070		(a)
APCo	594		648		154		21		45		950
I&M	283		855		180		147		(284)		750
OPCo	328		71		113		23		(240)		750
PSO	508		818		354		332		70		950
SWEPCo	375		1,308		258		192		494		950

(a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.

179

The activity in the above table does not include short-term lending activity of certain AEP nonutility subsidiaries. AEP Texas’ wholly-owned subsidiary, AEP Texas North Generation Company, LLC participates in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2026 and December 31, 2025 are included in Advances to Affiliates on AEP Texas’ balance sheets. The Nonutility Money Pool participants’ activity for the nine months ended September 30, 2026 is described in the following table:

Maximum Loans

Average Loans

Loans to the Nonutility

to the Nonutility

Money Pool as of

Company

Money Pool

September 30, 2026

(in millions)

AEP Texas

AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to (borrowings from) AEP as of September 30, 2026 and December 31, 2025 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 limit for the nine months ended September 30, 2026 are described in the following table:


									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		September 30,		September 30,		Limit (a)

	(in millions)
AEPTCo Parent	$	133	$	578	$	131	$	194	$	—	$	112	$	—
Midwest Transmission Holdings	—		10		—		—		—		10		—
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:


	Nine Months Ended September 30,
	2026		2025
Maximum Interest Rate	4.26	%	4.83	%
Minimum Interest Rate	2.57	%	4.00	%

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				Average Interest Rate for Funds
	Borrowed from the Utility Money Pool				Loaned to the Utility Money Pool
	for Nine Months Ended September 30,				for Nine Months Ended September 30,
Company	2026		2025		2026		2025
AEP Texas	3.94	%	4.67	%	3.98	%	4.37	%
AEPTCo	3.98	%	4.65	%	3.99	%	4.62	%
APCo	4.00	%	4.67	%	4.01	%	4.58	%
I&M	3.92	%	4.69	%	3.95	%	4.50	%
OPCo	4.01	%	4.61	%	3.99	%	4.70	%
PSO	4.02	%	4.64	%	3.76	%	4.68	%
SWEPCo	4.03	%	4.69	%	3.99	%	4.55	%

180

Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized in the following table:

Nine Months Ended September 30, 2026

Nine Months Ended September 30, 2025

Maximum

Minimum

Average

Maximum

Minimum

Average

Interest Rate

for Funds

Loaned to

the Nonutility

Company

Money Pool

AEP Texas

4.22

3.83

4.01

4.76

4.27

4.66

SWEPCo

—

4.76

4.62

4.69

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
Nine Months	for Funds		for Funds		for Funds		for Funds		for Funds		for Funds
Ended	Borrowed		Borrowed		Loaned		Loaned		Borrowed		Loaned
September 30,	from AEP		from AEP		to AEP		to AEP		from AEP		to AEP
2026	4.22	%	3.83	%	4.22	%	3.83	%	3.99	%	4.02	%
2025	4.76	%	4.27	%	4.76	%	4.27	%	4.64	%	4.64	%

Short-term Debt (Applies to AEP and SWEPCo)

Outstanding short-term debt was as follows:


		September 30, 2026				December 31, 2025
		Outstanding		Interest		Outstanding		Interest
Company	Type of Debt	Amount		Rate (a)		Amount		Rate (a)
		(dollars in millions)
AEP	Securitized Debt for Receivables (b)	$	900	4.03	%	$	900	4.00	%
AEP	Commercial Paper	975		4.21	%	605		3.92	%






SWEPCo	Notes Payable	—		—	%	3		6.30	%
	Total Short-term Debt	$	1,875			$	1,508

(a)Weighted-average rate of all borrowings outstanding as of September 30, 2026 and December 31, 2025, respectively.

(b)Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 5.

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.

181

Accounts receivable information for AEP Credit was as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2026			2025			2026			2025
	(dollars in millions)
Effective Interest Rates on Securitization of Accounts Receivable	3.97		%	4.52		%	3.94		%	4.56		%
Net Uncollectible Accounts Receivable Written-Off	$	14		$	11		$	30		$	25


	September 30, 2026		December 31, 2025
	(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts	$	1,559	$	1,230
Short-term – Securitized Debt of Receivables	900		900
Delinquent Securitized Accounts Receivable	41		66
Bad Debt Reserves Related to Securitization	41		42
Unbilled Receivables Related to Securitization	338		368

AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due.

Securitized Accounts Receivables – AEP Credit (Applies to all 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.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreements were:


Company	September 30, 2026		December 31, 2025
	(in millions)
APCo	$	210	$	203
I&M	191		175
OPCo	600		501
PSO	281		140
SWEPCo	232		169

The fees paid to AEP Credit for customer accounts receivable sold were:


	Three Months Ended September 30,				Nine Months Ended September 30,
Company	2026		2025		2026		2025

	(in millions)
APCo	$	4	$	4	$	11	$	11
I&M	4		4		12		11
OPCo	14		7		29		22
PSO	5		4		11		10
SWEPCo	4		4		11		12

182

The proceeds on the sale of receivables to AEP Credit were:


	Three Months Ended September 30,				Nine Months Ended September 30,
Company	2026		2025		2026		2025

	(in millions)
APCo	$	452	$	495	$	1,411	$	1,530
I&M	723		683		2,068		1,813
OPCo	1,070		927		2,799		2,523
PSO	809		659		1,722		1,466
SWEPCo	644		550		1,539		1,434

183

13. 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 non-consolidated VIEs are accounted for under the equity method of accounting.

Consolidated Variable Interest Entities

Appalachian Recovery Funding (Applies to AEP and APCo)

In May 2026, Appalachian Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds primarily related to certain Virginia jurisdictional Property, Plant and Equipment balances for the Amos and Mountaineer Plants and certain Virginia jurisdictional major storm costs deferred to Regulatory Assets. Management concluded that APCo holds a variable interest in Appalachian Recovery Funding and is the primary beneficiary of the VIE because APCo has the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and has the obligation to absorb losses of, or the right to receive benefits from, the VIE that could potentially be significant to the VIE. Therefore, APCo is required to consolidate Appalachian Recovery Funding. As of September 30, 2026, $35 million of the securitized bonds was included in Long-term Debt Due Within One Year - Nonaffiliated and $1.3 billion was included in Long-term Debt - Nonaffiliated on the balance sheets. Appalachian Recovery Funding’s securitized asset was $1.3 billion as of September 30, 2026 which is presented in Securitized Assets on the face of the balance sheets.

The securitized asset represents the right to impose and collect Virginia jurisdictional recovery charges from APCo’s Virginia jurisdictional customers. The securitization bonds are payable only from and secured by the securitized asset. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Recovery Funding’s securitized asset and remits all related amounts collected from customers to Appalachian Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Appalachian Recovery Funding’s assets and liabilities on APCo’s balance sheets.

The 2025 Annual Report includes a detailed discussion of AEP’s and Registrant Subsidiaries’ other consolidated VIEs.

184

The balances below represent the assets and liabilities of consolidated VIEs. These balances include intercompany transactions that are eliminated upon consolidation.




	September 30, 2026

	Consolidated VIEs
	SWEPCo Sabine		I&M DCC Fuel		AEP Texas Restoration Funding			APCo Appalachian Consumer Rate Relief Funding			APCo Appalachian Recovery Funding		SWEPCo Storm Recovery Funding		KPCo Cost Recovery Funding			AEP Credit		Protected Cell of EIS		Transource Energy
	(in millions)
ASSETS
Current Assets	$	1	$	75	$	15		$	10		$	52	$	9	$	12		$	1,561	$	257	$	55
Net Property, Plant and Equipment	—		132		—			—			—		—		—			—		—		692
Other Noncurrent Assets	57		67		80		(a)	57		(b)	1,350		302		452		(c)	11		2		27
Total Assets	$	58	$	274	$	95		$	67		$	1,402	$	311	$	464		$	1,572	$	259	$	774

LIABILITIES AND EQUITY
Current Liabilities	$	12	$	75	$	31		$	31		$	62	$	19	$	17		$	1,446	$	69	$	49
Noncurrent Liabilities	51		199		63			34			1,333		290		445			—		134		333
Equity	(5)		—		1			2			7		2		2			126		56		392
Total Liabilities and Equity	$	58	$	274	$	95		$	67		$	1,402	$	311	$	464		$	1,572	$	259	$	774

(a)Includes an intercompany item eliminated in consolidation of $3 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, 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.

185

Non-Consolidated Significant Variable Interests

OVEC (Applies to AEP and OPCo)

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. In December 2025 and April 2026, the PUCO approved the application and the FERC authorized the transaction, respectively. The transaction was completed in June 2026. As a result of the transaction, Parent remains responsible for the financial and other obligations of AGR under the intercompany power agreement.

The 2025 Annual Report includes a detailed discussion of AEP’s and Registrant Subsidiaries’ other significant variable interests in non-consolidated VIEs.

Equity Method Investment in Unconsolidated Entities

Gigawatt AI (Applies to AEP)

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 initially invested $100 million in exchange for shares of GWAI voting common stock and received a warrant to purchase additional shares of voting common stock for $50 million. Additionally, AEP committed to invest up to $100 million through four separate performance-based milestones. Upon achievement of specified performance milestones, AEP made four additional investments of $25 million each and received additional voting common stock. As of September 30, 2026, AEP had invested a cumulative $200 million in GWAI and owned 20 million shares of voting common stock, representing 21% of GWAI’s outstanding voting common stock.

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 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 September 30, 2026, AEP’s carrying value of the investment in GWAI was $200 million, which is recognized in Deferred Charges and Other Noncurrent Assets on the balance sheet. AEP’s proportionate share of GWAI’s losses was immaterial for the three and nine months ended September 30, 2026.

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 September 30, 2026.

The 2025 Annual Report includes a detailed discussion of AEP’s and Registrant Subsidiaries’ other equity method investments.

186

14. PROPERTY, PLANT AND EQUIPMENT

The disclosures in this note apply to AEP, PSO and SWEPCo.

Asset Retirement Obligations

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. AEP records ARO for the decommissioning of the Cook Plant. The table below summarizes significant changes to the Registrants’ ARO recorded in 2026 and should be read in conjunction with the Property, Plant and Equipment note within the 2025 Annual Report.


Company	ARO as of December 31, 2025		Accretion Expense		Liabilities Incurred		Liabilities Settled		Revisions in Cash Flow Estimates (a)		ARO as of September 30, 2026
	(in millions)
AEP (b)(c)(d)(e)(f)	$	3,712	$	131	$	11	$	(72)	$	43	$	3,825




PSO (b)(e)(f)	143		7		8		(5)		19		172
SWEPCo (b)(d)(e)(f)	290		12		—		(42)		4		264

(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.

187

15. 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 and Registrant Subsidiary revenues from contracts with customers, net of respective provisions for refund, by type of revenue:


	Three Months Ended September 30, 2026
	VIU (a)		T&D		AEPTHCo		G&M		Corporate and Other		Reconciling Adjustments		AEP Consolidated
	(in millions)
Retail Revenues:
Residential Revenues	$	1,612	$	905	$	—	$	—	$	—	$	—	$	2,517
Commercial Revenues	997		518		—		—		—		—		1,515
Industrial Revenues (b)	738		149		—		—		—		—		887
Other Retail Revenues	76		16		—		—		—		—		92
Total Retail Revenues	3,423		1,588		—		—		—		—		5,011

Wholesale and Competitive Retail Revenues:
Generation Revenues	338		—		—		27		1		90		456
Transmission Revenues (c)	169		220		610		—		—		(548)		451

Retail, Trading and Marketing Revenues (d)	—		—		—		806		—		(117)		689
Total Wholesale and Competitive Retail Revenues	507		220		610		833		1		(575)		1,596

Other Revenues from Contracts with Customers (e)	95		54		8		58		35		(64)		186

Total Revenues from Contracts with Customers	4,025		1,862		618		891		36		(639)		6,793

Other Revenues:
Alternative Revenue Programs (f)	(14)		1		(3)		—		—		2		(14)
Other Revenues (b) (g)	(10)		5		—		59		2		(3)		53
Total Other Revenues	(24)		6		(3)		59		2		(1)		39

Total Revenues	$	4,001	$	1,868	$	615	$	950	$	38	$	(640)	$	6,832

(a)Beginning in the first quarter of 2026, PSO and SWEPCo incorporated fuel‑related amounts into unbilled revenues to reflect consideration earned but not yet invoiced as of the balance sheet date. The change did not have a material impact on the financial statements or related disclosures.

(b)Amounts include immaterial affiliated and nonaffiliated revenues.

(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $480 million. The affiliated revenues for Vertically Integrated Utilities were $68 million. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $117 million. The remaining affiliated amounts were immaterial.

(e)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $35 million. The remaining affiliated amounts were immaterial.

(f)Alternative revenue programs in certain jurisdictions include regulatory mechanisms that periodically adjust for over/under collection of related revenues. Amounts include immaterial affiliated and nonaffiliated revenues.

(g)Generation & Marketing includes economic hedge activity.

188


	Three Months Ended September 30, 2025
	VIU		T&D		AEPTHCo		G&M		Corporate and Other		Reconciling Adjustments		AEP Consolidated
	(in millions)
Retail Revenues:
Residential Revenues	$	1,436	$	798	$	—	$	—	$	—	$	—	$	2,234
Commercial Revenues	861		423		—		—		—		—		1,284
Industrial Revenues (a)	710		134		—		—		—		(1)		843
Other Retail Revenues	67		15		—		—		—		—		82
Total Retail Revenues	3,074		1,370		—		—		—		(1)		4,443

Wholesale and Competitive Retail Revenues:
Generation Revenues	260		—		—		51		—		—		311
Transmission Revenues (b)	141		210		531		—		—		(480)		402

Retail, Trading and Marketing Revenues (c)	—		—		—		648		—		(18)		630
Total Wholesale and Competitive Retail Revenues	401		210		531		699		—		(498)		1,343

Other Revenues from Contracts with Customers (d)	97		84		12		3		34		(53)		177

Total Revenues from Contracts with Customers	3,572		1,664		543		702		34		(552)		5,963

Other Revenues:
Alternative Revenue Programs (e)	8		18		30		—		—		(32)		24
Other Revenues (a) (f)	6		8		—		10		2		(2)		24
Total Other Revenues	14		26		30		10		2		(34)		48

Total Revenues	$	3,586	$	1,690	$	573	$	712	$	36	$	(586)	$	6,011

(a)Amounts include immaterial affiliated and nonaffiliated revenues.

(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $423 million. The affiliated revenues for Vertically Integrated Utilities were $56 million. The remaining affiliated amounts were immaterial.

(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $18 million. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $31 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 $25 million. The remaining affiliated amounts were immaterial.

(f)Generation & Marketing includes economic hedge activity.

189


	Three Months Ended September 30, 2026
	AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO (a)		SWEPCo (a)
	(in millions)
Retail Revenues:
Residential Revenues	$	272	$	—	$	459	$	245	$	633	$	442	$	338
Commercial Revenues	132		—		203		281		385		224		202
Industrial Revenues (b)	43		—		195		153		106		130		115
Other Retail Revenues	11		—		27		1		4		42		3
Total Retail Revenues	458		—		884		680		1,128		838		658

Wholesale Revenues:
Generation Revenues (c)	—		—		137		169		—		5		51
Transmission Revenues (d)	192		589		62		12		29		19		60
Total Wholesale Revenues	192		589		199		181		29		24		111

Other Revenues from Contracts with Customers (e)	12		7		49		43		43		8		10

Total Revenues from Contracts with Customers	662		596		1,132		904		1,200		870		779

Other Revenues:
Alternative Revenue Programs (f)	(3)		(2)		(1)		—		4		(2)		(9)
Other Revenues (b)	—		—		2		(10)		4		—		—
Total Other Revenues	(3)		(2)		1		(10)		8		(2)		(9)

Total Revenues	$	659	$	594	$	1,133	$	894	$	1,208	$	868	$	770

(b)Amounts include immaterial affiliated and nonaffiliated revenues.

(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $42 million primarily related to the PPA with KGPCo. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEPTCo, APCo and SWEPCo were $477 million, $34 million and $26 million, respectively. The remaining affiliated amounts were immaterial.

(e)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for I&M were $23 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.

190


	Three Months Ended September 30, 2025
	AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Retail Revenues:
Residential Revenues	$	244	$	—	$	438	$	249	$	554	$	335	$	297
Commercial Revenues	124		—		195		217		298		185		189
Industrial Revenues (a)	42		—		198		150		92		112		112
Other Retail Revenues	11		—		26		1		5		33		4
Total Retail Revenues	421		—		857		617		949		665		602

Wholesale Revenues:
Generation Revenues (b)	—		—		107		141		—		7		44
Transmission Revenues (c)	184		516		44		11		25		8		61
Total Wholesale Revenues	184		516		151		152		25		15		105

Other Revenues from Contracts with Customers (d)	11		12		42		36		74		14		15

Total Revenues from Contracts with Customers	616		528		1,050		805		1,048		694		722

Other Revenues:
Alternative Revenue Programs (e)	4		30		6		1		14		—		2
Other Revenues (a)	(1)		—		1		6		8		—		—
Total Other Revenues	3		30		7		7		22		—		2

Total Revenues	$	619	$	558	$	1,057	$	812	$	1,070	$	694	$	724

(a)Amounts include immaterial affiliated and nonaffiliated revenues.

(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $41 million primarily related 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 $419 million, $19 million and $28 million, respectively. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for I&M were $19 million primarily related 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 $25 million. The remaining affiliated amounts were immaterial.

191


	Nine Months Ended September 30, 2026
	VIU (a)		T&D		AEPTHCo		G&M		Corporate and Other		Reconciling Adjustments		AEP Consolidated
	(in millions)
Retail Revenues:
Residential Revenues	$	4,048	$	2,300	$	—	$	—	$	—	$	—	$	6,348
Commercial Revenues	2,648		1,400		—		—		—		—		4,048
Industrial Revenues (b)	2,089		422		—		—		—		—		2,511
Other Retail Revenues	195		45		—		—		—		—		240
Total Retail Revenues	8,980		4,167		—		—		—		—		13,147

Wholesale and Competitive Retail Revenues:
Generation Revenues	936		—		—		126		1		90		1,153
Transmission Revenues (c)	485		657		1,795		—		—		(1,605)		1,332

Retail, Trading and Marketing Revenues (d)	—		—		—		2,179		—		(154)		2,025
Total Wholesale and Competitive Retail Revenues	1,421		657		1,795		2,305		1		(1,669)		4,510

Other Revenues from Contracts with Customers (e)	220		209		31		137		92		(171)		518

Total Revenues from Contracts with Customers	10,621		5,033		1,826		2,442		93		(1,840)		18,175

Other Revenues:
Alternative Revenue Programs (f)	(21)		8		(3)		—		—		(9)		(25)
Other Revenues (b) (g)	(39)		19		—		169		6		(8)		147

Total Other Revenues	(60)		27		(3)		169		6		(17)		122

Total Revenues	$	10,561	$	5,060	$	1,823	$	2,611	$	99	$	(1,857)	$	18,297

(b)Amounts include immaterial affiliated and nonaffiliated revenues.

(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $1.4 billion. The affiliated revenues for Vertically Integrated Utilities were $186 million. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $154 million. The remaining affiliated amounts were immaterial.

(e)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $91 million. The remaining affiliated amounts were immaterial.

(g)Generation & Marketing includes economic hedge activity.

192


	Nine Months Ended September 30, 2025
	VIU		T&D		AEPTHCo		G&M		Corporate and Other		Reconciling Adjustments		AEP Consolidated
	(in millions)
Retail Revenues:
Residential Revenues	$	3,818	$	2,149	$	—	$	—	$	—	$	—	$	5,967
Commercial Revenues	2,276		1,225		—		—		—		—		3,501
Industrial Revenues (a)	2,032		402		—		—		—		(1)		2,433
Other Retail Revenues	182		45		—		—		—		—		227
Total Retail Revenues	8,308		3,821		—		—		—		(1)		12,128

Wholesale and Competitive Retail Revenues:
Generation Revenues	802		—		—		140		—		—		942
Transmission Revenues (b)	419		604		1,751		—		—		(1,552)		1,222

Retail, Trading and Marketing Revenues (c)	—		—		—		1,808		—		(50)		1,758
Total Wholesale and Competitive Retail Revenues	1,221		604		1,751		1,948		—		(1,602)		3,922

Other Revenues from Contracts with Customers (d)	198		192		30		7		104		(148)		383

Total Revenues from Contracts with Customers	9,727		4,617		1,781		1,955		104		(1,751)		16,433

Other Revenues:
Alternative Revenue Programs (e)	26		34		91		—		—		(94)		57
Other Revenues (a) (f)	(14)		15		—		70		6		(6)		71
Total Other Revenues	12		49		91		70		6		(100)		128

Total Revenues	$	9,739	$	4,666	$	1,872	$	2,025	$	110	$	(1,851)	$	16,561

(a)Amounts include immaterial affiliated and nonaffiliated revenues.

(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEP Transmission Holdco were $1.4 billion. The affiliated revenues for Vertically Integrated Utilities were $160 million. The remaining affiliated amounts were immaterial.

(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Generation & Marketing were $50 million. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for Corporate and Other were $86 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 $74 million. The remaining affiliated amounts were immaterial.

(f)Generation & Marketing includes economic hedge activity.

193


	Nine Months Ended September 30, 2026
	AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO (a)		SWEPCo (a)
	(in millions)
Retail Revenues:
Residential Revenues	$	620	$	—	$	1,396	$	679	$	1,680	$	852	$	744
Commercial Revenues	365		—		579		807		1,034		494		526
Industrial Revenues (b)	122		—		578		458		300		316		312
Other Retail Revenues	32		—		80		4		12		96		9
Total Retail Revenues	1,139		—		2,633		1,948		3,026		1,758		1,591

Wholesale Revenues:
Generation Revenues (c)	—		—		314		573		—		10		145
Transmission Revenues (d)	573		1,733		182		34		84		47		173
Total Wholesale Revenues	573		1,733		496		607		84		57		318

Other Revenues from Contracts with Customers (e)	49		30		82		117		160		17		34

Total Revenues from Contracts with Customers	1,761		1,763		3,211		2,672		3,270		1,832		1,943

Other Revenues:
Alternative Revenue Program (f)	(7)		(3)		2		(4)		15		(4)		(14)
Other Revenues (b)	—		—		3		(41)		20		—		—
Total Other Revenues	(7)		(3)		5		(45)		35		(4)		(14)

Total Revenues	$	1,754	$	1,760	$	3,216	$	2,627	$	3,305	$	1,828	$	1,929

(b)Amounts include immaterial affiliated and nonaffiliated revenues.

(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $139 million primarily related to the PPA with KGPCo. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for AEPTCo, APCo and SWEPCo were $1.4 billion, $99 million and $68 million, respectively. The remaining affiliated amounts were immaterial.

(e)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for I&M were $57 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.

194


	Nine Months Ended September 30, 2025
	AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Retail Revenues:
Residential Revenues	$	596	$	—	$	1,410	$	671	$	1,553	$	701	$	681
Commercial Revenues	358		—		583		562		867		422		485
Industrial Revenues (a)	123		—		600		440		279		274		305
Other Retail Revenues	32		—		82		4		13		79		9
Total Retail Revenues	1,109		—		2,675		1,677		2,712		1,476		1,480

Wholesale Revenues:
Generation Revenues (b)	—		—		274		474		—		12		148
Transmission Revenues (c)	533		1,704		132		40		71		38		155
Total Wholesale Revenues	533		1,704		406		514		71		50		303

Other Revenues from Contracts with Customers (d)	29		30		75		93		164		29		31

Total Revenues from Contracts with Customers	1,671		1,734		3,156		2,284		2,947		1,555		1,814

Other Revenues:
Alternative Revenue Programs (e)	3		93		20		2		31		2		11
Other Revenues (a)	(1)		—		1		(14)		15		—		—
Total Other Revenues	2		93		21		(12)		46		2		11

Total Revenues	$	1,673	$	1,827	$	3,177	$	2,272	$	2,993	$	1,557	$	1,825

(a)Amounts include immaterial affiliated and nonaffiliated revenues.

(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for APCo were $122 million primarily related 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 $1.4 billion, $60 million and $59 million, respectively. The remaining affiliated amounts were immaterial.

(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenues for I&M were $55 million primarily related 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 $73 million. The remaining affiliated amounts were immaterial.

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 September 30, 2026. 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	$	18	$	54	$	12	$	2	$	86


APCo	2		13		7		2		24
I&M	—		1		1		1		3

195

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 material contract assets as of September 30, 2026 and December 31, 2025.

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 sheets 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.

AEP's contract liabilities primarily relate to advance payments received under contracts for the procurement of long-lead-time transmission and distribution equipment and related construction services, as well as services provided under joint use agreements for utility poles. During 2026, AEP T&D Services entered into additional transmission and distribution equipment arrangements under which customers provided consideration in advance of performance. Revenue associated with these arrangements is recognized over time as the related performance obligations are satisfied. AEP T&D Services had contract liabilities of $197 million and $37 million as of September 30, 2026 and December 31, 2025, respectively. Contract liabilities for the Registrant Subsidiaries were not material as of September 30, 2026 and December 31, 2025.

Accounts Receivable from Contracts with Customers

Accounts receivable from contracts with customers are presented on the Registrant Subsidiaries’ balance sheets within the Accounts Receivable - Customers line item. The Registrant Subsidiaries’ 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 September 30, 2026 and December 31, 2025. See “Securitized Accounts Receivables - AEP Credit” section of Note 12 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:


		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
September 30, 2026		$	1	$	157	$	149	$	83	$	90	$	35	$	48
December 31, 2025		—		146		113		67		74		22		65

196

CONTROLS AND PROCEDURES

During the third quarter of 2026, management, including the principal executive officer and principal financial officer of each of the Registrants, evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants 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 SEC’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 the Registrants’ 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 September 30, 2026, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives.

There was no change 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 third quarter of 2026 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

197

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of material legal proceedings, see Note 5 - Commitments, Guarantees and Contingencies for additional information.

Item 1A. Risk Factors

The Annual Report on Form 10-K for the year ended December 31, 2025 includes a detailed discussion of risk factors. As of September 30, 2026, there have been no material changes to the risk factors previously disclosed in AEP’s 2025 Annual Report on Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

On October 23, 2026, American Electric Power Company, Inc. (“Company”) entered into a Settlement, Release of All Claims, and Noncompetition Agreement (“Agreement”) with Alicia Knapp, former President Nuclear Development of the Company, in connection with Ms. Knapp’s previously disclosed separation from the Company. The Agreement supersedes the severance arrangements described in the Company's Current Report on Form 8-K filed on September 30, 2026.

Pursuant to the Agreement, Ms. Knapp will receive $4,342,662.00, less applicable withholdings required by law, subject to Ms. Knapp’s execution and non-revocation of the Agreement, which includes a general release, and continued compliance with the restrictive covenants and other obligations set forth therein. The amount was agreed upon with Ms. Knapp after considering certain financial consequences associated with her transition to employment with the Company and the timing of her subsequent separation. The payments and benefits under the Agreement are in lieu of any payments or benefits that Ms. Knapp otherwise may have been entitled to receive under the Company's Executive Severance Plan or General Severance Plan, and Ms. Knapp has waived any rights to benefits under those plans.

The foregoing description of the Agreement is qualified in its entirety by reference to the Agreement, a copy of which will be filed with the Company’s Annual Report on Form 10-K for the fiscal year ending December 31, 2026.

During the three months ended September 30, 2026, 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).

198

Item 6. Exhibits

The documents designated with an (*) below 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:

Exhibit

Description

Previously Filed as Exhibit to:

AEP Texas‡ File No. 333-221643

*10.1

Note Purchase Agreement, dated July 7, 2026, by and among AEP Texas, the Secretary of Energy acting through the U.S. Department of Energy and the Federal Financing Bank.

Form 8-K dated July 8, 2026, Exhibit 10.1

*10.2

Future Advance Promissory Note of AEP Texas, dated July 7, 2026.

Form 8-K dated July 8, 2026, Exhibit 10.2

*10.3

Loan Guarantee Agreement, dated July 7, 2026, by and between AEP Texas, and the U.S. Department of Energy.

Form 8-K dated July 8, 2026, Exhibit 10.3

PSO‡ File No. 0-343

*4(a)

Fourteenth Supplemental Indenture, dated as of August 1, 2026, between the Company and The Bank of New York Mellon Trust Company, N.A., as Trustee, establishing the terms of the 5.40% Senior Notes, Series O, due 2034 and the 6.30% Senior Notes, Series P, due 2056.

Form 8-K dated August 14, 2026, Exhibit 4(a)

SWEPCo‡ File No. 1-3146

*4(a)

Nineteenth Supplemental Indenture, dated as of September 16, 2026, between the Company and The Bank of New York Mellon Trust Company, N.A., as Trustee, establishing the terms of the 6.00% Senior Notes, Series S, due 2037.

Form 8-K dated September 16, 2026, Exhibit 4(a)

The exhibits designated with an (X) in the table below are being filed on behalf of the Registrants.

Exhibit

Description

AEP

AEP
Texas

AEPTCo

APCo

I&M

OPCo

PSO

SWEPCo

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

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101.SCH

XBRL Taxonomy Extension Schema

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104

Cover Page Interactive Data File

Formatted as Inline XBRL and contained in Exhibit 101.

199

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

AMERICAN ELECTRIC POWER COMPANY, INC.

By: /s/ Kate Dixon

Kate Dixon

Senior Vice President, Controller and Chief Accounting Officer

(Principal Accounting Officer and Authorized Signatory)

AEP TEXAS INC.

AEP TRANSMISSION COMPANY, LLC

APPALACHIAN POWER COMPANY

INDIANA MICHIGAN POWER COMPANY

OHIO POWER COMPANY

PUBLIC SERVICE COMPANY OF OKLAHOMA

SOUTHWESTERN ELECTRIC POWER COMPANY