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 March 31, 2026

or

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

For The Transition Period from ____ to ____

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

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

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

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
	Yes	x	No	☐

Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files).
	Yes	x	No	☐

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

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

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

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No x

AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction 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
	May 5, 2026
American Electric Power Company, Inc.	544,104,955
	($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
March 31, 2026
		Page
		Number
Glossary of Terms		i
Forward-Looking Information		vi
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	1
	Quantitative and Qualitative Disclosures About Market Risk	33
	Condensed Consolidated Financial Statements	36
AEP Texas Inc. and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	42
	Condensed Consolidated Financial Statements	44
AEP Transmission Company, LLC and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	50
	Condensed Consolidated Financial Statements	51
Appalachian Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	56
	Condensed Consolidated Financial Statements	59
Indiana Michigan Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	65
	Condensed Consolidated Financial Statements	68
Ohio Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	74
	Condensed Consolidated Financial Statements	77
Public Service Company of Oklahoma:
	Management’s Narrative Discussion and Analysis of Results of Operations	82
	Condensed Financial Statements	84
Southwestern Electric Power Company Consolidated:
	Management’s Narrative Discussion and Analysis of Results of Operations	90
	Condensed Consolidated Financial Statements	93
Index of Condensed Notes to Condensed Financial Statements of Registrants		99
Controls and Procedures		168

Part II.  OTHER INFORMATION
	Item 1.	Legal Proceedings	169
	Item 1A.	Risk Factors	169
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	169
	Item 3.	Defaults Upon Senior Securities	169
	Item 4.	Mine Safety Disclosures	169
	Item 5.	Other Information	169
	Item 6.	Exhibits	170
SIGNATURE			172
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 Texas	AEP Texas Inc., an AEP electric utility subsidiary. AEP Texas engages in the transmission and distribution of electric power to retail customers in west, central and southern Texas.
AEP Transmission Holdco / AEPTHCo	AEP Transmission Holding Company, LLC, a subsidiary of AEP, an intermediate holding company that owns transmission operations joint ventures and AEPTCo.
AEPEP	AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in deregulated markets.
AEPSC	American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo	AEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, is an intermediate holding company that owns the State Transcos.
AEPTCo Parent	AEP Transmission Company, LLC, the holding company of Midwest Transmission Holdings and the State Transcos within the AEPTCo consolidation.
AFUDC	Allowance for Funds Used During Construction.
AGR	AEP Generation Resources, Inc., a competitive AEP subsidiary in the Generation & Marketing segment.
AI	Artificial Intelligence.
ALJ	Administrative Law Judge.
AOCI	Accumulated Other Comprehensive Income.
APCo	Appalachian Power Company, an AEP electric utility subsidiary. APCo engages in the generation, transmission and distribution of electric power to retail customers in the southwestern portion of Virginia and southern West Virginia.
Appalachian Consumer Rate Relief Funding	Appalachian Consumer Rate Relief Funding, LLC, a wholly-owned subsidiary of APCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance.
APSC	Arkansas Public Service Commission.
ARO	Asset Retirement Obligations.
ASU	Accounting Standards Update.
ATM	At-the-Market.
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.

i

Term	Meaning
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 XVI, 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.
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.
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.

ii

Term	Meaning
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.
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.
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.
OCC	Corporation Commission of the State of Oklahoma.
ODEQ	Oklahoma Department of Environmental Quality.
OHTCo	AEP Ohio Transmission Company, Inc., a wholly-owned transmission subsidiary of Midwest Transmission Holdings.
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.

iii

Term	Meaning
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.
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.
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.

iv

Term	Meaning
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.

v

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

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

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

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

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

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

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

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

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

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

• The ability to 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; 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 associated with the completion of the 2026-2030 capital investment plan, including shortages or delays in labor, materials, equipment or parts.

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

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

vi

• 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 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.

• Geopolitical developments continue to create uncertainty in global energy markets and have contributed to increased volatility in fuel supply and pricing. Shifts in global market conditions and broader supply-chain pressures may influence natural gas prices, 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/.

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.

vii

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

First Quarter of 2026 Compared to First Quarter of 2025

Earnings Attributable to AEP Common Shareholders increased from $800 million in 2025 to $874 million in 2026 primarily due to:

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

•Favorable rate proceedings in AEP’s various jurisdictions.

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

•A gain related to renewable contract termination proceeds.

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

These increases were partially offset by:

•A decrease in sales volumes in the residential class driven by unfavorable weather.

•Unfavorable mark-to-market economic hedging activity driven by a decrease in commodity prices.

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

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.

1

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 March 31, 2026
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
GAAP Earnings (a)	$	874	$	120	$	183	$	195	$	148	$	117	$	15	$	56
Adjustments to GAAP Earnings:
Mark-to-Market Impact of Commodity Hedging Activities (b)	26		—		—		—		7		—		—		—
Impact of WVPSC Order (c)	(35)		—		—		(29)		—		—		—		—
Pirkey Plant Disallowance (d)	31		—		—		—		—		—		—		31
Income Tax Effect of Specified Items (e)	(5)		—		—		6		(2)		—		—		(6)
Total Specified Items	17		—		—		(23)		5		—		—		25
Operating Earnings (Non-GAAP)	$	891	$	120	$	183	$	172	$	153	$	117	$	15	$	81

(a)Represents the earnings (loss) attributable to common shareholders 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. These amounts represent the deferral of costs incurred in prior periods and are not indicative of the Company’s baseline operating performance in the current year.

(d)Represents the impact of the probable partial disallowance of the Pirkey Plant net book value in the 2025 Texas Base Rate Case. This disallowance is related to expectations related to the outcome of a pending case and is not indicative of the Company’s baseline operating performance in the current year.

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

	Three Months Ended March 31, 2025
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
GAAP Earnings (a)	$	800	$	102	$	211	$	165	$	58	$	63	$	28	$	48
Adjustments to GAAP Earnings (b):
Mark-to-Market Impact of Commodity Hedging Activities (c)	(14)		—		—		—		26		—		—		—
Sale of AEP Onsite Partners (d)	10		—		—		—		—		—		—		—
Impact of Ohio Legislation (e)	27		—		—		—		—		27		—		—
Total Specified Items	23		—		—		—		26		27		—		—
Operating Earnings (Non-GAAP)	$	823	$	102	$	211	$	165	$	84	$	90	$	28	$	48

(a)Represents the earnings (loss) attributable to common shareholders 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 sale of AEP OnSite Partners as a result of the contractual working capital true-up.

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

2

ELECTRIC INDUSTRY TRANSFORMATION

The electric utility industry is undergoing a historic transformation, fueled by rapid commercial customer class load growth, especially from data processing and other energy-intensive operations, as well as shifting regulator and customer expectations, evolving public policies, rising stakeholder demands, demographic changes, new competitive pressures, emerging technologies, necessary reliability investments and volatile commodity markets. AEP projects growth in system peak demand across its diversified service territory, with especially strong projected growth in Indiana, Ohio, Oklahoma and Texas. To meet this accelerating demand, AEP outlined a $78 billion, five-year capital plan focused on strengthening transmission infrastructure, adding new generation resources to serve both existing customers and forecasted large load additions and continuing to enhance distribution system reliability. Throughout this investment cycle, AEP remains committed to focusing on customer affordability. AEP expects to utilize various levers to address affordability including incremental load growth, rate design, continued operation and maintenance expense efficiency and financing mechanisms such as securitizations.

AEP has advanced large load tariff proposals and tariff modifications aimed at enabling the rapid interconnection of committed large load customers while protecting existing customers from increased costs. Additionally, several AEP utility subsidiaries have made rate filings with state commissions to establish new tariffs for data centers and other large load customers. The new tariffs are designed to protect existing customers by strengthening and lengthening contract terms with large customers. These new protections include contract lengths of up to 20 years and take-or-pay contractual minimums which can require a customer to pay for as much as 80-90% of their contracted demand. In practice, these provisions reduce risks around the buildout of large load infrastructure on existing customers, promoting stability and affordability. These proposals have been filed in eight of AEP’s jurisdictions, with four already approved by state commissions. As of March 31, 2026, there were four pending proposals in Michigan, Oklahoma, Texas and Virginia. AEP is actively engaging with regulators, policymakers, RTOs, customers and suppliers to advance system reliability, resiliency and affordability across its service territory during this period of rapid transformation.

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

•The addition of 870 MWs of owned generating capacity in 2026.

•Signing agreements in 2026 to acquire 1,236 MWs in additional generation facilities.

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

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

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

3

Customer Demand

AEP uses sales volumes by customer class as a way to measure drivers of customer demand. In 2026, AEP experienced higher customer demand, driven primarily by new data processing load added in the commercial and industrial customer classes. This growth was partially offset by weather-related impacts in the residential class, including unusually cold weather in the first quarter of 2025 and unusually warm weather in 2026. The table below shows the percentage change in sales volume by customer class.

(a)Percentage change for the three months ended March 31, 2026 as compared to the three months ended March 31, 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

In March 2026, I&M acquired the Oregon Clean Energy Center (Oregon Plant). The transaction reflects the Company’s focus on securing necessary generation to meet future customer demand. See “Acquisitions” section of Note 6 for additional information. The table below summarizes the acquisition:

Company	Plant Name	Fuel Type	Location	Acquisition Date	Net Maximum Capacity
					(in MWs)
I&M	Oregon Plant	Natural Gas	Oregon, OH	March 2026	870

4

Pending Natural Gas Generation

In December 2024, SWEPCo filed an application for a CCN with the APSC, LPSC and PUCT for construction of the Hallsville Natural Gas Plant (450 MWs) and the fuel conversion of Welsh Plant, Units 1 and 3 to natural gas. In the application for the CCN, SWEPCo seeks to site the Hallsville Natural Gas Plant at the location of the now-retired Pirkey Plant. In February 2026, the APSC approved both projects and regulatory proceedings in Louisiana and Texas are still underway. SWEPCo estimates the combined capital cost of these projects to be approximately $723 million and the projects would be placed in service between December 2027 and May 2028.

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

In January 2026, the IURC issued an order approving the settlement agreement in I&M’s Indiana Expedited Generation Resource (EGR) Plan filing. This order approved the settlement agreement allowing I&M to seek expedited IURC approval of future proposed PPAs, CPAs and owned generation resources to serve I&M’s increasing customer load and to implement deferral accounting for the generation resources that are approved by the IURC through the EGR Plan process.

In February 2026, I&M entered into a PSA to acquire the Big Sandy Peaker Plant, a six-unit, 318 MW combustion turbine plant located in Kenova, West Virginia. In April 2026, I&M filed an application with the IURC seeking approval of the purchase under its EGR plan. The acquisition is expected to close in the second half of 2026.

In April 2026, I&M entered into a PSA to acquire 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 proposes to acquire the Sycamore Plant to provide capacity and energy to I&M Indiana retail and FERC wholesale customers. Also in April 2026, I&M filed an application with the IURC seeking a CPCN for acquisition and development through a PSA of the Sycamore Plant. Through the application, I&M also seeks approval of the estimated project costs, proposed ratemaking and accounting treatment, and an alternative regulatory plan. A final order from the IURC is expected in December 2026.

Significant Approved Renewable Generation Filings

AEP received regulatory approvals from various state regulatory commissions to acquire approximately 1,024 MWs of owned renewable generation facilities, totaling approximately $2.6 billion. The Financial Condition section below includes the estimated cost of these facilities in the Budgeted Capital Expenditures. In addition, AEP received regulatory approvals for 1,067 MWs of renewable PPAs. The recently enacted OBBBA legislation is not expected to affect the eligibility of these generation facilities for federal tax incentives. The following table summarizes regulatory approvals received for active renewable projects that are not yet in service as of March 31, 2026:

Company	Generation Type	Expected Commercial Operation	Owned/PPA	Generating Capacity
				(in MWs)
APCo	Solar	2026-2027	PPA	113
APCo (a)	Wind	2026	Owned	140
I&M	Solar	2026-2027	PPA	280
I&M	Wind	2026-2030	PPA	674
I&M	Solar	2028	Owned	469
PSO (b)	Wind	2026	Owned	265
PSO (b)	Solar	2027	Owned	150
Total Approved Renewable Projects				2,091

(a)APCo has one wind project under construction and one wind project was terminated in the first quarter of 2026.

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

5

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

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

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

(c)Two self-build natural gas resources totaling 1,503 MWs were selected and filed for regulatory approval in December 2024. A draft 2026 All-source RFP totaling 3,000 MWs was issued in March 2026, and the final RFP is expected to be issued in May 2026.

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 March 31, 2026, by year, for the five-year period 2026-2030:

	I&M			PSO		SWEPCo
		Natural Gas	Wind	Natural Gas	Wind	Natural Gas	Wind
Delivery Start Year	(in MWs)
2026		—	73	460	86	150	74
2027		160	—	410	86	300	67
2028		1,000	—	438	—	472	—
2029		996	—	493	—	525	—
2030		996	—	568	—	299	—

6

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	Approved	New Rates
Company	Jurisdiction	Increase		ROE	ROE	Effective
		(in millions)
APCo/WPCo	West Virginia	$	91	9.75%	9.75%	August 2025	(a)
SWEPCo	Arkansas	85		9.5%	9.65%	February 2026	(b)
KPCo	Kentucky	55		9.75%	9.75%	March 2026	(c)
OPCo	Ohio	11		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 and set a procedural schedule for submitting information requests.

Pending Base Rate Case Proceedings

			Annual
		Filing	Base Revenue		Requested
Company	Jurisdiction	Date	Increase Request		ROE
			(in millions)
SWEPCo	Texas	October 2025	$	95	10.75%
PSO	Oklahoma	January 2026	299		10.5%

7

Other Significant Regulatory Matters

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. In April 2026, AEP Texas filed responses reflective of the legislative intent of Texas House Bill 5247 (2025). The impact of the final decision, and any potential retroactive impacts, as authorized by the PUCT, will be reflected in AEP Texas’ financial statements in the period in which a final decision is issued. A decision is expected in the second quarter of 2026.

In March 2026, AEP Texas began billing interim rates subject to refund as part of the UTM filing. If the PUCT issues a ruling that differs from AEP Texas’ position, a refund or billing credit could be required. Investments included in the UTM and the existing capital tracker filings remain subject to prudency review in the utility’s next base rate review before the PUCT. AEP Texas deferred approximately $80 million of eligible costs in the UTM through March 31, 2026 as a regulatory asset. If any of these deferred costs are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

2026 West Virginia Orders

In March 2026, the WVPSC issued a financing order approving APCo’s and WPCo’s (the Companies) proposed securitization for a maximum of $2.6 billion. See “2025 West Virginia Securitization Filing” section of Note 4 for additional information.

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 July 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 June 1, 2026.

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 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. The WVPSC order increased APCo’s and WPCo’s first quarter 2026 pretax net income by $29 million and $6 million, respectively. See “West Virginia Modified Rate Base Cost (MRBC) Surcharge Update Filing” section of Note 4 for additional information.

2025 Virginia Securitization Filing

In November 2025, the Virginia SCC issued a financing order approving securitization of the requested $1.4 billion of Virginia jurisdictional costs. In accordance with Virginia statutory requirements and the financing order, the issuance of the securitization bonds is subject to final review by the Virginia SCC after bond pricing. APCo expects to proceed with the securitization bond issuance process and to complete the securitization process in the first half of 2026, subject to market conditions. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See “2025 Virginia Securitization Filing” section of Note 4 for additional information.

Indiana Earnings Test

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 April 2026, I&M and an intervening party submitted a settlement agreement recommending that the IURC approve I&M’s proposed modifications to jurisdictional cost allocations and proposed over-earnings credit of $53 million for the earnings test period ending November 2025. A hearing will be held in May 2026 and an IURC order is expected in the second quarter of 2026. An IURC order approving I&M’s proposed jurisdictional cost allocation modifications as included in the settlement agreement would increase future net income and cash flows and impact financial condition. See “Indiana Earnings Test” section of Note 4 for additional information.

8

Federal Tax Legislation

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. The Company continues to evaluate the impact of the interim guidance.

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 Agreement

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

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 Holdings, LLC and Grid Growth Ventures 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 cap 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. FERC approval of the filing is pending.

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. 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.

9

As an affiliate of MGS Iowa, MGS Wisconsin is authorized to replicate MGS Iowa’s FERC-approved formula rate. This 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.

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 March 31, 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 March 31, 2026, AEP had NOLC regulatory assets of $103 million, of which $87 million are classified as pending final regulatory approval and $16 million are classified as approved for recovery.

10

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

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 November 2022, the Federal EPA made several assertions related to the CCR Rule (see “CCR Rule” section below for additional information), including an assertion that the closure of the FAR is noncompliant with the CCR Rule in multiple respects. The owners of the Gavin Power Station have notified AEP that they believe they are entitled to indemnification for any damages that may result from these claims. Management does not believe that the owners of the Gavin Power Station have any valid claim for indemnity or otherwise against AEP under the PSA. See “Claims for Indemnifications Made by Owners of the Gavin Power Station” section of Note 5 for additional information.

ENVIRONMENTAL ISSUES

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

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

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

Impact of Environmental Compliance on the Generating Fleet

The rules and environmental control requirements discussed below will have a material impact on AEP’s operations.  As of March 31, 2026, AEP owned generating capacity of approximately 26,300 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. Management continues to evaluate the impacts of these rules on the plans for the future of AEP’s generating fleet, in particular, the economic feasibility of making the requisite environmental investments in AEP’s fossil generation fleet. AEP continues to refine the cost estimates of complying with these rules to identify the best alternative for promoting compliance with all of the rules while meeting AEP’s obligations to provide reliable and affordable electricity.

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

11

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

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

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

Regional Haze

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

The Federal EPA disapproved portions of the Texas regional haze SIP and finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NOX regional haze obligations for electric generating units in Texas. Additionally, the Federal EPA finalized an intrastate SO2 emissions trading program based on CSAPR allowance allocations. Environmental groups filed challenges to these various rulemakings in district courts in the Fifth Circuit and the District of Columbia Circuit. Management cannot predict the outcome of that litigation, although management supports the intrastate trading program as a compliance alternative to source-specific controls and intervened in the Fifth Circuit litigation in support of the Federal EPA. In July 2024, the U.S. District Court for the District of Columbia Circuit entered a consent decree setting deadlines for the Federal EPA to rule on Regional Haze SIPs for 32 states, including Texas. In September 2024, the Federal EPA signed a proposed rule to partially approve and partially disapprove the Texas SIP revision. In May 2025, the Federal EPA proposed to withdraw the prior proposed rule, including the proposed partial disapproval of the Texas SIP revision, and instead proposed to approve the Texas Regional Haze SIP. In December 2025, the Federal EPA finalized its approval of the Texas and Oklahoma SIPs. The Federal EPA has recently approved Regional Haze SIP submissions for Ohio and West Virginia, both of which have been appealed by environmental groups. In February 2026, the Federal EPA proposed to approve the Regional Haze SIP for Oklahoma’s second implementation period. 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.

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

Climate Change, CO2 Regulation and Energy Policy

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

Twenty-seven states, numerous companies, trade associations and others challenged the rule. AEP has joined with several other utilities to challenge the rule and has asked the court to stay the rule during the litigation, and the appeals have been consolidated. The court 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 because 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 February 2026, the Federal EPA repealed the 2009 findings of contribution and endangerment for light-duty, medium-duty and heavy-duty vehicles and engines, which determined that GHG emissions from motor vehicles endanger public health and welfare. The Federal EPA also repealed the GHG standards for these vehicle and engine categories as part of that rulemaking. The 2009 Endangerment Finding is the basis of the Federal EPA’s authority to regulate GHG emissions under the Clean Air Act. Management is evaluating the Federal EPA’s proposed repeal of the 2009 motor vehicle Endangerment Finding and its impact on the Federal EPA’s authority to regulate GHG emissions from electric generators. Management cannot predict the outcome of the current litigation or the Federal EPA’s proposed action related to the GHG rule or its recent repeal of the Endangerment Finding related to emissions from fossil-fuel fired sources or any litigation that may result. More stringent rules directed at the fossil-fuel fired electric utility industry could force AEP to close additional coal-fired generation facilities earlier than their estimated useful life, if those rules remain in place. If AEP is unable to recover the costs of its investments, it would reduce future net income and cash flows and impact financial condition.

AEP is committed to delivering reliable, affordable power and routinely submits IRPs in various regulatory jurisdictions to address future generation needs. Accordingly, AEP continues to focus on supporting state-based clean energy mandates and decarbonization targets, including meeting the Virginia Clean Economy Act and Michigan Public Act 235 mandates that are on track for achievement. AEP remains committed to seeking advanced low-carbon generation solutions where supported. As an example, APCo and I&M are seeking early site permits to bring small modular reactors to Virginia and Indiana. AEP’s performance will ultimately be driven by the needs and desires of the states AEP serves and the company will continue to engage with regulators and policymakers to meet the energy needs while facilitating the delivery of reliable, affordable energy.

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

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

In January 2022, the Federal EPA made public statements in the context of a deadline extension request submitted by the Gavin Power Station suggesting more stringent closure requirements for CCR units. See “Claims for Indemnification Made by Owners of the Gavin Power Station” above for additional information. In April 2022, a petition was filed with the District of Columbia Circuit Court of Appeals, arguing that the Federal EPA could not enforce these new purported requirements without proper rulemaking. In June 2024, the District of Columbia Circuit 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. The proposal is expected to be finalized by the end of 2026. Management is evaluating the proposal and intends to participate 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.

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

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

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

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

Impact of Environmental Regulation on Coal-Fired Generation

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

15

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 March 31, 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	$	53	$	247		2026		(c)	$	13
SWEPCo	Pirkey Plant	—		76		(d)	2023		(e)	—
SWEPCo	Welsh Plant, Units 1 and 3	249		235			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. 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.

(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.

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RESULTS OF OPERATIONS

AEP’s Reportable Segments

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

•Vertically Integrated Utilities

•Transmission and Distribution Utilities

•AEP Transmission Holdco

•Generation & Marketing

The remainder of AEP’s activities are presented as Corporate and Other, which is not considered a reportable segment. See Note 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 March 31, 2026 as compared to the three months ended March 31, 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 months ended March 31, 2026 and 2025, see the discussions of Results of Operations by Registrant Subsidiary.

A detailed discussion of AEP’s 2025 results of operations by 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 Attributable to AEP Common Shareholders by segment:

	Three Months Ended
	March 31,
	2026		2025
	(in millions)
Vertically Integrated Utilities	$	462	$	324
Transmission and Distribution Utilities	237		165
AEP Transmission Holdco	209		235
Generation & Marketing	75		102
Corporate and Other	(109)		(26)
Earnings Attributable to AEP Common Shareholders	$	874	$	800

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.

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VERTICALLY INTEGRATED UTILITIES

Summary of KWh Energy Sales for Vertically Integrated Utilities

	Three Months Ended March 31,
	2026	2025
	(in millions of KWhs)
Retail:
Residential	8,873	9,404
Commercial	6,827	5,896
Industrial	7,998	8,101
Miscellaneous	534	533
Total Retail	24,232	23,934
Wholesale (a)	3,545	4,791
Total KWhs	27,777	28,725

(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 March 31,
	2026	2025
	(in degree days)
Eastern Region
Actual – Heating	1,575	1,617
Normal – Heating	1,566	1,567
Actual – Cooling	19	8
Normal – Cooling	5	4
Western Region
Actual – Heating	630	945
Normal – Heating	877	869
Actual – Cooling	121	59
Normal – Cooling	35	33

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Vertically Integrated Utilities
Reconciliation of 2025 to 2026 Earnings Attributable to AEP Common Shareholders
(in millions)
	Three Months Ended  March 31,
2025 Earnings Attributable to AEP Common Shareholders	$	324
Changes in Revenues:
Retail Revenues	183
Off-system Sales	82
Transmission Revenues	39
Other Revenues	(2)
Total Change in Revenues	302
Changes in Expenses and Other:
Other Operation and Maintenance	(133)
Asset Impairments and Other Related Charges	(31)
Depreciation and Amortization	(44)
Taxes Other Than Income Taxes	(10)
Other Income	(1)
Allowance for Equity Funds Used During Construction	7
Interest Expense	(45)
Total Change in Expenses and Other	(257)
Income Tax Benefit	93
2026 Earnings Attributable to AEP Common Shareholders	$	462

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

•Retail Revenues increased $183 million primarily due to the following:

•A $191 million increase in base case and rider revenues.

•A $50 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:

•A $56 million decrease in fuel revenues primarily due to decreases at APCo and SWEPCo, partially offset by an increase at I&M.

•A $21 million decrease in weather-related usage primarily in the residential class driven by a 14% decrease in heating degree days primarily in the Western Region.

•Off-system Sales increased $82 million primarily due to Rockport Plant, Unit 2 merchant sales during Winter Storm Fern in January 2026, partially offset by economic hedging activity at I&M.

•Transmission Revenues increased $39 million primarily due to continued transmission investment.

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

•Other Operation and Maintenance expenses increased $133 million primarily due to the following:

•A $34 million increase in transmission and distribution vegetation management expenses.

•A $33 million increase in generation expenses due to non-outage maintenance, nuclear and renewable energy.

•A $31 million increase in PJM and SPP transmission expenses.

•A $17 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.

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

•A $13 million increase in storm expenses.

These increases were partially offset by:

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

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

•Depreciation and Amortization expenses increased $44 million primarily due to the following:

•A $33 million increase due to a higher depreciable base at I&M, PSO and SWEPCo.

•A $27 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.

These increases were partially offset by:

•A $24 million decrease at APCo due to an April 2026 order approving a final true-up to recover past MRBC costs that were not reflected in MRBC surcharge rates in a timely manner.

•Taxes Other Than Income Taxes increased $10 million primarily due to the following:

•A $6 million increase at APCo due to higher business and occupation taxes.

•A $5 million increase at PSO due to property taxes on acquired generation facilities.

•Allowance for Equity Funds Used During Construction increased $7 million primarily due to a higher AFUDC base at SWEPCo.

•Interest Expense increased $45 million primarily due to higher long-term debt balances.

•Income Tax Benefit increased $93 million primarily due to the following:

•A $72 million increase due to an increase in PTCs.

•A $27 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.

These increases were partially offset by:

•A $9 million decrease due to an increase in pretax book income.

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TRANSMISSION AND DISTRIBUTION UTILITIES

Summary of KWh Energy Sales for Transmission and Distribution Utilities

	Three Months Ended March 31,
	2026	2025
	(in millions of KWhs)
Retail:
Residential	6,532	7,011
Commercial	12,777	9,588
Industrial	6,872	6,756
Miscellaneous	166	172
Total Retail (a)	26,347	23,527
Wholesale (b)	643	667
Total KWhs	26,990	24,194

(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 March 31,
	2026	2025
	(in degree days)
Eastern Region
Actual – Heating	1,864	1,907
Normal – Heating	1,819	1,820
Actual – Cooling	12	6
Normal – Cooling	3	2
Western Region
Actual – Heating	143	292
Normal – Heating	211	204
Actual – Cooling	224	161
Normal – Cooling	116	112

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Transmission and Distribution Utilities
Reconciliation of 2025 to 2026 Earnings Attributable to AEP Common Shareholders
(in millions)
	Three Months Ended  March 31,
2025 Earnings Attributable to AEP Common Shareholders	$	165
Changes in Revenues:
Retail Revenues	33
Off-system Sales	25
Transmission Revenues	20
Other Revenues	4
Total Change in Revenues	82
Changes in Expenses and Other:
Purchased Electricity for Resale	(4)
Purchased Electricity from AEP Affiliates	(4)
Other Operation and Maintenance	(3)
Depreciation and Amortization	(14)
Taxes Other Than Income Taxes	5
Other Income	(1)
Allowance for Equity Funds Used During Construction	6
Non-Service Cost Components of Net Periodic Benefit Cost	5
Interest Expense	7
Total Change in Expenses and Other	(3)
Income Tax Expense	(6)
Equity Earnings of Unconsolidated Subsidiary	(1)
2026 Earnings Attributable to AEP Common Shareholders	$	237

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

•Retail Revenues increased $33 million primarily due to the following:

•A $51 million increase due to higher prices for purchased power to serve OPCo’s SSO customers.

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

These increases were partially offset by:

•A $28 million decrease in weather-related usage primarily due to a 51% decrease in heating degree days in Texas and a 2% decrease in heating degree days in Ohio.

•Off-system Sales increased $25 million primarily due to increased sales of OVEC purchased power driven by higher market prices.

•Transmission Revenues increased $20 million primarily due to increased transmission investments in Ohio and Texas.

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

•Purchased Electricity for Resale increased $4 million primarily due to the following:

•A $51 million increase in recoverable auction purchases to serve SSO customers in Ohio.

This increase was partially offset by:

•A $35 million decrease due to the prior year reduction in regulatory assets for OVEC-related purchased power costs that were no longer probable of recovery due to approved legislation in Ohio in May 2025.

•A $9 million decrease due to the elimination of an OVEC-related regulatory mechanism in August 2025 as a result of approved legislation in Ohio in May 2025.

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•A $5 million decrease in OVEC purchased power costs.

•Depreciation and Amortization expenses increased $14 million primarily due to the deferral of income tax benefit from Excess ADIT credits to be refunded to customers as approved in the 2025 Ohio base rate case.

•Taxes Other Than Income Taxes decreased $5 million primarily due to a decrease in property taxes in Ohio.

•Allowance for Equity Funds Used During Construction increased $6 million primarily due to a higher AFUDC base in Texas.

•Non-Service Cost Components of Net Periodic Benefit Cost expenses decreased $5 million primarily due to the deferral of pension settlement expense approved in the 2025 base rate case.

•Interest Expense decreased $7 million primarily due to the following:

•A $12 million decrease due to the deferral of eligible costs related to the UTM in Texas.

This decrease was partially offset by:

•A $6 million increase primarily due to higher long-term debt balances in Texas.

•Income Tax Expense increased $6 million primarily due to the following:

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

This increase was partially offset by:

•A $9 million decrease from Excess ADIT credits to be refunded to customers as approved in the 2025 Ohio base rate case.

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AEP TRANSMISSION HOLDCO

Summary of Investment in Transmission Assets for AEP Transmission Holdco

	March 31,
	2026		2025
	(in millions)
Plant in Service	$	18,015	$	16,121
Construction Work in Progress	2,167		2,342
Accumulated Depreciation and Amortization	2,055		1,715
Total Transmission Property, Net	$	18,127	$	16,748

AEP Transmission Holdco
Reconciliation of 2025 to 2026
Earnings Attributable to AEP Members from AEP Transmission Holdco
(in millions)
	Three Months Ended  March 31,
2025 Earnings Attributable to AEP Members from AEP Transmission Holdco	$	235
Changes in Transmission Revenues:
Transmission Revenues	56
Total Change in Transmission Revenues	56
Changes in Expenses and Other:
Other Operation and Maintenance	(16)
Depreciation and Amortization	(15)
Taxes Other Than Income Taxes	(15)
Interest and Investment Income	2
Interest Expense	(12)
Total Change in Expenses and Other	(56)
Equity Earnings of Unconsolidated Subsidiaries	1
Net Income Attributable to Noncontrolling Interests	(27)
2026 Earnings Attributable to AEP Members from AEP Transmission Holdco	$	209

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

•Transmission Revenues increased $56 million primarily due to continued transmission investment.

Expenses and Other and Net Income Attributable to Noncontrolling Interests changed between years as follows:

•Other Operation and Maintenance expenses increased $16 million primarily due to an increase in employee-related costs, vegetation management expenses and other miscellaneous expenses.

•Depreciation and Amortization expenses increased $15 million primarily due to a higher depreciable base.

•Taxes Other than Income Taxes increased $15 million due to higher property taxes driven by higher transmission investment.

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

•Net Income Attributable to Noncontrolling Interests increased $27 million primarily due to the Midwest Transmission Holdings noncontrolling interest transaction that closed in June 2025.

24

GENERATION & MARKETING

Reconciliation of 2025 to 2026 Earnings Attributable to AEP Common Shareholders
(in millions)
	Three Months Ended  March 31,
2025 Earnings Attributable to AEP Common Shareholders	$	102
Changes in Revenues:
Retail, Trading and Marketing	174
Merchant Generation	9
Other Revenues	22
Total Change in Revenues	205
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(271)
Other Operation and Maintenance	21
Depreciation and Amortization	(1)
Interest and Investment Income	5
Non-Service Cost Components of Net Periodic Benefit Cost	(1)
Interest Expense	1
Total Change in Expenses and Other	(246)
Income Tax Expense	14
2026 Earnings Attributable to AEP Common Shareholders	$	75

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

•Retail, Trading and Marketing increased $174 million primarily due to higher market prices in 2026, partially offset by reduced MTM hedging gains.

•Merchant Generation increased $9 million primarily due to higher realized prices in 2026.

•Other Revenues increased $22 million primarily due to continued progress on 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 $271 million primarily due to an increase in energy costs in 2026.

•Other Operation and Maintenance expenses decreased $21 million primarily due to renewable contract restructuring and termination proceeds in 2026.

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

•Income Tax Expense decreased $14 million primarily due to a decrease in pretax book income.

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CORPORATE AND OTHER

First Quarter of 2026 Compared to First Quarter of 2025

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $26 million in 2025 to a loss of $109 million in 2026 primarily due to:

•A $20 million decrease in Income Tax Benefit primarily due to a $32 million decrease in PTCs, partially offset by a $12 million increase due to a decrease in pretax book income.

•A $19 million increase in interest expense primarily due to higher long-term debt balances.

•A $13 million decrease in earnings from equity method investments.

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

•A $6 million decrease at EIS primarily due to increased reserves.

These decreases in earnings were partially offset by:

•An $8 million increase in interest income primarily due to higher advances to affiliates.

AEP CONSOLIDATED INCOME TAXES

First Quarter of 2026 Compared to First Quarter of 2025

Income Tax Expense decreased $81 million primarily due to:

•A $41 million decrease due to an increase in PTCs.

•A $27 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.

•A $10 million decrease due to unfavorable adjustments in 2025.

26

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

	March 31, 2026				December 31, 2025
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	49,554	58.9	%	$	47,322	58.4	%
Short-term Debt	1,555		1.9		1,508		1.9
Total Debt	51,109		60.8		48,830		60.3
AEP Common Equity	31,808		37.8		31,138		38.4
Noncontrolling Interests	1,170		1.4		1,080		1.3
Total Debt and Equity Capitalization	$	84,087	100.0	%	$	81,048	100.0	%

AEP’s ratio of debt-to-total capital increased from 60.3% to 60.8% as of December 31, 2025 and March 31, 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 March 31, 2026, AEP had $6 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 March 31, 2026, available liquidity was approximately $5.7 billion as illustrated in the table below:

		Amount		Maturity (a)
Commercial Paper:		(in millions)
	Revolving Credit Facility	$	5,000	March 2029
	Revolving Credit Facility	1,000		March 2027
Cash and Cash Equivalents		306
Total Liquidity Sources		6,306
Less:	AEP Commercial Paper Outstanding	651
Net Available Liquidity		$	5,655

a)In April 2026, AEP increased its $5 billion Revolving Credit Facility to $6.5 billion and extended the maturity 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 maturity date from March 2027 to April 2029.

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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 three months of 2026 was $2.0 billion.  The weighted-average interest rate for AEP’s commercial paper for the three months ended March 31, 2026 was 3.87%.

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 six uncommitted facilities totaling $450 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of March 31, 2026 was $404 million with maturities ranging from April 2026 to March 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 2027. As of March 31, 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 March 31, 2026, this contractually defined percentage was 55.5%. 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, 2 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 “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 $0.95 per share in April 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.

28

Credit Ratings

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

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CASH FLOW

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

	Three Months Ended  March 31,
	2026		2025
	(in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	$	268	$	246
Net Cash Flows from Operating Activities	1,519		1,450
Net Cash Flows Used for Investing Activities	(3,569)		(2,102)
Net Cash Flows from Financing Activities	2,121		698
Net Increase in Cash, Cash Equivalents and Restricted Cash	71		46
Cash, Cash Equivalents and Restricted Cash at End of Period	$	339	$	292

Operating Activities

	Three Months Ended  March 31,
	2026		2025
	(in millions)
Net Income	$	903	$	802
Non-Cash Adjustments to Net Income (a)	1,056		941
Mark-to-Market of Risk Management Contracts	100		(15)
Property Taxes	(108)		(88)
Deferred Fuel Over/Under-Recovery, Net	(122)		(75)
Change in Other Noncurrent Assets	(351)		(131)
Change in Other Noncurrent Liabilities	433		142
Change in Certain Components of Working Capital	(392)		(126)
Net Cash Flows from Operating Activities	$	1,519	$	1,450

(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 $69 million primarily due to the following:

•A $216 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.

•A $115 million increase in cash due to changes in risk management contract collateral positions.

•A $71 million increase in cash from Change in Other Noncurrent Assets and Change in Other Noncurrent Liabilities. This increase is primarily due to changes in regulatory assets and liabilities driven by timing differences in collections from and refunds to customers under rate rider mechanisms, including storm restoration expenses incurred in several jurisdictions, as well as an increase in customer security deposits.

These increases in cash were partially offset by:

•A $266 million decrease in cash from the Change in Certain Components of Working Capital primarily due to an increase in fuel, material and supplies driven by higher coal inventory on hand, the timing of accounts receivable collections, decreased margin deposits driven by decreases in power prices and changes in income tax accruals and tax credits. These decreases in cash were partially offset by the timing of accounts payable and employee-related benefits.

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Investing Activities

	Three Months Ended  March 31,
	2026		2025
	(in millions)
Construction Expenditures	$	(2,830)	$	(2,100)
Acquisitions of Generation Facilities	(965)		—
Acquisitions of Nuclear Fuel	(13)		(36)
Other	239		34
Net Cash Flows Used for Investing Activities	$	(3,569)	$	(2,102)

Net Cash Flows Used for Investing Activities increased by $1.5 billion primarily due to the following:

•A $965 million increase due to the acquisition of the Oregon Clean Energy Center. See “Acquisitions” section of Note 6 for additional information.

•A $730 million increase in Construction Expenditures primarily due to increases in Transmission and Distribution Utilities of $357 million, Vertically Integrated Utilities of $258 million and Corporate and Other of $117 million.

Financing Activities

	Three Months Ended  March 31,
	2026		2025
	(in millions)
Issuance of Common Stock	$	358	$	75
Issuance/Retirement of Debt, Net	2,275		1,155
Principal Payments for Finance Lease Obligations	(24)		(13)
Dividends Paid on Common Stock	(520)		(500)
Other	32		(19)
Net Cash Flows from Financing Activities	$	2,121	$	698

Net Cash Flows from Financing Activities increased by $1.4 billion primarily due to the following:

•A $2.3 billion increase in issuances of long-term debt. See Note 12 - Financing Activities for additional information.

•A $283 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 $775 million decrease due to changes in short-term debt.

•A $449 million increase in retirements of long-term debt. See Note 12 - Financing Activities 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 March 31, 2026 through May 5, 2026, the date that the first quarter Form 10-Q was filed.

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BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately $12.8 billion of capital expenditures in 2026.  For the four-year period, 2027 through 2030, management forecasts capital expenditures of $65.1 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 2026-2030 estimated capital expenditures by Business Segment are as follows:

Segment	2026-2030 Budgeted Capital Expenditures
	(in millions)
Vertically Integrated Utilities	$	40,879
Transmission and Distribution Utilities	22,537
AEP Transmission Holdco	12,855
Generation & Marketing	111
Corporate and Other	1,555
Total	$	77,937

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.

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

Market risk evaluations are subject to certain limitations that may prevent a full reflection of the net market risk exposure. These limitations primarily relate to model and data constraints that rely on hypothetical assumptions and may not capture all potential future market conditions. These include the use of historical information, assumptions about market volatility and correlations, and dependence on observable inputs that may not be available for less liquid positions. As a result, the actual impact of market movements could differ from the estimates presented.

The Vertically Integrated Utilities segment is exposed to certain market risks as a major power producer and through transactions in power, coal, natural gas and marketing contracts. These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk. These risks represent the risk of loss that may impact this segment due to changes in the underlying market prices or rates.

The Transmission and Distribution Utilities segment is exposed to energy procurement risk and interest rate risk.

The Generation & Marketing segment conducts marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. This segment is exposed to certain market risks as a marketer of wholesale and retail electricity. These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk. These risks represent the risk of loss that may impact this segment due to changes in the underlying market prices or rates. In addition, the Generation & Marketing segment is also exposed to certain market risks as a power producer and through transactions in wholesale electricity, natural gas and marketing contracts.

Management employs risk management contracts including physical forward and financial forward purchase-and-sale contracts.  Management engages in risk management of power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business.  As a result, AEP is subject to price risk.  The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the AEP Board.  AEPSC’s market risk oversight staff independently monitor risk policies, procedures and risk levels and provide members of the Regulated Risk Committee and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures.  The Regulated Risk Committee consists of AEPSC’s Chief Financial Officer, Executive Vice President and Chief Commercial Officer, Senior Vice President and Treasurer, Senior Vice President of Regulated Commercial Operations, President AEP Transmission, and Senior Vice President Finance. The Competitive Risk Committee consists of AEPSC’s Chief Financial Officer, Executive Vice President and Chief Commercial Officer, Senior Vice President and Treasurer, and Senior Vice President of Competitive Commercial Operations.  If commercial activities result in predetermined limits being exceeded, positions are modified to reduce the risk to be within the limits unless specifically approved by the respective committee.

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The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2025:

MTM Derivative Contract Net Assets (Liabilities)

Three Months Ended March 31, 2026
	Vertically Integrated Utilities		Transmission and Distribution Utilities		Generation & Marketing		Total
	(in millions)
Total MTM Risk Management Contracts - Commodity Net Assets (Liabilities) as of December 31, 2025	$	143	$	(33)	$	208	$	318
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period	(160)		1		(24)		(183)
Fair Value of New Contracts at Inception When Entered During the Period (a)	—		—		10		10
Changes in Fair Value Due to Market Fluctuations During the Period (b)	(7)		—		7		—
Changes in Fair Value Allocated to Regulated Jurisdictions (c)	33		3		—		36
Total MTM Risk Management Contracts - Commodity Net Assets (Liabilities) as of March 31, 2026	$	9	$	(29)	$	201	$	181
Commodity Cash Flow Hedge Contracts							79
Fair Value Hedge Contracts							(32)
Collateral Deposits							(44)
Total MTM Derivative Contract Net Assets as of March 31, 2026							$	184

(a)Reflects fair value on primarily auctions or long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged.

(b)Market fluctuations are attributable to various factors such as supply/demand, weather, etc.

(c)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income.  These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable on the balance sheet.

See Note 9 – Derivatives and Hedging and Note 10 – Fair Value Measurements for additional information related to risk management contracts.  The following table and discussion provide information on credit risk and market volatility risk.

Credit Risk

Credit risk is mitigated in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

AEP has risk management contracts (including non-derivative contracts) with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily. As of March 31, 2026, credit exposure net of collateral to sub-investment grade counterparties was approximately 6.3%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).

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As of March 31, 2026, the following table approximates AEP’s counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:

Counterparty Credit Quality	Exposure Before Credit Collateral		Credit Collateral		Net Exposure		Number of Counterparties >10% of Net Exposure	Net Exposure of Counterparties >10%
	(in millions, except number of counterparties)
Investment Grade	$	604	$	42	$	562	4	$	365
Split Rating	10		10		—		1	—
Non-investment Grade	—		—		—		—	—
No External Ratings:
Internal Investment Grade	22		—		22		2	17
Internal Non-investment Grade	97		57		40		2	31
Total as of March 31, 2026	$	733	$	109	$	624

All exposure in the table above relates to AEPSC and AEPEP, as AEPSC serves as agent for, and transacts on behalf of, certain AEP subsidiaries, including the Registrant Subsidiaries, while AEPEP serves as agent for, and transacts on behalf of, other AEP subsidiaries.

In addition, AEP is exposed to credit risk related to participation in RTOs. For each of the RTOs in which AEP participates, this risk is generally determined based on the proportionate share of member gross activity over a specified period of time.

Value at Risk (VaR) Associated with Risk Management Contracts

Management uses a risk measurement model to calculate VaR and measure AEP’s commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, as of March 31, 2026, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.

Management calculates the VaR for both a trading and non-trading portfolio. The trading portfolio consists primarily of contracts related to energy trading and marketing activities, while the non-trading portfolio consists primarily of economic hedges of generation and retail supply activities. For the three months ended March 31, 2026, and twelve months ended December 31, 2025, the market risks measured by VaR for both trading and non-trading portfolios were immaterial.

Management back-tests VaR results against performance due to actual price movements. Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.

As the VaR calculation captures recent price movements, management also performs regular stress testing of the trading portfolio to understand AEP’s exposure to extreme price movements. A historical-based method is employed whereby the current trading portfolio is subjected to actual, observed price movements from the last several years in order to ascertain which historical price movements translated into the largest potential MTM loss. Management then researches the underlying positions, price movements and market events that created the most significant exposure and reports the findings to the Risk Executive Committee, Regulated Risk Committee or Competitive Risk Committee as appropriate.

Interest Rate Risk

AEP is exposed to interest rate market fluctuations in the normal course of business operations. After several increases in rates during 2022 and 2023, the Federal Reserve authorized rate cuts in 2024 and 2025, resulting in a 3.50%-3.75% target range as of December 31, 2025. There have been no changes in rates during the first quarter of 2026. AEP has outstanding short- and long-term debt which is subject to variable rates. AEP manages interest rate risk by limiting variable-rate exposures to a percentage of total debt, by entering into interest rate derivative instruments and by monitoring the effects of market changes on interest rates. For the three months ended March 31, 2026 and 2025, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense annually by $36 million and $43 million, respectively.

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2026 and 2025

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

(Unaudited)

	Three Months Ended March 31,
	2026		2025
REVENUES
Vertically Integrated Utilities	$	3,365	$	3,086
Transmission and Distribution Utilities	1,594		1,515
Generation & Marketing	931		730
Other Revenues	130		132
TOTAL REVENUES	6,020		5,463
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	2,118		1,853
Other Operation	750		752
Maintenance	411		319
Asset Impairments and Other Related Charges	31		—
Depreciation and Amortization	907		833
Taxes Other Than Income Taxes	443		422
TOTAL EXPENSES	4,660		4,179
OPERATING INCOME	1,360		1,284
Other Income (Expense):
Other Income	6		8
Allowance for Equity Funds Used During Construction	70		57
Non-Service Cost Components of Net Periodic Benefit Cost	38		35
Interest Expense	(552)		(495)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	922		889
Income Tax Expense	44		125
Equity Earnings of Unconsolidated Subsidiaries	25		38
NET INCOME	903		802
Net Income Attributable to Noncontrolling Interests	29		2
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	874	$	800
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	542,079,269		533,391,487
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1.61	$	1.50
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	547,054,104		534,663,493
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1.60	$	1.50
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
Net Income	$	903	$	802
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $(4) and $6 in 2026 and 2025, Respectively	(15)		23
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 in 2026 and 2025, Respectively	1		1
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(14)		24
TOTAL COMPREHENSIVE INCOME	889		826
Total Comprehensive Income Attributable To Noncontrolling Interests	29		2
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	860	$	824
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

37

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Three Months Ended March 31, 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
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 Noncontrolling Interest											96		96
Common Stock Dividends						(520)		(b)					(520)
Dividends Paid to Noncontrolling Interest											(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

(a)    Cash dividends declared per AEP common share were $0.93.

(b)    Cash dividends declared per AEP common share were $0.95.

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

38

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2026 and December 31, 2025

(in millions)

(Unaudited)

	March 31,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	306	$	197
Restricted Cash (March 31, 2026 and December 31, 2025 Amounts Include $33 and $71, Respectively, Related to Restoration Funding, Appalachian Consumer Rate Relief Funding, Storm Recovery Funding and Cost Recovery Funding)	33		71
Other Temporary Investments (March 31, 2026 and December 31, 2025 Amounts Include $202 and $209, Respectively, Related to EIS)	210		220
Accounts Receivable:
Customers	1,338		1,166
Accrued Unbilled Revenues	349		421
Pledged Accounts Receivable – AEP Credit	1,288		1,272
Miscellaneous	53		60
Allowance for Credit Losses	(58)		(52)
Total Accounts Receivable	2,970		2,867
Fuel	567		576
Materials and Supplies	1,098		1,046
Risk Management Assets	246		352
Accrued Tax Benefits	214		85
Regulatory Asset for Under-Recovered Fuel Costs	594		426
Prepayments and Other Current Assets	385		212
TOTAL CURRENT ASSETS	6,623		6,052
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	28,879		28,388
Transmission	43,093		42,557
Distribution	33,902		33,364
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	9,119		8,635
Construction Work in Progress	8,314		7,635
Total Property, Plant and Equipment	123,307		120,579
Accumulated Depreciation and Amortization	28,453		28,205
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	94,854		92,374
OTHER NONCURRENT ASSETS
Regulatory Assets	5,070		4,804
Securitized Assets	912		933
Spent Nuclear Fuel and Decommissioning Trusts	4,803		4,916
Goodwill	53		53
Long-term Risk Management Assets	233		265
Operating Lease Assets	650		661
Deferred Charges and Other Noncurrent Assets	4,578		4,402
TOTAL OTHER NONCURRENT ASSETS	16,299		16,034
TOTAL ASSETS	$	117,776	$	114,460
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

39

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

March 31, 2026 and December 31, 2025

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

(Unaudited)

			March 31,		December 31,
			2026		2025
CURRENT LIABILITIES
Accounts Payable			$	3,148	$	3,429
Short-term Debt:
Securitized Debt for Receivables – AEP Credit			900		900
Other Short-term Debt			655		608
Total Short-term Debt			1,555		1,508
Long-term Debt Due Within One Year (March 31, 2026 and December 31, 2025 Amounts Include $200 and $207, Respectively, Related to DCC Fuel, Restoration Funding, Appalachian Consumer Rate Relief Funding, Storm Recovery Funding, Transource Energy and Cost Recovery Funding)			2,704		3,194
Risk Management Liabilities			130		132
Customer Deposits			521		507
Accrued Taxes			1,888		2,002
Accrued Interest			629		544
Obligations Under Operating Leases			95		100
Other Current Liabilities			1,924		1,898
TOTAL CURRENT LIABILITIES			12,594		13,314
NONCURRENT LIABILITIES
Long-term Debt (March 31, 2026 and December 31, 2025 Amounts Include $1,246 and $1,294, Respectively, Related to DCC Fuel, Restoration Funding, Appalachian Consumer Rate Relief Funding, Storm Recovery Funding, Transource Energy and Cost Recovery Funding)			46,850		44,128
Long-term Risk Management Liabilities			165		178
Deferred Income Taxes			11,249		10,951
Regulatory Liabilities and Deferred Investment Tax Credits			8,230		8,362
Asset Retirement Obligations			3,607		3,556
Employee Benefits and Pension Obligations			245		232
Obligations Under Operating Leases			572		578
Deferred Credits and Other Noncurrent Liabilities			1,235		905
TOTAL NONCURRENT LIABILITIES			72,153		68,890
TOTAL LIABILITIES			84,747		82,204
Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)
Contingently Redeemable Performance Share Awards			51		38
EQUITY
Common Stock – Par Value – $6.50 Per Share:
	2026	2025
Shares Authorized	600,000,000	600,000,000
Shares Issued	545,159,912	542,048,288
(1,186,815 Shares were Held in Treasury as of March 31, 2026 and December 31, 2025, Respectively)			3,544		3,523
Paid-in Capital			12,447		12,138
Retained Earnings			15,795		15,441
Accumulated Other Comprehensive Income (Loss)			22		36
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY			31,808		31,138
Noncontrolling Interests			1,170		1,080
TOTAL EQUITY			32,978		32,218
TOTAL LIABILITIES AND EQUITY			$	117,776	$	114,460
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

40

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	903	$	802
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	907		833
Deferred Income Taxes	188		165
Asset Impairments and Other Related Charges	31		—
Allowance for Equity Funds Used During Construction	(70)		(57)
Mark-to-Market of Risk Management Contracts	100		(15)
Property Taxes	(108)		(88)
Deferred Fuel Over/Under-Recovery, Net	(122)		(75)
Change in Other Noncurrent Assets	(351)		(131)
Change in Other Noncurrent Liabilities	433		142
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(36)		(2)
Fuel, Materials and Supplies	(39)		139
Accounts Payable	108		6
Accrued Taxes, Net	(244)		(153)
Other Current Assets	(115)		(23)
Other Current Liabilities	(66)		(93)
Net Cash Flows from Operating Activities	1,519		1,450
INVESTING ACTIVITIES
Construction Expenditures	(2,830)		(2,100)
Purchases of Investment Securities	(575)		(603)
Sales of Investment Securities	555		587
Acquisitions of Generation Facilities	(965)		—
Acquisitions of Nuclear Fuel	(13)		(36)
Contribution in Aid of Construction Advances	260		55
Other Investing Activities	(1)		(5)
Net Cash Flows Used for Investing Activities	(3,569)		(2,102)
FINANCING ACTIVITIES
Capital Contribution from Noncontrolling Interest	96		—
Issuance of Common Stock	358		75
Issuance of Long-term Debt	2,906		562
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	47		752
Retirement of Long-term Debt	(678)		(229)
Redemption of Short-term Debt with Original Maturities Greater than 90 Days	—		(250)
Principal Payments for Finance Lease Obligations	(24)		(13)
Dividends Paid on Common Stock	(520)		(500)
Dividends Paid to Noncontrolling Interest	(35)		(1)
Other Financing Activities	(29)		(18)
Net Cash Flows from Financing Activities	2,121		698
Net Increase in Cash, Cash Equivalents and Restricted Cash	71		46
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	268		246
Cash, Cash Equivalents and Restricted Cash at End of Period	$	339	$	292
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

41

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 March 31,
	2026	2025
	(in millions of KWhs)
Retail:
Residential	2,531	2,916
Commercial	5,058	4,099
Industrial	3,494	3,370
Miscellaneous	138	144
Total Retail	11,221	10,529

Summary of Heating and Cooling Degree Days

	Three Months Ended March 31,
	2026	2025
	(in degree days)
Actual – Heating	143	292
Normal – Heating	211	204
Actual – Cooling	224	161
Normal – Cooling	116	112

42

AEP Texas Inc. and Subsidiaries
Reconciliation of 2025 to 2026
Net Income
(in millions)
	Three Months Ended  March 31,
2025 Net Income	$	102
Changes in Revenues:
Retail Revenues	(19)
Transmission Revenues	13
Other Revenues	7
Total Change in Revenues	1
Changes in Expenses and Other:
Other Operation and Maintenance	4
Depreciation and Amortization	4
Taxes Other Than Income Taxes	2
Allowance for Equity Funds Used During Construction	7
Interest Expense	7
Total Change in Expenses and Other	24
Income Tax Expense	(7)
2026 Net Income	$	120

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

•Retail Revenues decreased $19 million primarily due to the following:

•A $13 million decrease in weather-related usage primarily due to a 51% decrease in heating degree days.

•A $9 million decrease in rider revenues.

•Transmission Revenues increased $13 million primarily due to increased transmission investments.

•Other Revenues increased $7 million primarily due to the taxable portion of payments received from customers for large interconnection projects.

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

•Allowance for Equity Funds Used During Construction increased $7 million primarily due to a higher AFUDC base.

•Interest Expense decreased $7 million primarily due to the following:

•A $12 million decrease due to the deferral of eligible costs related to the UTM.

This decrease was partially offset by:

•A $6 million increase primarily due to higher long-term debt balances.

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

43

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
REVENUES
Electric Transmission and Distribution	$	513	$	520
Sales to AEP Affiliates	2		1
Other Revenues	9		2
TOTAL REVENUES	524		523
EXPENSES
Other Operation	162		166
Maintenance	24		24
Depreciation and Amortization	105		109
Taxes Other Than Income Taxes	45		47
TOTAL EXPENSES	336		346
OPERATING INCOME	188		177
Other Income (Expense):
Allowance for Equity Funds Used During Construction	19		12
Non-Service Cost Components of Net Periodic Benefit Cost	6		6
Interest Expense	(66)		(73)
INCOME BEFORE INCOME TAX EXPENSE	147		122
Income Tax Expense	27		20
NET INCOME	$	120	$	102
The common stock of AEP Texas is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

44

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
Net Income	$	120	$	102
OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 in 2026 and 2025, Respectively	—		(1)
TOTAL COMPREHENSIVE INCOME	$	120	$	101
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

45

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, 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
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
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

46

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2026 and December 31, 2025

(in millions)

(Unaudited)

	March 31,		December 31,
	2026		2025
CURRENT ASSETS
Restricted Cash (March 31, 2026 and December 31, 2025 Amounts Include $6 and $14, Respectively, Related to Restoration Funding)	$	6	$	14
Advances to Affiliates	112		7
Accounts Receivable:
Customers	268		189
Affiliated Companies	19		15
Accrued Unbilled Revenues	103		101
Total Accounts Receivable	390		305
Materials and Supplies	189		168
Prepayments and Other Current Assets	22		15
TOTAL CURRENT ASSETS	719		509
PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission	8,257		8,229
Distribution	7,010		6,835
Other Property, Plant and Equipment	1,257		1,239
Construction Work in Progress	2,045		1,766
Total Property, Plant and Equipment	18,569		18,069
Accumulated Depreciation and Amortization	2,241		2,205
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	16,328		15,864
OTHER NONCURRENT ASSETS
Regulatory Assets	441		402
Securitized Assets (March 31, 2026 and December 31, 2025 Amounts Include $88 and $94, Respectively, Related to Restoration Funding)	88		94
Operating Lease Assets	50		52
Deferred Charges and Other Noncurrent Assets	247		154
TOTAL OTHER NONCURRENT ASSETS	826		702
TOTAL ASSETS	$	17,873	$	17,075
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

47

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, 2026 and December 31, 2025

(in millions)

(Unaudited)

	March 31,		December 31,
	2026		2025
CURRENT LIABILITIES
Advances from Affiliates	$	—	$	188
Accounts Payable:
General	560		652
Affiliated Companies	31		60
Long-term Debt Due Within One Year – Nonaffiliated (March 31, 2026 and December 31, 2025 Amounts Include $25 and $25, Respectively, Related to Restoration Funding)	75		75
Accrued Taxes	162		118
Accrued Interest	120		64
Security Deposits	91		87
Contribution in Aid of Construction Advances	185		67
Obligations Under Operating Leases	14		14
Other Current Liabilities	77		93
TOTAL CURRENT LIABILITIES	1,315		1,418
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated (March 31, 2026 and December 31, 2025 Amounts Include $65 and $78, Respectively, Related to Restoration Funding)	7,669		6,941
Deferred Income Taxes	1,481		1,430
Regulatory Liabilities and Deferred Investment Tax Credits	1,260		1,286
Obligations Under Operating Leases	39		40
Deferred Credits and Other Noncurrent Liabilities	163		134
TOTAL NONCURRENT LIABILITIES	10,612		9,831
TOTAL LIABILITIES	11,927		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	3,403		3,283
Accumulated Other Comprehensive Income (Loss)	(3)		(3)
TOTAL COMMON SHAREHOLDER’S EQUITY	5,946		5,826
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	17,873	$	17,075
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

48

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	120	$	102
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	105		109
Deferred Income Taxes	44		13
Allowance for Equity Funds Used During Construction	(19)		(12)
Property Taxes	(100)		(95)
Change in Other Noncurrent Assets	(57)		(6)
Change in Other Noncurrent Liabilities	33		(1)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(35)		(10)
Materials and Supplies	(21)		14
Accounts Payable	47		(7)
Accrued Taxes, Net	44		48
Other Current Assets	(6)		2
Other Current Liabilities	36		24
Net Cash Flows from Operating Activities	191		181
INVESTING ACTIVITIES
Construction Expenditures	(761)		(450)
Change in Advances to Affiliates, Net	(105)		—
Contribution in Aid of Construction Advances	127		14
Other Investing Activities	—		(2)
Net Cash Flows Used for Investing Activities	(739)		(438)
FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated	741		400
Change in Advances from Affiliates, Net	(188)		(141)
Retirement of Long-term Debt – Nonaffiliated	(12)		(12)
Principal Payments for Finance Lease Obligations	(2)		(2)
Other Financing Activities	1		2
Net Cash Flows from Financing Activities	540		247
Net Decrease in Cash, Cash Equivalents and Restricted Cash	(8)		(10)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	14		24
Cash, Cash Equivalents and Restricted Cash at End of Period	$	6	$	14
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	7	$	25
Construction Expenditures Included in Current Liabilities as of March 31,	337		196
Contributions in Aid of Construction Advances Included in Current Assets as of March 31,	50		—
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

49

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 March 31,
	2026		2025
	(in millions)
Plant In Service	$	17,464	$	15,715
Construction Work in Progress	1,991		2,088
Accumulated Depreciation and Amortization	2,000		1,666
Total Transmission Property, Net	$	17,455	$	16,137

AEP Transmission Company, LLC and Subsidiaries
Reconciliation of 2025 to 2026
Earnings Attributable to AEP Member
(in millions)
	Three Months Ended  March 31,
2025 Earnings Attributable to AEP Member	$	211
Changes in Transmission Revenues:
Transmission Revenues	51
Total Change in Transmission Revenues	51
Changes in Expenses and Other:
Other Operation and Maintenance	(17)
Depreciation and Amortization	(14)
Taxes Other Than Income Taxes	(14)
Interest Income	2
Interest Expense	(10)
Total Change in Expenses and Other	(53)
Income Tax Expense	1
Net Income Attributable to Noncontrolling Interest	(27)
2026 Earnings Attributable to AEP Member	$	183

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

•Transmission Revenues increased $51 million primarily due to increased transmission investments.

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

•Other Operation and Maintenance expenses increased $17 million primarily due to an increase in employee-related costs, vegetation management expenses and other miscellaneous expenses.

•Depreciation and Amortization expenses increased $14 million primarily due to a higher depreciable base.

•Taxes Other than Income Taxes increased $14 million primarily due to higher property taxes driven by higher transmission investments.

•Interest Expense increased $10 million primarily due to higher long-term debt balances and interest rates.

•Net Income Attributable to Noncontrolling Interest increased $27 million due to the Midwest Transmission Holdings noncontrolling interest transaction that closed in June 2025.

50

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
REVENUES
Transmission Revenues	$	110	$	106
Sales to AEP Affiliates	470		430
Provision for Refund – Affiliated	(2)		(7)
Provision for Refund – Nonaffiliated	—		(2)
TOTAL REVENUES	578		527
EXPENSES
Other Operation	41		29
Maintenance	10		5
Depreciation and Amortization	128		114
Taxes Other Than Income Taxes	88		74
TOTAL EXPENSES	267		222
OPERATING INCOME	311		305
Other Income (Expense):
Interest Income – Affiliated	2		—
Allowance for Equity Funds Used During Construction	22		22
Interest Expense	(65)		(55)
INCOME BEFORE INCOME TAX EXPENSE	270		272
Income Tax Expense	60		61
NET INCOME	210		211
Net Income Attributable to Noncontrolling Interest	27		—
EARNINGS ATTRIBUTABLE TO AEP MEMBER	$	183	$	211
AEPTCo is wholly-owned by AEP Transmission Holdco.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

51

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY

For the Three Months Ended March 31, 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
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
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

52

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2026 and December 31, 2025

(in millions)

(Unaudited)

	March 31,		December 31,
	2026		2025
CURRENT ASSETS
Advances to Affiliates	$	372	$	71
Accounts Receivable:
Customers	76		94
Affiliated Companies	178		153
Miscellaneous	1		—
Total Accounts Receivable	255		247
Prepayments and Other Current Assets	8		4
TOTAL CURRENT ASSETS	635		322
TRANSMISSION PROPERTY
Transmission Property	16,885		16,542
Other Property, Plant and Equipment	579		571
Construction Work in Progress	1,991		2,005
Total Transmission Property	19,455		19,118
Accumulated Depreciation and Amortization	2,000		1,915
TOTAL TRANSMISSION PROPERTY – NET	17,455		17,203
OTHER NONCURRENT ASSETS
Regulatory Assets	78		73
Deferred Property Taxes	280		326
Deferred Charges and Other Noncurrent Assets	83		75
TOTAL OTHER NONCURRENT ASSETS	441		474
TOTAL ASSETS	$	18,531	$	17,999
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

53

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND MEMBER’S EQUITY

March 31, 2026 and December 31, 2025

(in millions)

(Unaudited)

	March 31,		December 31,
	2026		2025
CURRENT LIABILITIES
Advances from Affiliates	$	2	$	143
Accounts Payable:
General	416		477
Affiliated Companies	257		164
Long-term Debt Due Within One Year – Nonaffiliated	425		425
Accrued Taxes	579		650
Accrued Interest	72		46
Contribution in Aid of Construction Advances	134		32
Obligations Under Operating Leases	1		1
Other Current Liabilities	14		9
TOTAL CURRENT LIABILITIES	1,900		1,947
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	6,188		6,174
Deferred Income Taxes	1,508		1,481
Regulatory Liabilities	737		708
Obligations Under Operating Leases	1		2
Deferred Credits and Other Noncurrent Liabilities	48		44
TOTAL NONCURRENT LIABILITIES	8,482		8,409
TOTAL LIABILITIES	10,382		10,356
Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)
MEMBER’S EQUITY
Paid-in Capital	5,195		4,962
Retained Earnings	1,834		1,651
TOTAL MEMBER’S EQUITY	7,029		6,613
Noncontrolling Interest	1,120		1,030
TOTAL EQUITY	8,149		7,643
TOTAL LIABILITIES AND EQUITY	$	18,531	$	17,999
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

54

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	210	$	211
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	128		114
Deferred Income Taxes	23		33
Allowance for Equity Funds Used During Construction	(22)		(22)
Property Taxes	46		39
Change in Other Noncurrent Assets	(15)		(3)
Change in Other Noncurrent Liabilities	4		10
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(8)		(21)
Accounts Payable	104		(1)
Accrued Taxes, Net	(71)		(75)
Other Current Assets	(2)		—
Other Current Liabilities	30		11
Net Cash Flows from Operating Activities	427		296
INVESTING ACTIVITIES
Construction Expenditures	(403)		(422)
Change in Advances to Affiliates, Net	(301)		(30)
Contribution in Aid of Construction Advances	107		6
Other Investing Activities	2		9
Net Cash Flows Used for Investing Activities	(595)		(437)
FINANCING ACTIVITIES
Capital Contribution from AEP Member	233		32
Capital Contribution from Noncontrolling Interest	96		—
Issuance of Long-term Debt – Nonaffiliated	114		—
Retirement of Long-term Debt – Nonaffiliated	(101)		(50)
Change in Advances from Affiliates, Net	(141)		201
Dividends Paid to AEP Member	—		(42)
Dividends Paid to Noncontrolling Interest	(33)		—
Net Cash Flows from Financing Activities	168		141
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	$	37	$	33
Construction Expenditures Included in Current Liabilities as of March 31,	270		230
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

55

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 March 31,
	2026	2025
	(in millions of KWhs)
Retail:
Residential	3,621	3,654
Commercial	1,498	1,500
Industrial	2,000	2,076
Miscellaneous	208	211
Total Retail	7,327	7,441
Wholesale (a)	451	727
Total KWhs	7,778	8,168

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

Summary of Heating and Cooling Degree Days

	Three Months Ended March 31,
	2026	2025
	(in degree days)
Actual – Heating	1,334	1,364
Normal – Heating	1,281	1,279
Actual – Cooling	25	11
Normal – Cooling	6	6

56

Appalachian Power Company and Subsidiaries
Reconciliation of 2025 to 2026
Net Income
(in millions)
	Three Months Ended  March 31,
2025 Net Income	$	165
Changes in Revenues:
Retail Revenues	(16)
Transmission Revenues	14
Other Revenues	(4)
Total Change in Revenues	(6)
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	43
Other Operation and Maintenance	(16)
Depreciation and Amortization	(5)
Taxes Other Than Income Taxes	(6)
Non-Service Cost Components of Net Periodic Benefit Cost	(1)
Interest Expense	(8)
Total Change in Expenses and Other	7
Income Tax Expense	29
2026 Net Income	$	195

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

•Retail Revenues decreased $16 million primarily due to the following:

•A $55 million decrease in fuel revenues.

This decrease was partially offset by:

•A $25 million increase in base rate and rider revenues.

•A $10 million increase in weather-normalized margins primarily driven by the commercial and industrial classes.

•Transmission Revenues increased $14 million primarily due to continued transmission investment.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $43 million primarily due to an increase in under-recovered deferred fuel regulatory assets primarily driven by lower authorized fuel rates in Virginia.

•Other Operation and Maintenance expenses increased $16 million primarily due to the following:

•A $14 million increase in transmission expenses primarily due to increases in vegetation management, storm restoration expenses and recoverable PJM expenses.

•A $12 million increase in distribution expenses primarily due to an increase in storm-related expenses and vegetation management costs.

•A $7 million increase in administrative and general expenses primarily due to employee-related costs.

•A $3 million increase in steam generation expenses primarily due to increased plant maintenance.

These increases were partially offset by:

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

57

•Depreciation and Amortization expenses increased $5 million primarily due to the following:

•A $27 million increase 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.

This increase was partially offset by:

•A $24 million decrease due to an April 2026 order approving a final true-up to recover past MRBC costs that were not reflected in MRBC surcharge rates in a timely manner.

•Taxes Other Than Income Taxes increased $6 million primarily due to higher business and occupation taxes.

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

•Income Tax Expense decreased $29 million primarily due to the following:

•A $21 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.

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

•A $5 million decrease due to an increase in amortization of Excess ADIT.

58

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
REVENUES
Electric Generation, Transmission and Distribution	$	1,071	$	1,098
Sales to AEP Affiliates	92		72
Other Revenues	4		3
TOTAL REVENUES	1,167		1,173
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	364		407
Other Operation	217		222
Maintenance	99		78
Depreciation and Amortization	168		163
Taxes Other Than Income Taxes	47		41
TOTAL EXPENSES	895		911
OPERATING INCOME	272		262
Other Income (Expense):
Interest Income	1		1
Allowance for Equity Funds Used During Construction	4		4
Non-Service Cost Components of Net Periodic Benefit Cost	4		5
Interest Expense	(75)		(67)
INCOME BEFORE INCOME TAX EXPENSE	206		205
Income Tax Expense	11		40
NET INCOME	$	195	$	165
The common stock of APCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

59

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
Net Income	$	195	$	165
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 in 2026 and 2025, Respectively	—		—
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 in 2026 and 2025, Respectively	—		—
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	—		—
TOTAL COMPREHENSIVE INCOME	$	195	$	165
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

60

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, 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
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
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

61

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2026 and December 31, 2025

(in millions)

(Unaudited)

	March 31,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	4	$	5
Restricted Cash for Securitized Funding	12		18
Advances to Affiliates	17		17
Accounts Receivable:
Customers	205		171
Affiliated Companies	236		142
Accrued Unbilled Revenues	90		112
Allowance for Credit Losses	(5)		(2)
Total Accounts Receivable	526		423
Fuel	229		229
Materials and Supplies	152		139
Risk Management Assets	22		81
Regulatory Asset for Under-Recovered Fuel Costs	194		83
Prepayments and Other Current Assets	59		38
TOTAL CURRENT ASSETS	1,215		1,033
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	7,906		7,886
Transmission	5,298		5,277
Distribution	5,998		5,938
Other Property, Plant and Equipment	1,207		1,175
Construction Work in Progress	820		802
Total Property, Plant and Equipment	21,229		21,078
Accumulated Depreciation and Amortization	6,424		6,365
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	14,805		14,713
OTHER NONCURRENT ASSETS
Regulatory Assets	1,504		1,439
Securitized Assets	71		78
Employee Benefits and Pension Assets	254		251
Operating Lease Assets	92		95
Deferred Charges and Other Noncurrent Assets	200		183
TOTAL OTHER NONCURRENT ASSETS	2,121		2,046
TOTAL ASSETS	$	18,141	$	17,792
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

62

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, 2026 and December 31, 2025

(Unaudited)

	March 31,		December 31,
	2026		2025
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	177	$	209
Accounts Payable:
General	376		375
Affiliated Companies	190		173
Long-term Debt Due Within One Year – Nonaffiliated	1,132		1,131
Customer Deposits	99		94
Accrued Taxes	125		116
Obligations Under Operating Leases	14		15
Other Current Liabilities	298		271
TOTAL CURRENT LIABILITIES	2,411		2,384
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	5,115		5,128
Deferred Income Taxes	2,216		2,130
Regulatory Liabilities and Deferred Investment Tax Credits	1,072		1,111
Asset Retirement Obligations	726		707
Employee Benefits and Pension Obligations	26		26
Obligations Under Operating Leases	79		81
Deferred Credits and Other Noncurrent Liabilities	40		45
TOTAL NONCURRENT LIABILITIES	9,274		9,228
TOTAL LIABILITIES	11,685		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	4,134		3,939
Accumulated Other Comprehensive Income (Loss)	24		24
TOTAL COMMON SHAREHOLDER’S EQUITY	6,456		6,180
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	18,141	$	17,792
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

63

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	195	$	165
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	168		163
Deferred Income Taxes	49		20
Allowance for Equity Funds Used During Construction	(4)		(4)
Mark-to-Market of Risk Management Contracts	64		6
Deferred Fuel Over/Under-Recovery, Net	(106)		2
Change in Regulatory Assets	(62)		(86)
Change in Other Noncurrent Assets	(48)		(24)
Change in Other Noncurrent Liabilities	(14)		38
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(94)		29
Fuel, Materials and Supplies	(13)		43
Accounts Payable	24		(29)
Accrued Taxes, Net	5		24
Other Current Assets	(11)		(4)
Other Current Liabilities	14		10
Net Cash Flows from Operating Activities	167		353
INVESTING ACTIVITIES
Construction Expenditures	(236)		(262)
Change in Advances to Affiliates, Net	—		(1)
Other Investing Activities	29		2
Net Cash Flows Used for Investing Activities	(207)		(261)
FINANCING ACTIVITIES
Capital Contribution from Parent	81		—
Change in Advances from Affiliates, Net	(32)		(28)
Retirement of Long-term Debt – Nonaffiliated	(15)		(14)
Principal Payments for Finance Lease Obligations	(1)		(2)
Dividends Paid on Common Stock	—		(50)
Other Financing Activities	—		1
Net Cash Flows from (Used for) Financing Activities	33		(93)
Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding	(7)		(1)
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	$	16	$	19
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	42	$	35
Noncash Acquisitions Under Finance Leases	2		2
Construction Expenditures Included in Current Liabilities as of March 31,	126		139
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

64

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 March 31,
	2026	2025
	(in millions of KWhs)
Retail:
Residential	1,508	1,553
Commercial	2,181	1,272
Industrial	1,727	1,748
Miscellaneous	12	13
Total Retail	5,428	4,586
Wholesale (a)	1,667	2,436
Total KWhs	7,095	7,022

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

Summary of Heating and Cooling Degree Days

	Three Months Ended March 31,
	2026	2025
	(in degree days)
Actual – Heating	2,059	2,118
Normal – Heating	2,121	2,128
Actual – Cooling	1	—
Normal – Cooling	1	1

65

Indiana Michigan Power Company and Subsidiaries
Reconciliation of 2025 to 2026
Net Income
(in millions)
	Three Months Ended  March 31,
2025 Net Income	$	58
Changes in Revenues:
Retail Revenues	128
Off-system Sales	82
Transmission Revenues	3
Other Revenues	(3)
Total Change in Revenues	210
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(56)
Purchased Electricity from AEP Affiliates	(1)
Other Operation and Maintenance	(33)
Depreciation and Amortization	(7)
Taxes Other Than Income Taxes	2
Other Income	3
Non-Service Cost Components of Net Periodic Benefit Cost	(1)
Interest Expense	(8)
Total Change in Expenses and Other	(101)
Income Tax Expense	(19)
2026 Net Income	$	148

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

•Retail Revenues increased $128 million primarily due to the following:

•A $55 million increase in weather-normalized revenues primarily in the commercial class.

•A $47 million increase in rider revenues.

•An $18 million increase in fuel revenues.

•A $9 million increase due to a decrease in regulatory provisions for refund.

•Off-system Sales increased $82 million primarily due to Rockport Plant, Unit 2 merchant sales during Winter Storm Fern in January 2026, partially offset by economic hedging activity.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $56 million primarily due to an increase in recoverable fuel and purchased power costs and an increase in Rockport Plant, Unit 2, merchant generation fuel costs.

•Other Operation and Maintenance expenses increased $33 million primarily due to the following:

•An $11 million increase in distribution expenses primarily due to an increase in vegetation management costs and other distribution-related expenses.

•An $11 million increase in transmission expenses primarily due to an increase in recoverable PJM expenses.

•A $5 million increase in nuclear expenses at Cook Plant.

•A $4 million increase in demand side management expenses.

These increases were partially offset by:

•A $7 million decrease due to an increased Nuclear Electric Insurance Limited distribution.

66

•Depreciation and Amortization increased $7 million primarily due to the following:

•A $5 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.

•A $2 million increase due to a higher depreciable base.

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

•Income Tax Expense increased $19 million primarily due to the following:

•A $23 million increase due to an increase in pretax book income.

This increase was partially offset by:

•A $6 million decrease due to an increase in PTCs.

67

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
REVENUES
Electric Generation, Transmission and Distribution	$	961	$	759
Sales to AEP Affiliates	5		4
Provision for Refund – Affiliated	—		(1)
Provision for Refund – Nonaffiliated	(48)		(58)
Other Revenues – Affiliated	14		16
Other Revenues – Nonaffiliated	1		3
TOTAL REVENUES	933		723
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	232		176
Purchased Electricity from AEP Affiliates	77		76
Other Operation	188		171
Maintenance	76		60
Depreciation and Amortization	131		124
Taxes Other Than Income Taxes	24		26
TOTAL EXPENSES	728		633
OPERATING INCOME	205		90
Other Income (Expense):
Other Income	8		5
Non-Service Cost Components of Net Periodic Benefit Cost	4		5
Interest Expense	(43)		(35)
INCOME BEFORE INCOME TAX EXPENSE	174		65
Income Tax Expense	26		7
NET INCOME	$	148	$	58
The common stock of I&M is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

68

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
Net Income	$	148	$	58
OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 in 2026 and 2025, Respectively	—		—
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 in 2026 and 2025, Respectively	—		—
TOTAL OTHER COMPREHENSIVE INCOME	—		—
TOTAL COMPREHENSIVE INCOME	$	148	$	58
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

69

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, 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
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
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

70

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2026 and December 31, 2025

(in millions)

(Unaudited)

	March 31,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	2	$	2
Advances to Affiliates	—		192
Accounts Receivable:
Customers	127		103
Affiliated Companies	141		90
Accrued Unbilled Revenues	—		17
Miscellaneous	13		2
Total Accounts Receivable	281		212
Fuel	56		61
Materials and Supplies	229		222
Risk Management Assets	3		10
Accrued Tax Benefits	67		32
Prepayments and Other Current Assets	92		53
TOTAL CURRENT ASSETS	730		784
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	6,277		5,483
Transmission	2,070		2,055
Distribution	3,874		3,823
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	1,353		1,058
Construction Work in Progress	464		403
Total Property, Plant and Equipment	14,038		12,822
Accumulated Depreciation, Depletion and Amortization	5,123		4,878
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	8,915		7,944
OTHER NONCURRENT ASSETS
Regulatory Assets	553		585
Spent Nuclear Fuel and Decommissioning Trusts	4,803		4,916
Operating Lease Assets	48		52
Deferred Charges and Other Noncurrent Assets	356		344
TOTAL OTHER NONCURRENT ASSETS	5,760		5,897
TOTAL ASSETS	$	15,405	$	14,625
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

71

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, 2026 and December 31, 2025

(dollars in millions)

(Unaudited)

	March 31,		December 31,
	2026		2025
CURRENT LIABILITIES
Advances from Affiliates	$	9	$	—
Accounts Payable:
General	237		232
Affiliated Companies	120		125
Long-term Debt Due Within One Year – Nonaffiliated    (March 31, 2026 and December 31, 2025 Amounts Include $108 and $117,    Respectively, Related to DCC Fuel)	108		117
Customer Deposits	55		55
Accrued Taxes	159		112
Accrued Interest	43		42
Obligations Under Operating Leases	16		17
Regulatory Liability for Over-Recovered Fuel Costs	49		19
Other Current Liabilities	216		230
TOTAL CURRENT LIABILITIES	1,012		949
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	4,066		3,444
Deferred Income Taxes	1,222		1,219
Regulatory Liabilities and Deferred Investment Tax Credits	2,869		2,938
Asset Retirement Obligations	2,186		2,165
Obligations Under Operating Leases	34		37
Deferred Credits and Other Noncurrent Liabilities	84		89
TOTAL NONCURRENT LIABILITIES	10,461		9,892
TOTAL LIABILITIES	11,473		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	1,033		1,033
Retained Earnings	2,840		2,692
Accumulated Other Comprehensive Income (Loss)	2		2
TOTAL COMMON SHAREHOLDER’S EQUITY	3,932		3,784
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	15,405	$	14,625
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

72

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	148	$	58
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	131		124
Deferred Income Taxes	—		(13)
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net	19		(14)
Allowance for Equity Funds Used During Construction	(6)		(4)
Mark-to-Market of Risk Management Contracts	7		17
Amortization of Nuclear Fuel	32		26
Deferred Fuel Over/Under-Recovery, Net	30		8
Change in Other Noncurrent Assets	(15)		(20)
Change in Other Noncurrent Liabilities	79		65
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(60)		5
Fuel, Materials and Supplies	2		21
Accounts Payable	(7)		39
Accrued Taxes, Net	12		23
Other Current Assets	(1)		7
Other Current Liabilities	(11)		(17)
Net Cash Flows from Operating Activities	360		325
INVESTING ACTIVITIES
Construction Expenditures	(167)		(159)
Change in Advances to Affiliates, Net	192		—
Purchases of Investment Securities	(573)		(601)
Sales of Investment Securities	548		577
Acquisitions of Generation Facilities	(965)		—
Acquisitions of Nuclear Fuel	(13)		(36)
Other Investing Activities	1		18
Net Cash Flows Used for Investing Activities	(977)		(201)
FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated	640		—
Change in Advances from Affiliates, Net	9		(43)
Retirement of Long-term Debt – Nonaffiliated	(31)		(27)
Principal Payments for Finance Lease Obligations	(1)		(2)
Dividends Paid on Common Stock	—		(50)
Net Cash Flows from (Used for) Financing Activities	617		(122)
Net Increase in Cash and Cash Equivalents	—		2
Cash and Cash Equivalents at Beginning of Period	2		2
Cash and Cash Equivalents at End of Period	$	2	$	4
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	40	$	38
Noncash Acquisitions Under Finance Leases	1		1
Construction Expenditures Included in Current Liabilities as of March 31,	94		62
Acquisition of Nuclear Fuel Included in Current Liabilities as of March 31,	9		—
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

73

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 March 31,
	2026	2025
	(in millions of KWhs)
Retail:
Residential	4,001	4,095
Commercial	7,719	5,489
Industrial	3,378	3,386
Miscellaneous	28	28
Total Retail (a)	15,126	12,998
Wholesale (b)	643	667
Total KWhs	15,769	13,665

(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 March 31,
		2026	2025
	(in degree days)
Actual – Heating		1,864	1,907
Normal – Heating		1,819	1,820
Actual – Cooling		12	6
Normal – Cooling		3	2

74

Ohio Power Company and Subsidiaries
Reconciliation of 2025 to 2026
Net Income
(in millions)
	Three Months Ended  March 31,
2025 Net Income	$	63
Changes in Revenues:
Retail Revenues	52
Off-system Sales	25
Transmission Revenues	7
Other Revenues	(3)
Total Change in Revenues	81
Changes in Expenses and Other:
Purchased Electricity for Resale	(4)
Purchased Electricity from AEP Affiliates	(4)
Other Operation and Maintenance	(8)
Depreciation and Amortization	(17)
Taxes Other Than Income Taxes	3
Other Income	(1)
Non-Service Cost Components of Net Periodic Benefit Cost	5
Interest Expense	(2)
Total Change in Expenses and Other	(28)
Income Tax Expense	2
Equity Earnings of Unconsolidated Subsidiaries	(1)
2026 Net Income	$	117

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

•Retail Revenues increased $52 million primarily due to the following:

•A $51 million increase due to higher prices for purchased power to serve OPCo’s SSO customers.

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

These increases were partially offset by:

•A $15 million decrease in weather-related usage driven by a 2% decrease in heating degree days.

•Off-system Sales increased $25 million primarily due to increased sales of OVEC purchased power driven by higher market prices.

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

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

•Purchased Electricity for Resale increased $4 million primarily due to the following:

•A $51 million increase in recoverable auction purchases to serve SSO customers.

This increase was partially offset by:

•A $35 million decrease due to the prior year reduction in regulatory assets for OVEC-related purchased power costs that were no longer probable of recovery due to approved legislation in Ohio in May 2025.

•A $9 million decrease due to the elimination of an OVEC-related regulatory mechanism in August 2025 as a result of approved legislation in Ohio in May 2025.

•A $5 million decrease in OVEC purchased power costs.

75

•Other Operation and Maintenance expenses increased $8 million primarily due to the following:

•A $10 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.

•An $8 million increase in distribution expenses primarily due to recoverable vegetation management expenses.

These increases were partially offset by:

•A $10 million decrease in transmission expenses primarily due to a $21 million decrease in recoverable PJM expenses, partially offset by a $9 million increase in recoverable storm restoration costs and vegetation management expenses.

•Depreciation and Amortization expenses increased $17 million primarily due to the deferral of income tax benefit from Excess ADIT credits to be refunded to customers as approved in the 2025 base rate case.

•Non-Service Cost Components of Net Periodic Benefit Cost expenses decreased $5 million primarily due to the deferral of pension settlement expense approved in the 2025 base rate case.

•Income Tax Expense decreased $2 million primarily due to the following:

•A $12 million decrease from Excess ADIT credits to be 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.

76

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
REVENUES
Electricity, Transmission and Distribution	$	1,069	$	990
Sales to AEP Affiliates	13		10
Other Revenues	3		4
TOTAL REVENUES	1,085		1,004
EXPENSES
Purchased Electricity for Resale	251		247
Purchased Electricity from AEP Affiliates	20		16
Other Operation	323		334
Maintenance	71		52
Depreciation and Amortization	111		94
Taxes Other Than Income Taxes	156		159
TOTAL EXPENSES	932		902
OPERATING INCOME	153		102
Other Income (Expense):
Other Income	—		1
Allowance for Equity Funds Used During Construction	7		7
Non-Service Cost Components of Net Periodic Benefit Cost	9		4
Interest Expense	(40)		(38)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	129		76
Income Tax Expense	12		14
Equity Earnings of Unconsolidated Subsidiaries	—		1
NET INCOME	$	117	$	63
The common stock of OPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

77

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, 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
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
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

78

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2026 and December 31, 2025

(in millions)

(Unaudited)

	March 31,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	5	$	5
Accounts Receivable:
Customers	121		109
Affiliated Companies	194		132
Accrued Unbilled Revenues	—		29
Total Accounts Receivable	315		270
Materials and Supplies	193		191
Prepayments and Other Current Assets	22		25
TOTAL CURRENT ASSETS	535		491
PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission	3,961		3,916
Distribution	7,760		7,661
Other Property, Plant and Equipment	1,300		1,289
Construction Work in Progress	853		811
Total Property, Plant and Equipment	13,874		13,677
Accumulated Depreciation and Amortization	3,010		2,993
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	10,864		10,684
OTHER NONCURRENT ASSETS
Regulatory Assets	384		326
Operating Lease Assets	47		50
Deferred Charges and Other Noncurrent Assets	560		659
TOTAL OTHER NONCURRENT ASSETS	991		1,035
TOTAL ASSETS	$	12,390	$	12,210
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

79

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, 2026 and December 31, 2025

(dollars in millions)

(Unaudited)

	March 31,		December 31,
	2026		2025
CURRENT LIABILITIES
Advances from Affiliates	$	139	$	79
Accounts Payable:
General	376		391
Affiliated Companies	208		197
Risk Management Liabilities	4		5
Customer Deposits	116		108
Accrued Taxes	664		858
Obligations Under Operating Leases	13		13
Other Current Liabilities	214		239
TOTAL CURRENT LIABILITIES	1,734		1,890
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	3,719		3,718
Long-term Risk Management Liabilities	28		28
Deferred Income Taxes	1,336		1,268
Regulatory Liabilities and Deferred Investment Tax Credits	906		893
Obligations Under Operating Leases	34		37
Deferred Credits and Other Noncurrent Liabilities	326		225
TOTAL NONCURRENT LIABILITIES	6,349		6,169
TOTAL LIABILITIES	8,083		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	1,069		1,030
Retained Earnings	2,917		2,800
TOTAL COMMON SHAREHOLDER’S EQUITY	4,307		4,151
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	12,390	$	12,210
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

80

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	117	$	63
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	111		94
Deferred Income Taxes	49		1
Allowance for Equity Funds Used During Construction	(7)		(7)
Mark-to-Market of Risk Management Contracts	(1)		4
Property Taxes	106		101
Security Deposits	96		35
Change in Regulatory Assets	(58)		24
Change in Other Noncurrent Assets	(26)		26
Change in Other Noncurrent Liabilities	24		(32)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(45)		31
Materials and Supplies	(2)		7
Accounts Payable	27		(17)
Customer Deposits	8		17
Accrued Taxes, Net	(190)		(169)
Other Current Assets	—		5
Other Current Liabilities	(20)		(17)
Net Cash Flows from Operating Activities	189		166
INVESTING ACTIVITIES
Construction Expenditures	(300)		(254)
Change in Advances to Affiliates, Net	—		115
Other Investing Activities	13		15
Net Cash Flows Used for Investing Activities	(287)		(124)
FINANCING ACTIVITIES
Capital Contribution from Parent	39		—
Change in Advances from Affiliates, Net	60		10
Principal Payments for Finance Lease Obligations	(1)		(1)
Dividends Paid on Common Stock	—		(46)
Net Cash Flows from (Used for) Financing Activities	98		(37)
Net Increase in Cash and Cash Equivalents	—		5
Cash and Cash Equivalents at Beginning of Period	5		5
Cash and Cash Equivalents at End of Period	$	5	$	10
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	17	$	17
Noncash Acquisitions Under Finance Leases	—		1
Construction Expenditures Included in Current Liabilities as of March 31,	106		140
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

81

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 March 31,
	2026	2025
	(in millions of KWhs)
Retail:
Residential	1,364	1,592
Commercial	1,347	1,321
Industrial	1,411	1,377
Miscellaneous	284	279
Total Retail	4,406	4,569
Wholesale (a)	37	57
Total KWhs	4,443	4,626

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

Summary of Heating and Cooling Degree Days

	Three Months Ended March 31,
	2026	2025
	(in degree days)
Actual – Heating	760	1,162
Normal – Heating	1,049	1,038
Actual – Cooling	94	24
Normal – Cooling	21	20

82

Public Service Company of Oklahoma
Reconciliation of 2025 to 2026
Net Income
(in millions)
	Three Months Ended  March 31,
2025 Net Income	$	28
Changes in Revenues:
Retail Revenues (a)	44
Other Revenues	1
Total Change in Revenues	45
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(35)
Other Operation and Maintenance	(37)
Depreciation and Amortization	(4)
Taxes Other Than Income Taxes	(5)
Interest Income	(2)
Interest Expense	(13)
Total Change in Expenses and Other	(96)
Income Tax Benefit	38
2026 Net Income	$	15

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

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

•Retail Revenues increased $44 million primarily due to the following:

•A $62 million increase in rider revenues.

This increase was partially offset by:

•An $8 million decrease in weather-normalized revenues primarily in the residential class partially offset by an increase in the industrial class.

•A $6 million decrease in weather-related usage primarily due to a 35% decrease in heating degree days.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $35 million primarily due to increased recoverable PTCs.

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

•A $20 million increase in transmission expenses primarily due to SPP expenses.

•A $10 million increase in generation expenses primarily due to acquisitions of generation facilities.

•A $5 million increase in distribution expenses primarily due to overhead line maintenance.

•Depreciation and Amortization expenses increased $4 million primarily due to the following:

•A $16 million increase due to a higher depreciable base.

This increase was partially offset by:

•An $11 million decrease primarily due to higher under-recovery of costs and allowable return associated with the renewable rider.

•Taxes Other Than Income Taxes increased $5 million primarily due to property taxes on acquired generation facilities.

•Interest Expense increased $13 million primarily due to higher long-term debt balances.

•Income Tax Benefit increased $38 million primarily due to the following:

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

•An $11 million increase due to a decrease in pretax book income.

83

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
REVENUES
Electric Generation, Transmission and Distribution	$	434	$	390
Sales to AEP Affiliates	4		1
Other Revenues	1		3
TOTAL REVENUES	439		394
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	164		129
Other Operation	127		101
Maintenance	39		28
Depreciation and Amortization	73		69
Taxes Other Than Income Taxes	23		18
TOTAL EXPENSES	426		345
OPERATING INCOME	13		49
Other Income (Expense):
Interest Income	—		2
Allowance for Equity Funds Used During Construction	3		3
Non-Service Cost Components of Net Periodic Benefit Cost	2		2
Interest Expense	(43)		(30)
INCOME (LOSS) BEFORE INCOME TAX EXPENSE (BENEFIT)	(25)		26
Income Tax Expense (Benefit)	(40)		(2)
NET INCOME	$	15	$	28
The common stock of PSO is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

84

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
Net Income	$	15	$	28
OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 in 2026 and 2025, Respectively	—		(1)
TOTAL COMPREHENSIVE INCOME	$	15	$	27
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

85

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Three Months Ended March 31, 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
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
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

86

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED BALANCE SHEETS

ASSETS

March 31, 2026 and December 31, 2025

(in millions)

(Unaudited)

	March 31,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	2	$	2
Accounts Receivable:
Customers	115		109
Affiliated Companies	84		45
Miscellaneous	5		4
Total Accounts Receivable	204		158
Fuel	3		3
Materials and Supplies	125		119
Risk Management Assets	21		42
Accrued Tax Benefits	79		8
Regulatory Asset for Under-Recovered Fuel Costs	58		37
Prepayments and Other Current Assets	17		14
TOTAL CURRENT ASSETS	509		383
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	4,093		4,365
Transmission	1,490		1,433
Distribution	4,059		3,987
Other Property, Plant and Equipment	1,290		1,292
Construction Work in Progress	682		635
Total Property, Plant and Equipment	11,614		11,712
Accumulated Depreciation and Amortization	2,455		2,748
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	9,159		8,964
OTHER NONCURRENT ASSETS
Regulatory Assets	676		637
Employee Benefits and Pension Assets	95		95
Operating Lease Assets	124		126
Deferred Charges and Other Noncurrent Assets	72		13
TOTAL OTHER NONCURRENT ASSETS	967		871
TOTAL ASSETS	$	10,635	$	10,218
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

87

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

March 31, 2026 and December 31, 2025

(Unaudited)

	March 31,		December 31,
	2026		2025
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	487	$	171
Accounts Payable:
General	263		339
Affiliated Companies	101		87
Long-term Debt Due Within One Year – Nonaffiliated	51		51
Risk Management Liabilities	30		27
Customer Deposits	116		115
Accrued Taxes	88		37
Accrued Interest	37		67
Obligations Under Operating Leases	12		11
Other Current Liabilities	78		104
TOTAL CURRENT LIABILITIES	1,263		1,009
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	3,475		3,475
Deferred Income Taxes	1,124		1,113
Regulatory Liabilities and Deferred Investment Tax Credits	717		717
Asset Retirement Obligations	148		136
Obligations Under Operating Leases	120		122
Deferred Credits and Other Noncurrent Liabilities	160		33
TOTAL NONCURRENT LIABILITIES	5,744		5,596
TOTAL LIABILITIES	7,007		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	1,718		1,718
Retained Earnings	1,751		1,736
Accumulated Other Comprehensive Income (Loss)	2		2
TOTAL COMMON SHAREHOLDER’S EQUITY	3,628		3,613
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	10,635	$	10,218
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

88

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONDENSED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	15	$	28
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	73		69
Deferred Income Taxes	6		40
Allowance for Equity Funds Used During Construction	(3)		(3)
Mark-to-Market of Risk Management Contracts	28		(17)
Property Taxes	(58)		(45)
Deferred Fuel Over/Under-Recovery, Net	(21)		(76)
Change in Other Noncurrent Assets	(17)		(9)
Change in Other Noncurrent Liabilities	138		19
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(46)		2
Fuel, Materials and Supplies	(6)		5
Accounts Payable	(13)		(10)
Accrued Taxes, Net	(20)		(1)
Other Current Assets	(3)		(2)
Other Current Liabilities	(58)		(30)
Net Cash Flows from (Used for) Operating Activities	15		(30)
INVESTING ACTIVITIES
Construction Expenditures	(331)		(168)
Change in Advances to Affiliates, Net	—		232
Other Investing Activities	1		1
Net Cash Flows from (Used for) Investing Activities	(330)		65
FINANCING ACTIVITIES
Change in Advances from Affiliates, Net	316		91
Retirement of Long-term Debt – Nonaffiliated	—		(125)
Principal Payments for Finance Lease Obligations	(1)		(1)
Other Financing Activities	—		1
Net Cash Flows from (Used for) Financing Activities	315		(34)
Net Increase in Cash and Cash Equivalents	—		1
Cash and Cash Equivalents at Beginning of Period	2		2
Cash and Cash Equivalents at End of Period	$	2	$	3
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	69	$	34
Noncash Acquisitions Under Finance Leases	1		1
Construction Expenditures Included in Current Liabilities as of March 31,	131		73
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

89

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 March 31,
	2026	2025
	(in millions of KWhs)
Retail:
Residential	1,431	1,603
Commercial	1,272	1,245
Industrial	1,225	1,181
Miscellaneous	16	16
Total Retail	3,944	4,045
Wholesale (a)	1,275	1,492
Total KWhs	5,219	5,537

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

Summary of Heating and Cooling Degree Days

	Three Months Ended March 31,
	2026	2025
	(in degree days)
Actual – Heating	494	717
Normal – Heating	696	690
Actual – Cooling	150	96
Normal – Cooling	50	46

90

Southwestern Electric Power Company Consolidated
Reconciliation of 2025 to 2026
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
	Three Months Ended  March 31,
2025 Earnings Attributable to Common Shareholder	$	48
Changes in Revenues:
Retail Revenues (a)	21
Transmission Revenues	19
Total Change in Revenues	40
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	20
Other Operation and Maintenance	(32)
Asset Impairments and Other Related Charges	(31)
Depreciation and Amortization	(23)
Taxes Other Than Income Taxes	(2)
Allowance for Equity Funds Used During Construction	5
Non-Service Cost Components of Net Periodic Benefit Cost	(1)
Interest Expense	(11)
Total Change in Expenses and Other	(75)
Income Tax Benefit	43
2026 Earnings Attributable to Common Shareholder	$	56

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

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

•Retail Revenues increased $21 million primarily due to the following:

•A $36 million increase in Arkansas base case and rider revenues.

•A $19 million increase in weather-normalized revenues primarily in the commercial and industrial classes.

These increases were partially offset by:

•A $26 million decrease in fuel revenue primarily due to the refund of the Texas over-recovered fuel balance.

•A $10 million decrease in weather-related usage primarily due to a 31% decrease in heating degree days.

•Transmission Revenues increased $19 million primarily due to a $12 million increase in continued transmission investment and a $5 million increase in transmission reservation revenue.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $20 million primarily due to the following:

•A $31 million decrease in fuel revenues primarily due to the amortization of a Texas fuel regulatory liability as a result of the refund of previously over-recovered fuel balances and lower authorized rates in Arkansas.

•A $6 million decrease due to a prior year Texas fuel disallowance.

These decreases were partially offset by:

•A $15 million increase in non-recoverable fuel costs primarily in Louisiana.

•An $8 million increase in recoverable PTCs.

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

•A $13 million increase in transmission expenses primarily due to SPP expenses.

•A $7 million increase in distribution expenses primarily due to overhead line maintenance.

•A $5 million increase in renewable generation operation and maintenance expenses.

91

•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 $23 million primarily due to the following:

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

•A $7 million increase primarily due to higher over-recovery of costs and allowable return associated with the renewable rider inclusive of $29 million of higher PTCs.

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

•Interest Expense increased $11 million primarily due to higher long-term debt balances.

•Income Tax Benefit increased $43 million primarily due to the following:

•A $32 million increase due to an increase in PTCs.

•A $7 million increase due to a decrease in pretax book income.

92

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
REVENUES
Electric Generation, Transmission and Distribution	$	548	$	517
Sales to AEP Affiliates	22		11
Other Revenues	1		3
TOTAL REVENUES	571		531
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	171		191
Other Operation	118		97
Maintenance	46		35
Asset Impairments and Other Related Charges	31		—
Depreciation and Amortization	121		98
Taxes Other Than Income Taxes	37		35
TOTAL EXPENSES	524		456
OPERATING INCOME	47		75
Other Income (Expense):
Interest Income	2		2
Allowance for Equity Funds Used During Construction	8		3
Non-Service Cost Components of Net Periodic Benefit Cost	1		2
Interest Expense	(50)		(39)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	8		43
Income Tax Expense (Benefit)	(49)		(6)
NET INCOME	57		49
Net Income Attributable to Noncontrolling Interest	1		1
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	56	$	48
The common stock of SWEPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

93

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
Net Income	$	57	$	49
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 in 2026 and 2025, Respectively	—		—
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 in 2026 and 2025, Respectively	—		—
TOTAL COMPREHENSIVE INCOME	57		49
Total Comprehensive Income Attributable to Noncontrolling Interest	1		1
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER	$	56	$	48
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

94

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Three Months Ended March 31, 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
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

See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

95

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2026 and December 31, 2025

(in millions)

(Unaudited)

	March 31,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	2	$	2
Restricted Cash (March 31, 2026 and December 31, 2025 Amounts Include $7 and $15, Respectively, Related to Storm Recovery Funding)	7		15
Advances to Affiliates	—		23
Accounts Receivable:
Customers	72		63
Affiliated Companies	133		91
Miscellaneous	6		10
Total Accounts Receivable	211		164
Fuel	97		83
Materials and Supplies (March 31, 2026 and December 31, 2025 Amounts Include $1 and $1, Respectively, Related to Sabine)	93		88
Risk Management Assets	15		35
Accrued Tax Benefits	93		17
Regulatory Asset for Under-Recovered Fuel Costs	114		115
Prepayments and Other Current Assets	23		14
TOTAL CURRENT ASSETS	655		556
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	6,634		6,621
Transmission	3,328		3,302
Distribution	3,304		3,242
Other Property, Plant and Equipment (March 31, 2026 and December 31, 2025 Amounts Include $101 and $125, Respectively, Related to Sabine)	930		942
Construction Work in Progress	888		712
Total Property, Plant and Equipment	15,084		14,819
Accumulated Depreciation and Amortization (March 31, 2026 and December 31, 2025 Amounts Include $101 and $125, Respectively, Related to Sabine)	3,534		3,478
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	11,550		11,341
OTHER NONCURRENT ASSETS
Regulatory Assets	929		903
Securitized Assets (March 31, 2026 and December 31, 2025 Amounts Include $311 and $315, Respectively, Related to Storm Recovery Funding)	311		315
Deferred Charges and Other Noncurrent Assets	495		409
TOTAL OTHER NONCURRENT ASSETS	1,735		1,627
TOTAL ASSETS	$	13,940	$	13,524
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

96

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

March 31, 2026 and December 31, 2025

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

(Unaudited)

	March 31,		December 31,
	2026		2025
CURRENT LIABILITIES
Advances from Affiliates	$	293	$	—
Accounts Payable:
General	429		392
Affiliated Companies	59		89
Short-term Debt – Nonaffiliated	4		3
Long-term Debt Due Within One Year – Nonaffiliated (March 31, 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	80		79
Accrued Taxes	160		68
Accrued Interest	50		49
Obligations Under Operating Leases	6		7
Provision for Refund	82		81
Other Current Liabilities	150		191
TOTAL CURRENT LIABILITIES	1,740		1,885
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated (March 31, 2026 and December 31, 2025 Amounts Include $296 and $304, Respectively, Related to Storm Recovery Funding)	4,441		3,057
Long-term Debt – Affiliated	—		1,000
Deferred Income Taxes	1,476		1,458
Regulatory Liabilities and Deferred Investment Tax Credits	524		531
Asset Retirement Obligations	248		252
Employee Benefits and Pension Obligations	40		39
Obligations Under Operating Leases	194		195
Provision for Refund	22		47
Storm Reserve	109		108
Deferred Credits and Other Noncurrent Liabilities	63		53
TOTAL NONCURRENT LIABILITIES	7,117		6,740
TOTAL LIABILITIES	8,857		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	2,279		2,151
Retained Earnings	2,796		2,740
Accumulated Other Comprehensive Income (Loss)	8		8
TOTAL COMMON SHAREHOLDER’S EQUITY	5,083		4,899
Noncontrolling Interest	—		—
TOTAL EQUITY	5,083		4,899
TOTAL LIABILITIES AND EQUITY	$	13,940	$	13,524
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

97

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended March 31,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	57	$	49
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	121		98
Deferred Income Taxes	1		37
Asset Impairments and Other Related Charges	31		—
Allowance for Equity Funds Used During Construction	(8)		(3)
Mark-to-Market of Risk Management Contracts	23		(2)
Property Taxes	(84)		(75)
Deferred Fuel Over/Under-Recovery, Net	6		23
Change in Other Noncurrent Assets	(75)		(21)
Change in Other Noncurrent Liabilities	(15)		(9)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(47)		7
Fuel, Materials and Supplies	(19)		13
Accounts Payable	30		(7)
Accrued Taxes, Net	16		49
Other Current Assets	(10)		(1)
Other Current Liabilities	(24)		(39)
Net Cash Flows from Operating Activities	3		119
INVESTING ACTIVITIES
Construction Expenditures	(345)		(235)
Change in Advances to Affiliates, Net	23		—
Other Investing Activities	6		—
Net Cash Flows Used for Investing Activities	(316)		(235)
FINANCING ACTIVITIES
Capital Contribution from Parent	128		—
Issuance of Long-term Debt – Nonaffiliated	1,393		—
Change in Short-term Debt – Nonaffiliated	1		3
Change in Advances from Affiliates, Net	293		125
Retirement of Long-term Debt – Nonaffiliated	(508)		—
Retirement of Long-term Debt – Affiliated	(1,000)		—
Principal Payments for Finance Lease Obligations	(1)		(1)
Dividends Paid on Common Stock – Nonaffiliated	(1)		(1)
Net Cash Flows from Financing Activities	305		126
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(8)		10
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	17		5
Cash, Cash Equivalents and Restricted Cash at End of Period	$	9	$	15
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	50	$	39
Noncash Acquisitions Under Finance Leases	—		1
Construction Expenditures Included in Current Liabilities as of March 31,	195		89
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 99.

98

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	100
New Accounting Standards	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	102
Comprehensive Income	AEP	103
Rate Matters	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	104
Commitments, Guarantees and Contingencies	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	119
Acquisitions and Impairments	AEP, I&M, SWEPCo	123
Benefit Plans	AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo	124
Business Segments	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	125
Derivatives and Hedging	AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo	129
Fair Value Measurements	AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo	138
Income Taxes	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	151
Financing Activities	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	153
Variable Interest Entities	AEP	160
Revenue from Contracts with Customers	AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo	163

99

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 months ended March 31, 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 March 31,
	2026				2025
	(in millions, except per share data)
			$/share				$/share
Earnings Attributable to AEP Common Shareholders	$	874			$	800
Weighted-Average Number of Basic AEP Common Shares Outstanding	542.1		$	1.61	533.4		$	1.50
Weighted-Average Dilutive Effect	5.0		(0.01)		1.3		—
Weighted-Average Number of Diluted AEP Common Shares Outstanding	547.1		$	1.60	534.7		$	1.50

There were no antidilutive shares outstanding as of March 31, 2026 and 2025.

100

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:

	March 31, 2026
	AEP		AEP Texas		APCo		SWEPCo
	(in millions)
Cash and Cash Equivalents	$	306	$	—	$	4	$	2
Restricted Cash	33		6		12		7
Total Cash, Cash Equivalents and Restricted Cash	$	339	$	6	$	16	$	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)

	Three Months Ended March 31,
Cash Flow Information	2026		2025
	(in millions)
Cash Paid for:
Interest, Net of Capitalized Amounts	$	450	$	350
Noncash Investing and Financing Activities:
Acquisitions Under Finance Leases	24		8
Construction Expenditures Included in Current Liabilities as of March 31,	1,434		1,041
Contribution in Aid of Construction Advances in Current Assets as of March 31,	61		—
Acquisition of Nuclear Fuel Included in Current Liabilities as of March 31,	9		—

101

2. NEW ACCOUNTING STANDARDS

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

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

SEC Climate Disclosure Rule

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

ASU 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.

102

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 March 31, 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	25		—		—		25
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)	(50)		—		—		(50)
Amortization of Actuarial (Gains) Losses	—		—		1		1
Reclassifications from AOCI, before Income Tax Expense	(50)		—		1		(49)
Income Tax Expense	(10)		—		—		(10)
Reclassifications from AOCI, Net of Income Tax Expense	(40)		—		1		(39)
Net Current Period Other Comprehensive Income (Loss)	(15)		—		1		(14)
Balance in AOCI as of March 31, 2026	$	63	$	(1)	$	(40)	$	22

	Cash Flow Hedges				Pension
Three Months Ended March 31, 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	38		(1)		—		37
Amount of (Gain) Loss Reclassified from AOCI
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation (a)	(17)		—		—		(17)
Interest Expense (a)	—		(1)		—		(1)
Amortization of Actuarial (Gains) Losses	—		—		1		1
Reclassifications from AOCI, before Income Tax Expense	(17)		(1)		1		(17)
Income Tax Expense	(4)		—		—		(4)
Reclassifications from AOCI, Net of Income Tax Expense	(13)		(1)		1		(13)
Net Current Period Other Comprehensive Income (Loss)	25		(2)		1		24
Balance in AOCI as of March 31, 2025	$	124	$	1	$	(104)	$	21

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

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4.  RATE MATTERS

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

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 March 31, 2026, SWEPCo’s share of the net investment in the Pirkey Plant was $172 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 March 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 March 31, 2026, the Texas jurisdictional share of the net book value of the Pirkey Plant was $46 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.

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.

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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 ODEQ has submitted. 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 March 31, 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.

The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of March 31, 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	$	53	$	247	$	21	(b)	2026		(c)	$	13
Welsh Plant, Units 1 and 3	249		235		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.

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Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except OPCo)

	AEP
	March 31,		December 31,
	2026		2025
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Welsh Plant, Units 1 and 3 Accelerated Depreciation	$	235	$	220
UTM Deferred Costs	80		56
Pirkey Plant Accelerated Depreciation	46		93
Storm-Related Costs	48		43
West Virginia MRBC Surcharge (a)	34		—
System Resiliency Plan Deferred Costs - Texas	31		17
Other Regulatory Assets Pending Final Regulatory Approval	21		6
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs (b)	273		191
Plant Retirement Costs – Asset Retirement Obligation Costs (c)	263		257
2024-2025 Virginia Biennial Under-Earnings (d)	192		172
NOLC Costs (e)	87		89
Pension Settlement	24		24
Deferred Pension and OPEB Costs	32		27
Other Regulatory Assets Pending Final Regulatory Approval	134		112
Total Regulatory Assets Pending Final Regulatory Approval	$	1,500	$	1,307

(a)In April 2026, the WVPSC issued an order that affirms previously approved MRBC revenue requirements and allows APCo to perform a final true-up to recover past MRBC costs that were not reflected in MRBC surcharge rates in a timely manner. The timing of recovery through the ENEC will be determined in the Companies’ 2026 ENEC proceeding. See “West Virginia Modified Rate Base Cost (MRBC) Surcharge Update Filing” section below for additional information.

(b)In March 2026, the WVPSC issued a financing order approving a securitization that includes $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)See “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.

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

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

	AEP Texas
	March 31,		December 31,
	2026		2025
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
UTM Deferred Costs	$	80	$	56
Storm-Related Costs	41		41
System Resiliency Plan Deferred Costs	20		17
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	34		31
Deferred Pension and OPEB Costs	32		27
Other Regulatory Assets Pending Final Regulatory Approval	9		9
Total Regulatory Assets Pending Final Regulatory Approval	$	216	$	181

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	AEPTCo
	March 31,		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
	March 31,		December 31,
	2026		2025
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
West Virginia MRBC Surcharge (a)	$	28	$	—
Other Regulatory Assets Pending Final Regulatory Approval	2		2
Regulatory Assets Currently Not Earning a Return
2024-2025 Virginia Biennial Under-Earnings (b)	192		172
Plant Retirement Costs – Asset Retirement Obligation Costs (c)	173		169
Storm-Related Costs – West Virginia (d)	62		39
Pension Settlement	16		16
2026-2027 Virginia Biennial Under-Earnings	15		—
Virginia Corporate Alternative Minimum Tax	—		13
West Virginia Corporate Alternative Minimum Tax	—		11
Other Regulatory Assets Pending Final Regulatory Approval	29		18
Total Regulatory Assets Pending Final Regulatory Approval	$	517	$	440

(a)In April 2026, the WVPSC issued an order that affirms previously approved MRBC revenue requirements and allows APCo to perform a final true-up to recover past MRBC costs that were not reflected in MRBC surcharge rates in a timely manner. The timing of recovery through the ENEC will be determined in the Companies’ 2026 ENEC proceeding. See “West Virginia Modified Rate Base Cost (MRBC) Surcharge Update Filing” section below for additional information.

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

(c)See “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.

(d)In March 2026, the WVPSC issued a financing order approving a securitization that includes $40 million of West Virginia jurisdictional storm operation and maintenance costs that are subject to a final review by the WVPSC after bond pricing.

	I&M
	March 31,		December 31,
	2026		2025
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval	$	4	$	4
Regulatory Assets Currently Not Earning a Return
Plant Retirement Costs – Asset Retirement Obligation Costs (a)	79		78
Storm-Related Costs – Indiana	32		29
Other Regulatory Assets Pending Final Regulatory Approval	6		7
Total Regulatory Assets Pending Final Regulatory Approval	$	121	$	118

(a)See “Federal EPA’s Revised CCR Rule” section of Note 5 for additional information.

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	PSO
	March 31,		December 31,
	2026		2025
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	$	32	$	25
NOLC Costs (a)	21		23
Generation PBA and Delayed Retirement Deferral	17		13
Oklahoma Senate Bill 998 Deferral	16		9
Other Regulatory Assets Pending Final Regulatory Approval	15		14
Total Regulatory Assets Pending Final Regulatory Approval	$	101	$	84

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

	SWEPCo
	March 31,		December 31,
	2026		2025
Noncurrent Regulatory Assets	(in millions)
Regulatory Assets Currently Earning a Return
Welsh Plant, Units 1 and 3 Accelerated Depreciation	$	235	$	220
Pirkey Plant Accelerated Depreciation	46		93
Retired Plant Costs - FERC	15		—
System Resiliency Plan Deferred Costs - Texas	11		1
Other Regulatory Assets Pending Final Regulatory Approval	7		2
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs - Louisiana, Texas	88		43
NOLC Costs (a)	65		66
Other Regulatory Assets Pending Final Regulatory Approval	21		20
Total Regulatory Assets Pending Final Regulatory Approval	$	488	$	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.

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

AEP Texas Interim Transmission and Distribution Rates

Through March 31, 2026, AEP Texas’ cumulative revenues from transmission and distribution interim base rate increases that are subject to review are estimated to be approximately $159 million. A base rate review could result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition.

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. In April 2026, AEP Texas filed responses reflective of the legislative intent of Texas House Bill 5247 (2025). The impact of the final decision, and

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any potential retroactive impacts, as authorized by the PUCT, will be reflected in AEP Texas’ financial statements in the period in which a final decision is issued. A decision is expected in the second quarter of 2026.

In March 2026, AEP Texas began billing interim rates subject to refund as part of the UTM filing. If the PUCT issues a ruling that differs from AEP Texas’ position, a refund or billing credit could be required. Investments included in the UTM and the existing capital tracker filings remain subject to prudency review in the utility’s next base rate review before the PUCT. AEP Texas deferred approximately $80 million of eligible costs through March 31, 2026 as a regulatory asset. If any of these deferred costs are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

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

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

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

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

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

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’ West Virginia base case filing, as described in the “2024 West Virginia Base Rate Case” section above, approved the termination of the MRBC and the transition of MRBC rates into base rates. The WVPSC did not rule on MRBC refunds proposed by WVPSC staff and an intervening party related to NOLCs and other issues.

In April 2026, the WVPSC issued an order that adjudicated the Companies’ 2024 MRBC 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

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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 a carrying charge on revised MRBC under-recovery balances starting September 2024 and for the Companies 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. If any refund liabilities are imposed by the WVPSC related to NOLC, it could 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. As included in the WVPSC’s March 2026 order, shown below is a summary of the Companies’ combined $2.6 billion maximum securitization amount:

Proposed Securitized Items	APCo		WPCo		Total
	(in millions)
Undepreciated Utility Plant Balances of Amos, Mitchell and Mountaineer (as of December 31, 2022)	$	1,145	$	559	$	1,704
ENEC Under-Recovery Regulatory Assets (a)	216		276		492
Forecasted Undepreciated CCR and ELG Investments of Amos, Mitchell and Mountaineer (as of November 30, 2024) (a)(b)	88		149		237
Deferred Storm Other Operation and Maintenance Expense Regulatory Assets (b)	155		3		158
Upfront Financing Costs (a)	10		6		16
Total	$	1,614	$	993	$	2,607

(a)Amounts represent estimates. The WVPSC may update these estimates prior to securitization bond marketing.

(b)In December 2025, the KPSC approved KPCo’s request for a CPCN to make investments necessary for KPCo to resume: (a) a 50% share of the Mitchell Plant ELG Project and (b) a 50% share of non-ELG capital investments. This approval by the KPSC allows KPCo to continue taking a 50% share of energy and capacity from the Mitchell Plant to serve KPCo customers beyond December 31, 2028. See “Mitchell Plant Filing for Certificate of Public Convenience and Necessity” section below for additional information. In February 2026, WPCo requested that the WVPSC grant any additional authorizations necessary to enable WPCo to reflect the holdings and impact of the December 2025 KPSC order or make a determination that no such authorizations are required. WPCo forecasted CCR and ELG amounts related to the Mitchell Plant are subject to change pending a ruling from the WVPSC on WPCo’s February 2026 filing.

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 second half of 2026, subject to market conditions. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2025 Virginia Securitization Filing

In July 2025, APCo filed a request with the Virginia SCC to finance, through the issuance of proposed 20-year securitization bonds, approximately $1.4 billion of Virginia jurisdictional undepreciated property balances and a major storm operation and maintenance regulatory asset deferral balance. This proposed securitization included: (a) $1.2 billion of undepreciated Virginia jurisdictional plant balances as of December 31, 2023 for the Amos and Mountaineer Plants and (b) $141 million of Virginia jurisdictional major storm other operation and maintenance expenses deferred during the 2024-2025 biennial period. In November 2025, the Virginia SCC issued a financing order approving securitization of the requested $1.4 billion of Virginia jurisdictional costs. In accordance with Virginia statutory requirements and the financing order, the issuance of the securitization bonds is subject to final review by the Virginia SCC after bond pricing. APCo expects to proceed with the securitization bond issuance process and to complete the securitization process in the second 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.

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ETT Rate Matters (Applies to AEP)

ETT Interim Transmission Rates

AEP has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next base rate proceeding. Through March 31, 2026, AEP’s share of ETT’s cumulative revenues from interim base rate increases that are subject to a prudency review is approximately $1 million. A base rate review could produce a refund to customers if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition.

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. A procedural schedule for the case is pending. If any of the costs in the case are not recoverable or refunds collected under interim transmission rates are ordered to be returned, it could reduce future net income and cash flows and impact financial condition.

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

Michigan Power Supply Cost Recovery (PSCR) Reconciliation

2024 PSCR Reconciliation

In March 2025, I&M submitted its 2024 PSCR Reconciliation to the MPSC. In October 2025, MPSC staff and intervenors submitted testimony recommending PSCR cost disallowances associated with the OVEC ICPA and the Rockport UPA with AEGCo ranging from $259 thousand to $14 million. A hearing on I&M’s 2024 PSCR Reconciliation was held in December 2025. In April 2026, an ALJ issued a PFD recommending a $2 million cost disallowance associated with the OVEC ICPA and no cost associated with the Rockport UPA with AEGCo. An MPSC order is expected in the second quarter of 2026. Any future disallowances ordered by the MPSC on I&M’s 2024 PSCR Reconciliation could reduce future net income and cash flows and impact financial condition.

Indiana Earnings Test

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

In 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 April 2026, I&M and an intervening party submitted a settlement agreement recommending that the IURC approve I&M’s proposed modifications to jurisdictional cost allocations and proposed over-earnings credit of $53 million for the earnings test period ending November 2025. A hearing will be held in May 2026 and an IURC order is expected in the second quarter of 2026. An IURC order approving I&M’s proposed jurisdictional cost allocation modifications as included in the settlement agreement would increase future net income and cash flows and impact financial condition.

KPCo Rate Matters (Applies to AEP)

Investigation of the Service, Rates and Facilities of KPCo

In June 2023, the KPSC issued an order directing KPCo to show cause why it should not be subject to Kentucky statutory remedies, including fines and penalties, for failure to provide adequate service in its service territory. The KPSC’s show cause order did not make any determination regarding the adequacy of KPCo’s service. In July 2023, KPCo filed a response to the

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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 “2025 Kentucky Base Rate Case” section below for additional information.

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

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

To operate in accordance with KPSC and WVPSC directives related to Mitchell Plant ELG investments, KPCo and WPCo expect to utilize existing authority under the Mitchell Plant Operating Agreement to revise billing procedures resulting in equal allocation of costs. In February 2026, WPCo requested that the WVPSC grant any additional authorizations necessary to enable WPCo to reflect the holdings and impact of the December 2025 KPSC order or make a determination that no such authorizations are required. As of March 31, 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 $517 million.

2025 Kentucky Base Rate Case

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

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

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

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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 and set a procedural schedule for submitting information requests. Additionally, the order authorized KPCo to defer $17 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. In December 2024, intervenors filed appeals with the Supreme Court of Ohio on the PUCO’s denial for rehearing. In April 2026, the Supreme Court of Ohio issued a decision affirming the PUCO’s August 2024 order which determined costs incurred by OPCo during the 2018-2019 audit period 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.

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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, two intervenors filed applications for rehearing.

March 2026 Storm Costs

In March 2026, the service territory of OPCo was impacted by strong winds from an isolated storm resulting in power outages and damage to the transmission and distribution infrastructure. As of March 31, 2026, OPCo had incurred approximately $20 million in incremental operation and maintenance costs related to service restoration efforts. The 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.

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 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.

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In April 2026, a unanimous settlement in principle was reached and SWEPCo filed a motion to abate the hearing. A PUCT order on the settlement is not expected until the fourth quarter of 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.

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 denial at the United States Supreme Court, which is pending.

In October 2025, the Maryland Public Service Commission approved an extension of the construction commencement deadline to May 2026. Additional regulatory proceedings before the PAPUC are expected to resume in 2026.

In September 2021, PJM notified Transource Energy that the IEC was suspended to allow for the regulatory and related appeals process to proceed in an orderly manner without breaching milestone dates in the project agreement. At that time, PJM stated that the IEC had not been canceled and remained necessary to alleviate congestion. In July 2025, PJM removed the IEC from suspended status and indicated the project going forward will be included in PJM’s models with a modified scope. PJM continues to evaluate reliability and market efficiency in the area. As of March 31, 2026, AEP’s share of IEC capital expenditures was approximately $96 million, located in Total Property, Plant and Equipment - Net on AEP’s balance sheets. The FERC has previously granted abandonment benefits for this project, allowing the full recovery of prudently incurred costs if the project is canceled for reasons outside the control of Transource Energy. If any of the IEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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

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

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

In January 2024, the FERC issued two orders granting formal challenges by certain unaffiliated customers related to stand-alone treatment of NOLCs in the 2021 Transmission Formula Rates of the AEP transmission owning subsidiaries within PJM and SPP. The FERC directed the AEP transmission owning subsidiaries within PJM and SPP to provide refunds with interest on all amounts collected for the 2021 rate year, and for such refunds to be reflected in the annual update for the next rate year. Accordingly, AEP transmission owning subsidiaries within PJM and SPP 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 FERC on the merits in November 2025. 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. Intervenors have filed petitions for review of the FERC’s orders in this matter with the United States Court of Appeals for the District of Columbia Circuit. The appeals have been consolidated and are pending the establishment of a procedural schedule.

As directed by the FERC in its June 2025 order, AEP transmission owning subsidiaries within PJM and SPP submitted compliance filings in August 2025 that revised the March 2024 refund compliance reports and permit the collection of excess refunds provided to customers, with interest, in the annual update for the 2025 rate year. In October 2025, intervenors filed comments in response to the compliance filings. In March and April 2026, the FERC approved the AEP transmission owning subsidiaries’ compliance filings related to PJM and SPP, respectively.

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As a result of the June 2025 FERC orders, the Registrants recognized revenues, with interest, attributable to accelerated depreciation-related NOLCs included in transmission formula rates for years 2021 through 2025 and reduced Excess ADIT regulatory liabilities. Increases in affiliated transmission expense, which correspond to affiliated transmission revenues recognized, were deferred as an increase to regulatory assets or a reduction to regulatory liabilities on the balance sheets where management expects that expense would be collected from retail customers through authorized retail jurisdiction rider mechanisms. The table below summarizes the impact to the statements of income recorded by the Registrants in the second quarter of 2025:

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

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

In March 2025, the KPSC and the Attorney General of Kentucky filed a complaint at the FERC against AEPSC and the AEP East Companies challenging the manner in which costs are allocated for local transmission projects pursuant to the TA. The complaint contends that certain costs allocated to KPCo are unjust, unreasonable and provide no benefit to KPCo customers. The relief requested in the complaint includes requiring a revision to the TA so that the costs for local transmission projects remain exclusively with the retail distribution service territory where the project is located unless a specific project is granted approval to establish a different cost allocation by the state commissions. Various parties have filed comments and motions to intervene. In May 2025, AEP filed a motion to dismiss and answered the complaint. In November 2025, the FERC issued an order denying the KPSC and Attorney General of Kentucky complaint. In December 2025, the KPSC and Attorney General of Kentucky requested a rehearing of the November order denying the complaint. In January 2026, the FERC issued a notice of denial of the request for rehearing by operation of law, providing the FERC with additional time to consider and decide on the merits of the request. In February 2026, the KPSC and Attorney General of Kentucky filed a petition for review of the FERC’s orders in this matter with the United States Court of Appeals for the Sixth Circuit. In March 2026, the FERC again denied the complaint, continuing to find that the KPSC and Attorney General of Kentucky have not met their burden of proof. 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, effective starting 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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Further discussions with the FERC audit staff will be held in 2026 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.

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 March 31, 2026, no letters of credit were issued under either revolving credit facility.

An uncommitted facility gives AEP the right to accept or decline each request made under the facility.  AEP issues letters of credit on behalf of subsidiaries under six uncommitted facilities totaling $450 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of March 31, 2026 were as follows:

Company	Amount		Maturity
	(in millions)
AEP	$	404	April 2026 to March 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 March 31, 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.

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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 March 31, 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	$	36
AEP Texas	8
APCo	5
I&M	4
OPCo	6
PSO	3
SWEPCo	4

ENVIRONMENTAL CONTINGENCIES (Applies to all Registrants except AEPTCo)

Federal EPA’s Revised CCR Rule

In April 2024, the Federal EPA finalized revisions to the CCR Rule (Legacy CCR Rule) to expand the scope of the rule to include inactive impoundments at inactive facilities (legacy CCR surface impoundments) as well as to establish requirements for currently exempt solid waste management units that involve the direct placement of CCR on the land (CCR management units). The Federal EPA is requiring that owners and operators of legacy surface impoundments comply with all of the Legacy CCR Rule requirements applicable to inactive CCR surface impoundments at active facilities, except for the location restrictions and liner design criteria. The rule establishes compliance deadlines for legacy surface impoundments to meet regulatory requirements, including a requirement to initiate closure within five years after the effective date of the final rule. The rule requires evaluations to be completed at both active facilities and inactive facilities with one or more legacy surface impoundments. Closure may be accomplished by applying an impermeable cover system over the CCR material (closure in place) or the CCR material may be excavated and placed in a compliant landfill (closure by removal). Groundwater monitoring and other analysis over the next three years will provide additional information on the planned closure method. 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, 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 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 January 2026, APCo received a final order from the Virginia SCC approving the recovery of $80 million of Legacy CCR Rule regulatory assets through 2041 and concurrent recovery of ongoing depreciation and accretion expenses. AEP will continue to seek cost recovery through regulated rates in other jurisdictions, including proposal of new regulatory mechanisms for cost recovery where existing mechanisms are not applicable. The rule could have an additional, material adverse impact on net income, cash flows and financial condition if AEP cannot ultimately recover these additional costs of compliance. Several parties, including AEP and one of its trade associations, have filed petitions for review of the Legacy CCR Rule with the U.S. Court of Appeals for the District of Columbia Circuit. The litigation is being held in abeyance. In February 2026, the Federal EPA finalized a rule that provides additional time to meet facility evaluation requirements for identifying CCR management units and to comply with groundwater monitoring provisions. Additionally, this rule makes conforming changes to the remaining CCR management units compliance deadlines. Management cannot predict the outcome of the litigation.

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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. The proposal is expected to be finalized by the end of 2026. Management is evaluating the proposal and intends to participate in the rulemaking process through submission of comments, but cannot predict the outcome of the rulemaking process.

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.

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

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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.

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6. ACQUISITIONS AND IMPAIRMENTS

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

ACQUISITIONS

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 will initially reflect 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 represents an asset acquisition. 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	Fuel Type	Net Maximum Capacity	Property, Plant and Equipment, Net		Prepayments & Other Current Assets		Materials &  Supplies		Accounts Receivable		Accounts Payables
		(MWs)	(in millions)
Oregon Plant	Natural Gas	870	$	918	$	35	$	5	$	16	$	9

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.

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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 March 31, 2026	AEP		AEP Texas		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
Service Cost	$	25	$	2	$	2	$	3	$	2	$	2	$	2
Interest Cost	51		4		6		6		5		3		3
Expected Return on Plan Assets	(64)		(5)		(8)		(8)		(7)		(4)		(4)
Amortization of Net Actuarial Loss	11		1		1		1		1		—		1
Net Periodic Benefit Cost	$	23	$	2	$	1	$	2	$	1	$	1	$	2

Three Months Ended March 31, 2025	AEP		AEP Texas	APCo	I&M	OPCo	PSO	SWEPCo
	(in millions)
Service Cost	$	24	$