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 June 30, 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
	July 30, 2026
American Electric Power Company, Inc.	544,397,352
	($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
June 30, 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	37
	Condensed Consolidated Financial Statements	38
AEP Texas Inc. and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	44
	Condensed Consolidated Financial Statements	47
AEP Transmission Company, LLC and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	53
	Condensed Consolidated Financial Statements	55
Appalachian Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	60
	Condensed Consolidated Financial Statements	64
Indiana Michigan Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	70
	Condensed Consolidated Financial Statements	73
Ohio Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations	79
	Condensed Consolidated Financial Statements	82
Public Service Company of Oklahoma:
	Management’s Narrative Discussion and Analysis of Results of Operations	87
	Condensed Financial Statements	90
Southwestern Electric Power Company Consolidated:
	Management’s Narrative Discussion and Analysis of Results of Operations	96
	Condensed Consolidated Financial Statements	100
Index of Condensed Notes to Condensed Financial Statements of Registrants		106
Controls and Procedures		192

Part II.  OTHER INFORMATION
	Item 1.	Legal Proceedings	193
	Item 1A.	Risk Factors	193
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	193
	Item 3.	Defaults Upon Senior Securities	193
	Item 4.	Mine Safety Disclosures	193
	Item 5.	Other Information	193
	Item 6.	Exhibits	194
SIGNATURE			196
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.
Appalachian Recovery Funding	Appalachian Recovery Funding, LLC, a wholly-owned subsidiary of APCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to certain Virginia jurisdictional Amos and Mountaineer Property, Plant and Equipment balances and deferred storm costs.
APSC	Arkansas Public Service Commission.
ARO	Asset Retirement Obligations.
ASU	Accounting Standards Update.
ATM	At-the-Market.
BESS	Battery Energy Storage System.
CAA	Clean Air Act.
CAMT	Corporate Alternative Minimum Tax.
CCN	Certificate of Convenience and Necessity.

i

Term	Meaning
CCR	Coal Combustion Residual.
CEO	Chief Executive Officer.
CO2	Carbon dioxide and other greenhouse gases.
CODM	Chief Operating Decision Maker.
Cook Plant	Donald C. Cook Nuclear Plant, a two-unit, 2,296 MW nuclear plant owned by I&M.
Cost Recovery Funding	KPCo Cost Recovery Funding, LLC, a wholly-owned subsidiary of KPCo and consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to plant retirement costs, deferred storm costs, deferred purchased power expenses, under-recovered purchased power rider costs and issuance-related expenses.
CPA	Capacity Purchase Agreement.
CPCN	Certificate of Public Convenience and Necessity.
CSAPR	Cross-State Air Pollution Rule.
CWIP	Construction Work in Progress.
DCC Fuel	DCC Fuel XVII, DCC Fuel XVIII, DCC Fuel XIX, DCC Fuel XX, DCC Fuel XXI and DCC Fuel XXII consolidated VIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
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.
ERCOT Batch Zero Process	A one-time transitional interconnection process established by ERCOT and approved by the PUCT in 2026 that evaluates qualifying large load interconnection requests on a system-wide basis, allocates available transmission capacity, identifies necessary transmission upgrades and requires financial commitments from participating customers. The process applies primarily to large electric loads of 75 MW or greater and serves as the precursor to ERCOT's future recurring batch interconnection framework.
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.

ii

Term	Meaning
I&M	Indiana Michigan Power Company, an AEP electric utility subsidiary. I&M engages in the generation, transmission and distribution of electric power to retail customers in northern and eastern Indiana and southwestern Michigan.
IMTCo	AEP Indiana Michigan Transmission Company, Inc., a wholly-owned transmission subsidiary of Midwest Transmission Holdings.
IRP	Integrated Resource Plan.
IRS	Internal Revenue Service.
ITC	Investment Tax Credit.
IURC	Indiana Utility Regulatory Commission.
KGPCo	Kingsport Power Company, an AEP electric utility subsidiary. KGPCo provides electric service to retail customers in Kingsport, Tennessee and eight neighboring communities in northeastern Tennessee.
KPCo	Kentucky Power Company, an AEP electric utility subsidiary. KPCo engages in the generation, transmission and distribution of electric power to retail customers in eastern Kentucky.
KPSC	Kentucky Public Service Commission.
KWh	Kilowatt-hour.
LPSC	Louisiana Public Service Commission.
MATS	Mercury and Air Toxic Standards.
Midcontinent Grid Solutions	Midcontinent Grid Solutions, LLC, a holding company formed by Transource Energy and an affiliate of Berkshire Hathaway Energy in 2025, which is 43.25% owned by AEP.
Midwest Transmission Holdings	Midwest Transmission Holdings, LLC, a subsidiary of AEPTCo Parent that owns all of the issued and outstanding stock of IMTCo and OHTCo.
MISO	Midcontinent Independent System Operator.
Mitchell Plant	A two unit, 1,560 MW coal-fired power plant located in Moundsville, West Virginia. The plant is jointly owned by KPCo and WPCo.
MMBtu	Million British Thermal Units.
MPSC	Michigan Public Service Commission.
MRBC	Modified Rate Base Cost.
MTM	Mark-to-Market.
MW	Megawatt.
MWh	Megawatt-hour.
NAAQS	National Ambient Air Quality Standards.
NCWF	North Central Wind Energy Facilities, a joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,484 MWs of wind generation.
Nonutility Money Pool	Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
NOLC	Net Operating Loss Carryforward.
NOx	Nitrogen Oxide.
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.

iii

Term	Meaning
Parent	American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.
PBA	Performance Based Accreditation.
PFD	Proposal for Decision.
PJM	Pennsylvania – New Jersey – Maryland regional transmission organization.
PLR	Private Letter Ruling.
PM	Particulate Matter.
PPA	Power Purchase Agreement.
PSA	Purchase and Sale Agreement.
PSO	Public Service Company of Oklahoma, an AEP electric utility subsidiary. PSO engages in the generation, transmission and distribution of electric power to retail customers in eastern and southwestern Oklahoma.
PTC	Production Tax Credit.
PUCO	Public Utilities Commission of Ohio.
PUCT	Public Utility Commission of Texas.
Registrant Subsidiaries	AEP subsidiaries which are SEC registrants: AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Registrants	SEC registrants: AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.
Restoration Funding	AEP Texas Restoration Funding, LLC, a wholly-owned subsidiary of AEP Texas and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to storm restoration in Texas primarily caused by Hurricane Harvey.
Risk Management Contracts	Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant	A generation plant, jointly-owned by AEGCo and I&M, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana.
ROE	Return on Equity.
RPM	Reliability Pricing Model.
RTO	Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine	Sabine Mining Company, a lignite mining company that is a consolidated VIE for AEP and SWEPCo.
SEC	U.S. Securities and Exchange Commission.
SIP	State Implementation Plan.
SNF	Spent Nuclear Fuel.
SO2	Sulfur Dioxide.
SPP	Southwest Power Pool regional transmission organization.
SSO	Standard Service Offer.
State Transcos	AEPTCo’s five wholly-owned and two majority-owned, FERC regulated, transmission only electric utilities, which are geographically aligned with AEP's existing utility operating companies.
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.

iv

Term	Meaning
Tax Reform	On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.
T&D	Transmission and Distribution Utilities.
Transition Funding	AEP Texas Central Transition Funding III, LLC, a wholly-owned subsidiary of AEP Texas and consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to restructuring legislation in Texas.
Transource Energy	Transource Energy, LLC, a consolidated VIE formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. Transource Energy is 86.5% owned by AEP.
UPA	Unit Power Agreement.
Utility Money Pool	Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
UTM	Unified Tracker Mechanism.
VIE	Variable Interest Entity.
Virginia SCC	Virginia State Corporation Commission.
VIU	Vertically Integrated Utilities.
Western Region	AEP’s western service territory includes the areas where AEP Texas, PSO and SWEPCo engage in the generation, transmission and distribution of electric power to customers.
WPCo	Wheeling Power Company, an AEP electric utility subsidiary. WPCo provides electric service to retail customers in northern West Virginia.
WVPSC	Public Service Commission of West Virginia.

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

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

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

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

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

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

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

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

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

• The ability to plan for, develop, construct, acquire, or integrate a broad range of generation and energy storage resources, as well as related transmission and distribution infrastructure, including obtaining necessary regulatory approvals, permits, and incentives for which the timing is dependent upon the priorities, requirements, processes and determinations of the local policy and regulatory authorities; complying with cost caps and other regulatory or contractual requirements; and recovering associated costs and earning an appropriate return while meeting reliability, affordability, environmental, and customer‑service obligations.

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

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

• The impact of prolonged or recurring U.S. federal government shutdowns on AEP’s operations, regulatory approvals and financial performance, including potential volatility in the capital markets which may interrupt our access to capital.

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

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 or our participation within those RTOs.

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

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

• The impact of geopolitical developments on global energy markets, including volatility in fuel supply and pricing, power generation economics and customer demand patterns.

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

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

• The ability to successfully defend against cybersecurity threats.

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

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

• Projected increases in demand from data centers are subject to uncertainty and may not materialize as expected, or may occur at a different pace or scale than anticipated, which could impact our load forecasts, capital investment plans, cost recovery expectations and financial results.

The 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

Second Quarter of 2026 Compared to Second Quarter of 2025

Earnings Attributable to AEP Common Shareholders decreased from $1.2 billion in 2025 to $713 million in 2026 primarily due to:

•The favorable $480 million impact from the receipt of the June 2025 FERC NOLC order related to the treatment of NOLCs in transmission formula rates.

•A decrease in sales volumes in the residential class driven by favorable weather in 2025.

These decreases were partially offset by:

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

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

•Favorable mark-to-market economic hedging activity.

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

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025

Earnings Attributable to AEP Common Shareholders decreased from $2 billion in 2025 to $1.6 billion in 2026 primarily due to:

•The favorable $480 million impact from the receipt of the June 2025 FERC NOLC order related to the treatment of NOLCs in transmission formula rates.

•Unfavorable mark-to-market economic hedging activity.

•A decrease in sales volumes in the residential class driven by favorable weather in 2025.

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

These decreases were partially offset by:

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

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

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

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

See Results of Operations section for additional information by segment.

1

Non-GAAP Financial Measures

AEP reports its financial results in accordance with GAAP. AEP supplements its reporting of financial information with certain non-GAAP financial measures, such as operating earnings. The most comparable GAAP measure to operating earnings is GAAP earnings. Operating earnings, which could differ from earnings reported in accordance with GAAP, exclude certain gains and losses and other specified items, including mark-to-market adjustments from commodity hedging activities and other items as set forth in the reconciliation below, that management believes are not indicative of AEP’s ongoing performance.

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

Reconciliation of GAAP Earnings to Operating Earnings

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

	Three Months Ended June 30, 2026
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
GAAP Earnings (a)	$	713	$	113	$	192	$	50	$	97	$	109	$	54	$	86
Adjustments to GAAP Earnings:
Mark-to-Market Impact of Commodity Hedging Activities (b)	(8)		—		—		—		—		—		—		—
UTM Partial Disallowance (c)	22		22		—		—		—		—		—		—
Wholesale Customer Contract Agreements (d)	23		—		—		—		—		—		—		23
Income Tax Effect of Specified Items (e)	(8)		(5)		—		—		—		—		—		(5)
Total Specified Items	29		17		—		—		—		—		—		18
Operating Earnings (Non-GAAP)	$	742	$	130	$	192	$	50	$	97	$	109	$	54	$	104

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

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

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

(d)Represents probable liability related to SWEPCo’s agreements with certain existing wholesale customers and current discussions with one remaining existing wholesale customer under generation supply contracts, which is expected to result in credits to these wholesale customers.

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

	Three Months Ended June 30, 2025
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
GAAP Earnings (a)	$	1,226	$	121	$	556	$	107	$	124	$	103	$	63	$	116
Adjustments to GAAP Earnings (b):
Mark-to-Market Impact of Commodity Hedging Activities (c)	20		—		—		—		(10)		—		—		—
FERC NOLC Order (d)	(480)		—		(354)		(29)		(36)		—		(4)		(54)
Total Specified Items	(460)		—		(354)		(29)		(46)		—		(4)		(54)
Operating Earnings (Non-GAAP)	$	766	$	121	$	202	$	78	$	78	$	103	$	59	$	62

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

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

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

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

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	Six Months Ended June 30, 2026
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
GAAP Earnings (a)	$	1,587	$	233	$	375	$	245	$	245	$	226	$	69	$	142
Adjustments to GAAP Earnings:
Mark-to-Market Impact of Commodity Hedging Activities (b)	18		—		—		—		7		—		—		—
Impact of WVPSC Order (c)	(35)		—		—		(29)		—		—		—		—
Pirkey Plant Partial Disallowance (d)	31		—		—		—		—		—		—		31
UTM Partial Disallowance (e)	22		22		—		—		—		—		—		—
Wholesale Customer Contract Agreements (f)	23		—		—		—		—		—		—		23
Income Tax Effect of Specified Items (g)	(13)		(5)		—		6		(2)		—		—		(11)
Total Specified Items	46		17		—		(23)		5		—		—		43
Operating Earnings (Non-GAAP)	$	1,633	$	250	$	375	$	222	$	250	$	226	$	69	$	185

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

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

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

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

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

(f)Represents probable liability related to SWEPCo’s agreements with certain existing wholesale customers and current discussions with one remaining existing wholesale customer under generation supply contracts, which is expected to result in credits to these wholesale customers.

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

	Six Months Ended June 30, 2025
	AEP		AEP Texas		AEPTCo		APCo		I&M		OPCo		PSO		SWEPCo
	(in millions)
GAAP Earnings (a)	$	2,026	$	223	$	767	$	272	$	182	$	166	$	91	$	164
Adjustments to GAAP Earnings (b):
Mark-to-Market Impact of Commodity Hedging Activities (c)	6		—		—		—		16		—		—		—
Sale of AEP OnSite Partners (d)	10		—		—		—		—		—		—		—
Impact of Ohio Legislation (e)	27		—		—		—		—		27		—		—
FERC NOLC Order (f)	(480)		—		(354)		(29)		(36)		—		(4)		(54)
Total Specified Items	(437)		—		(354)		(29)		(20)		27		(4)		(54)
Operating Earnings (Non-GAAP)	$	1,589	$	223	$	413	$	243	$	162	$	193	$	87	$	110

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

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

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

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

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

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

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ELECTRIC INDUSTRY TRANSFORMATION

The electric utility industry is undergoing a historic transformation, fueled by rapid and projected 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. 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, with a goal of promoting stability and affordability. As of March 31, 2026, these tariff proposals were filed in eight of AEP’s jurisdictions, with four receiving approval from state commissions. During the second quarter of 2026, the Virginia State Commission approved APCo’s large load tariff proposal, which applies to new large load additions greater than or equal to 150 MW on an aggregated basis or 100 MW on an individual basis. As of June 30, 2026, there were three pending proposals in Michigan, Oklahoma and SWEPCo-Texas. AEP is actively engaging with regulators, policymakers, RTOs, customers and suppliers to connect large load customers to the grid while also advancing system reliability, resiliency and affordability across its service territory.

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

•The addition of 1,013 MWs of owned generating capacity in 2026.

•Signing agreements in 2026 to acquire 1,838 MWs in additional generation facilities.

•Requests for proposals seeking approximately 12,100 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.

PJM Proposed Reforms

In July 2026, the PJM Board approved near-term resource adequacy reforms intended to address projected reliability concerns associated with significant forecasted load growth and capacity shortages. The package directs PJM to seek FERC approval of a Reliability Backstop Procurement mechanism and an Interim Resource Adequacy Service for new large load customers that do not provide sufficient capacity resources to meet their resource adequacy needs. The reforms also include the creation of a Large Load Registry and new requirements for electric distribution utilities to provide information regarding certain large load interconnection requests. PJM expects to conduct a centralized procurement process beginning in September 2026.

Fixed Resource Requirement entities are excluded from the Reliability Backstop Procurement targets and associated cost allocation. AEP's Fixed Resource Requirement operating companies within PJM also may be affected in their role as electric distribution utilities. Under the proposed framework, beginning June 1, 2027, electric distribution utilities would be required to administer an Interim Resource Adequacy Service for certain new large load customers that do not provide sufficient capacity resources to meet applicable reliability requirements. The proposal also requires electric distribution utilities to administer a FERC-approved compensation mechanism for qualifying large load customers that are directed to reduce their electricity consumption.

The PJM proposal also includes provisions intended to mitigate impacts associated with a transmission owner's withdrawal from PJM. Under the proposal, a withdrawing transmission owner that participates in the Reliability Backstop Procurement program could be required to satisfy certain future obligations associated with resources procured through that program or charges allocated to load on an accelerated basis prior to withdrawal, or otherwise provide for continued payment of such obligations through the applicable commitment term. These provisions are intended to prevent costs associated with committed reliability resources from being shifted to remaining PJM participants.

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PJM has not yet filed the proposal with the FERC, and the ultimate form of any approved tariff revisions, implementation requirements, cost recovery mechanisms and operational impacts remains uncertain. At this time, AEP cannot predict the outcome of the FERC proceeding or estimate the potential impact, if any, that any final approved provisions may have on its financial condition, results of operations or cash flows. AEP will continue to monitor the proceeding.

Customer Demand

AEP uses sales volumes by customer class as a way to measure drivers of customer demand. Through the first half of 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 favorable weather in the first and second quarters of 2025 and normal weather through the first half of 2026. The table below shows the percentage change in sales volume by customer class.

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

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

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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). In May 2026, APCo acquired the Grover Hill Wind Project (Grover Hill Wind). These transactions reflect the Companies’ focus on securing necessary generation to meet future customer demand. See the “Acquisitions” section of Note 6 for additional information. The table below summarizes these acquisitions:

Company	Plant Name	Fuel Type	Location	Acquisition Date	Net Maximum Capacity
					(in MWs)
I&M	Oregon Plant	Natural Gas	Oregon, OH	March 2026	870
APCo	Grover Hill Wind	Wind	Paulding County, OH	May 2026	143
Total Acquired Generation Facilities					1,013

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. In July 2026, SWEPCo, PUCT staff and certain intervenors filed an unopposed stipulation and settlement agreement with the PUCT agreeing the application for a CCN should be approved. Additionally, in July 2026, SWEPCo and the LPSC staff filed a joint stipulation and term sheet with the LPSC agreeing the application for a CCN should be approved. 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, which was approved in May 2026. The combustion turbines are projected to be online by the end of 2028.

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

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

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Significant Approved Renewable Generation and Storage Filings

AEP received approval from various state regulatory commissions to acquire approximately 884 MWs of owned renewable generation and storage facilities, totaling approximately $2.3 billion. The Financial Condition section below includes the estimated cost of these facilities in the Budgeted Capital Expenditures. In addition, AEP received approval from various state regulatory commissions for 924 MWs of renewable PPAs. The following table summarizes regulatory approvals received for active renewable projects that are not yet in service as of June 30, 2026:

Company	Generation Type	Expected Commercial Operation	Owned/PPA	Generating Capacity
				(in MWs)
APCo	Solar	2026-2028	PPA	343
I&M	Wind	2026-2030	PPA	401
I&M	Solar	2027	PPA	180
I&M	Solar	2029	Owned	245
PSO (a)	Wind	2026	Owned	265
PSO (a)	Solar	2027	Owned	150
PSO	BESS	2027-2028	Owned	224
Total Approved Renewable Projects				1,808

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

Significant Generation Requests for Proposal (RFP)

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

Company	Issuance Date	Resource Type	Projected In-Service Dates	Generating Capacity
				(in MWs)
APCo	May 2026	Owned wind and solar	2029	800
APCo	May 2026	Purchased power from solar, wind and hydroelectric resources	2029/2030	300
I&M (a)	September 2024	Wind, solar, dispatchable resources, BESS and emerging technology resources	2029	4,000
PSO	January 2026	All-source	2029	4,000
SWEPCo	May 2026	All-source	2031	3,000
Total Significant RFPs				12,100

(a)Five wind resources totaling 574 MWs from the 2024 RFP were contracted and approved by the IURC. The 918 MW Sycamore Plant was also selected through the 2024 RFP and was filed with the IURC for approval in April 2026. I&M expects to file several additional projects selected through the 2024 RFP in the second half of 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 June 30, 2026, by year, for the five-year period 2026-2030:

	APCo	I&M		PSO		SWEPCo
	Gas	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	203	1,392	—	438	—	472	75
2029	—	996	—	493	—	525	75
2030	—	996	—	568	—	299	75

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Large Load Interconnections in Texas

In June 2025, Texas Senate Bill 6 (SB 6) became effective and was signed into law by the Governor of Texas. SB 6 establishes a standardized process for connecting large load customers within ERCOT in a manner intended to support economic development in Texas while reducing the potential for stranded infrastructure costs. The new legislation establishes criteria for new large load interconnections and directs the PUCT to ensure that these large load customers pay a reasonable share of allocated transmission costs. The PUCT continues its rulemaking efforts to implement SB 6, including provisions related to large load interconnection standards, load forecasting, reliability requirements and transmission cost allocation.

AEP Texas has executed Letters of Agreement for approximately 45 gigawatts of incremental load by 2030, including approximately 40 gigawatts of prospective load seeking consideration under ERCOT’s Batch Zero process, a one-time transitional interconnection process established by ERCOT and approved by the PUCT in 2026. The ERCOT Batch Zero process is designed to evaluate qualifying large load interconnection requests on a system-wide basis, allocate available transmission capacity, identify necessary transmission upgrades and require financial commitments from participating customers. The process applies primarily to large electric loads of 75 MW or greater and serves as the precursor to ERCOT's future recurring batch interconnection framework. In July 2026, AEP Texas received approximately $2 billion of financial security in the form of cash collateral, corporate or parental guarantees and letters of credit for the 40 gigawatts of prospective load seeking consideration for participation in the Batch Zero process.

ERCOT is expected to identify projects eligible for participation in Batch Zero, while the PUCT is expected to issue additional SB 6 rulemaking guidance in August 2026. ERCOT expects to provide load ramp information to eligible Batch Zero projects in April 2027, enabling large load customers to determine whether to proceed with an interconnection agreement and reserve its electric capacity. These activities are expected to provide greater clarity regarding large load interconnection requirements, transmission infrastructure needs and the timing and scale of future load growth. However, the amount, timing and cost responsibility associated with these prospective large load interconnections remain subject to ongoing ERCOT and PUCT actions.

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.

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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%
APCo	Virginia	May 2026	61		10.5%

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

As of June 30, 2026, AEP Texas had deferred approximately $72 million of eligible costs as a regulatory asset of which $65 million will be included in AEP Texas’ next UTM application. Investments included in the UTM and the existing capital tracker filings remain subject to prudency review in the utility’s next base rate case proceeding before the PUCT. If any of these deferred costs 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. In July 2026, the WVPSC approved an overall balance of $2.7 billion of eligible costs for securitization. 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 June 1, 2027. In April 2026, the Companies agreed to the terms of the Inflation-Based Rate Adjustment described above and filed revised tariff sheets reflecting a $40 million combined annual increase to base rates effective July 1, 2026.

In April 2026, the WVPSC issued an order that adjudicated the Companies’ 2024 MRBC surcharge update filing. This order affirms previously approved MRBC revenue requirements and allows the Companies to perform a final true-up in an ENEC filing to recover past MRBC costs that were not reflected in MRBC surcharge rates in a timely manner during the four-year existence of the surcharge. This order also allows the Companies to recognize carrying charges on revised MRBC under-recovery balances starting September 2024 and 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 the revenue requirement related to inclusion of a stand-alone NOLC deferred tax asset in MRBC rates may be subject to refund, pending the future issuance of a PLR or other guidance by the IRS.

In May 2026, a group of APCo customers submitted an appeal to the West Virginia Intermediate Court of Appeals alleging that the WVPSC erred in its April 2026 order approving: (a) the Inflation-Based Rate Adjustment without adequate findings, evidentiary support or reasoned explanation demonstrating the approval of reasonable rates under WVPSC statutes, (b) a final MRBC true-up without sufficient record support and (c) recovery mechanisms associated with the ENEC, vegetation management, Broadband and securitization-related ratemaking. This appeal was dismissed by the West Virginia Intermediate Court of Appeals for lack of jurisdiction. The group of APCo customers subsequently submitted the appeal to

9

the West Virginia Supreme Court. In July 2026, an intervening party submitted an appeal to the West Virginia Supreme Court regarding the Inflation-Based Rate Adjustment alleging that the WVPSC: (a) failed to carry its burden of proving that the Companies’ existing rates were unreasonable and needed to be changed, (b) failed to adequately support its order with evidence of record and (c) violated the due process rights of the intervening party and the customers that it represents. See the “2026 ENEC Update Filing”, “West Virginia Modified Rate Base Cost (MRBC) Surcharge Update Filing” and “2025 West Virginia Securitization Filing” sections of Note 4 for additional information.

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

2025 Virginia Securitization Filing

In May 2026, APCo issued 20-year securitization bonds to finance approximately $1.4 billion of jurisdictional costs, including; (a) $1.2 billion of certain Virginia jurisdictional Property, Plant and Equipment balances for the Amos and Mountaineer Plants, (b) $141 million of Virginia jurisdictional major storm operation and maintenance expenses deferred as Regulatory Assets during the 2024-2025 biennial period and (c) $11 million of up-front financing costs. After issuing the securitization bonds, APCo implemented a rider to recover annual securitization debt financing costs and the Base Rate Reduction (BRR) Rider to credit customers for the recovery of, and return on, the Amos and Mountaineer Plant costs currently included in APCo Virginia base rates.

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 June 2026, the IURC issued an order approving the jurisdictional cost allocation modifications and the $53 million over-earnings customer credit. See “Indiana Earnings Test” section of Note 4 for additional information.

Mitchell Plant Cooling Tower CPCN Requests

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

In May 2026, intervenors recommended certain modifications to KPCo’s cost recovery proposal or that KPCo’s Mitchell CPCN request be denied. A hearing was held at the KPSC in July 2026 and a KPSC decision is expected in the fourth quarter of 2026.

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

In July 2026, WVPSC staff submitted testimony recommending that WPCo’s Mitchell CPCN be approved with certain modifications to WPCo’s proposed cost recovery, while intervenors submitted testimony that did not offer an opinion as to whether WPCo’s Mitchell CPCN should be approved and recommended adjustments to WPCo’s cost recovery if WPCo’s Mitchell CPCN is approved. A hearing at the WVPSC is scheduled for September 2026 and an order from the WVPSC is expected in the fourth quarter of 2026.

As of June 30, 2026, the net book value of Mitchell Plant Unit 2, before cost of removal and including CWIP and inventory, is estimated to be approximately $643 million ($383 million at WPCo and $260 million at KPCo). If AEP cannot ultimately recover Mitchell Plant Unit 2 costs, it would reduce future net income and cash flows and impact financial condition.

Indiana House Enrolled Act 1002

On February 26, 2026, House Enrolled Act 1002 (HEA 1002) was signed into law in Indiana. Among other things, this law requires Indiana’s investor-owned electricity suppliers to petition the IURC for approval of a multi-year rate plan (MYRP). When establishing an electricity supplier’s authorized return for its MYRP, Indiana law requires the IURC to consider any changes in risk to the electricity supplier and its customers that may result from implementing the MYRP.

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In July 2026, the IURC launched investigations into the risks and changes in those risks to the electricity suppliers and customers in Indiana as a result of the electricity supplier implementing an MYRP. The IURC also launched an investigation into the continued use of trackers or riders by electricity suppliers during MYRPs. Technical conferences to discuss these investigations are scheduled for August 2026.

In July 2026, I&M submitted a notice of intent to file an Indiana MYRP with the IURC no later than September 1, 2026. If I&M is not able to recover its costs to serve Indiana retail customers, including a fair return on investments, it could reduce future net income and cash flows and impact financial condition.

Federal Tax Legislation

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

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

Fuel Cell Agreements

In 2025, OPCo signed two contracts totaling approximately 98 MWs for electricity service from fuel cells. The PUCO approved the contracts in May 2025. In September 2025, an intervenor filed a request for rehearing with the Supreme Court of Ohio, opposing the PUCO's approval and claiming that the order was unlawful, anti-competitive, and discriminatory. In June 2026, the appeals were dismissed and the PUCO decisions are now final and non-appealable.

In January 2026, an unregulated subsidiary of AEP executed: (a) an unconditional purchase agreement to acquire a substantial portion of its 1 GW option for solid oxide fuel cells for the development and construction of a fuel cell generation facility for approximately $2.65 billion and (b) a 20 year offtake arrangement with a high investment grade third party customer for 100% of the output of the fuel cell generation facility expected to be located near Cheyenne, Wyoming. The offtake arrangement remains subject to specified conditions, however, in June 2026, the deadline for those conditions was extended by mutual agreement of the parties. Should the revised conditions not be satisfied in December 2026, AEP will be entitled to additional consideration to account for the extended timeline.

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 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. In July 2026, the FERC issued an order accepting the formula rate, subject to settlement proceedings which will determine the companies’ base ROE, cost of debt, formula rate template language and depreciation rates.

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Midcontinent Grid Solutions Investment (Applies to AEP)

In 2025, Transource Energy and an affiliate of Berkshire Hathaway Energy formed Midcontinent Grid Solutions, LLC to participate in MISO’s 2024 Regional Transmission Expansion Plan competitive process. In January 2026, MISO selected the upgrades proposed by Midcontinent Grid Solutions to address forecasted reliability and load growth requirements. The projects awarded by MISO were estimated to cost approximately $1.2 billion and AEP’s share of this investment was estimated to be $500 million. The projects awarded by MISO will be developed, owned and operated by Midcontinent Grid Solutions Wisconsin, LLC (MGS Wisconsin), a subsidiary of Midcontinent Grid Solutions, LLC.

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

As an affiliate of MGS Iowa, MGS Wisconsin is authorized to replicate MGS Iowa’s FERC-approved formula rate. A request was filed in April 2026 and included an additional incentive for the recovery of abandonment costs if the projects are cancelled for reasons beyond MGS Wisconsin’s control. In June 2026, the FERC approved MGS Wisconsin’s request.

NOLCs in Retail Jurisdictions - IRS PLRs

AEP’s utility subsidiaries have made rate filings with state commissions to transition to stand-alone treatment of NOLCs in retail ratemaking. In April 2024, supportive PLRs for certain retail jurisdictions were received from the IRS, effective March 2024. The PLRs concluded NOLCs on a stand-alone ratemaking basis should be included in rate base and in the computation of Excess ADIT regulatory liabilities to be refunded to customers. As of June 30, 2026, there were four jurisdictions awaiting approval and two jurisdictions that have been approved but are subject to refund in their status of transitioning to stand-alone treatment of NOLCs in retail ratemaking. Beginning in the second quarter of 2024 and continuing until the NOLC revenue requirement is in rates, AEP is recognizing additional regulatory assets related to revenue requirement amounts to be collected from customers. As of June 30, 2026, AEP had NOLC regulatory assets of $97 million, of which $85 million are classified as pending final regulatory approval and $12 million are classified as approved for recovery.

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LITIGATION

In the ordinary course of business, AEP is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases that have a probable likelihood of loss if the loss can be estimated.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition. See Note 4 – Rate Matters and Note 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 June 30, 2026, AEP owned generating capacity of approximately 26,500 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. The Federal EPA administration has proposed to revise or repeal portions of those new rules. Management continues to evaluate the impacts of the rules that are currently in effect on the plans for the future of AEP’s generating fleet, in particular, the economic feasibility of making the requisite environmental investments in AEP’s fossil generation fleet. AEP continues to refine the cost estimates of complying with these rules to identify the best alternative for promoting compliance with all of the rules while meeting AEP’s obligations to provide reliable and affordable electricity.

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

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Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states and localities implement and administer many of these programs and could impose additional or more stringent requirements. Primary CAA regulatory programs that continue to drive investments in AEP’s existing generating units include the following: (a) periodic revisions to NAAQS and the development of SIPs to achieve more stringent standards, (b) implementation of the regional haze program by the states and the Federal EPA, (c) regulation of hazardous air pollutant emissions under MATS, (d) implementation and review of CSAPR and (e) the Federal EPA’s regulation of GHG emissions from fossil generation under Section 111 of the CAA. Certain notable developments in significant CAA regulatory requirements affecting AEP’s operations are discussed in the following sections.

National Ambient Air Quality Standards

The Federal EPA periodically reviews and revises the NAAQS for criteria pollutants under the CAA, which in turn may require AEP to make investments in pollution control equipment at existing generating units or change how units are dispatched and operated. In February 2024, the Federal EPA finalized a new more stringent annual primary PM2.5 standard.

Areas with air quality that does not meet the new standard will be designated by the Federal EPA as “nonattainment,” which will trigger an obligation for states to revise their SIPs. In November 2025, in connection with pending litigation challenging the new standards, the Federal EPA filed a motion asking the court to vacate the stricter PM2.5 standard. In June 2026, the United States Court of Appeals for the District of Columbia Circuit denied the request.

If the rule is not vacated by any further legal challenge, states must revise SIPs to attain the new standard. Areas around some of AEP’s generating facilities may be deemed nonattainment, which may require additional pollution controls or the implementation of operational constraints. At this time, management cannot reasonably estimate any impacts on AEP’s operations, cash flows, net income or financial condition.

Regional Haze

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

The Federal EPA disapproved portions of the Texas regional haze SIP and finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NOX regional haze obligations for electric generating units in Texas. Additionally, the Federal EPA finalized an intrastate SO2 emissions trading program based on CSAPR allowance allocations. Environmental groups filed challenges to these various rulemakings in district courts in the Fifth Circuit and the District of Columbia Circuit. Management cannot predict the outcome of that litigation, although management supports the intrastate trading program as a compliance alternative to source-specific controls and intervened in the Fifth Circuit litigation in support of the Federal EPA. In July 2024, the 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. In August 2023, a FIP (the Good Neighbor Plan) went into effect that further revised the ozone season NOX budgets under the existing CSAPR ozone season program in states to which the FIP applies. The FIP was the subject of judicial review in the United States Court of Appeals for the District of Columbia Circuit and has since been administratively stayed pending the Supreme Court lifting its June 2024 order staying enforcement of the Good Neighbor Plan, other courts lifting judicial orders staying the Federal EPA SIP disapproval actions as to SIPs submitted by several states, and the Federal EPA taking subsequent rulemaking action consistent with any judicial rulings on the merits. Additionally, in April 2025, the court placed the challenges to the Good Neighbor Plan in abeyance pending further order of the court. The Federal EPA has indicated it intends to propose rulemaking to revise the rule. Management will continue to monitor the litigation and any further actions by the Federal EPA for any potential impact to operations.

Climate Change, CO2 Regulation and Energy Policy

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

Twenty-seven states, numerous companies, trade associations and others challenged the rule. AEP has joined with several other utilities to challenge the rule and has asked the court to stay the rule during the litigation, and the appeals have been consolidated. The court stayed the litigation pending rulemaking by the Federal EPA. In June 2025, the Federal EPA proposed to repeal the GHG emissions standards for fossil-fueled fired electric generating units based on a determination that GHG emissions from power plants do not significantly contribute to air pollution that may endanger public health or the environment. As an alternative, the Federal EPA proposed to eliminate GHG standards for existing coal and gas units and to keep only certain emission limits applicable to new sources. These proposals have not been finalized. In 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 developing energy solutions that align with state and federal policy objectives, customer expectations, and reliability requirements. These energy solutions may include a range of generation and energy resources, depending on the needs and priorities of the jurisdictions. AEP remains committed to evaluating and pursuing generation strategies that support reliability, affordability and long-term energy needs where supported by regulators and customers. As an example, APCo and I&M are seeking early site permits to bring small modular reactors to Virginia and Indiana as part of their evaluation of future generation options. AEP’s performance will ultimately be driven by the needs and desires of the jurisdictions AEP serves and the company will continue to engage with regulators and policymakers to meet the energy needs while facilitating the delivery of reliable, affordable energy.

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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 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 has participated in the rulemaking process.

Should additional corrective measures like groundwater treatment or ash removal be mandated at any of AEP’s coal-fired facilities, AEP could face substantial costs that could materially and adversely affect financial condition, results of operations and cash flows. See “Federal EPA’s Revised CCR Rule” section in Note 5 for additional information.

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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 commit by December 31, 2025 to retire by 2034. Several petitions for review have been filed with various federal courts challenging the 2024 ELG rule. SWEPCo also challenged the rule by filing a joint petition with a utility trade association in which AEP participates. The litigation challenging the ELG Rule is being held in abeyance while the new administration evaluates the rule. The Federal EPA has announced plans to reconsider the standards and deadlines established by the 2024 ELG rule.

In December 2025, the Federal EPA issued the Deadline Extension ELG Rule to extend the compliance deadlines in the 2024 ELG Rule by five years as well as to establish a site-specific mechanism for extending compliance deadlines for both the 2020 and 2024 ELG Rules. The Deadline Extension ELG Rule also extended the deadline to commit to cease coal combustion by 2034 from December 31, 2025 to December 31, 2031. Management is evaluating the compliance alternatives in the rule, taking into consideration the requirements of other rules and their combined impacts to operations. Management cannot predict the outcome of the pending litigation or any further rulemaking actions by the Federal EPA related to the ELG rule.

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

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

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Impact of Environmental Regulation on Coal-Fired Generation

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

For generating facilities retired or planned for retirement in advance of the retirement date currently authorized for ratemaking purposes, with related accelerated depreciation regulatory assets pending regulatory approval, the table below summarizes the net book value and related regulatory asset balances recorded as of June 30, 2026:

Company	Plant	Net Investment (a)		Accelerated Depreciation Regulatory Asset			Actual/Projected Retirement Date		Current Authorized Recovery Period	Annual Depreciation (b)
		(in millions)								(in millions)
PSO	Northeastern Plant, Unit 3	$	53	$	251		2026		(c)	$	11
SWEPCo	Pirkey Plant	—		46		(d)	2023		(e)	—
SWEPCo	Welsh Plant, Units 1 and 3	230		249			2028	(f)	(g)	44

(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. In July 2026, SWEPCo, PUCT staff and certain intervenors filed an unopposed stipulation and settlement agreement with the PUCT agreeing the application for a CCN should be approved. Additionally, in July 2026, SWEPCo and the LPSC staff filed a joint stipulation and term sheet with the LPSC agreeing the application for a CCN should be approved.

(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 and six months ended June 30, 2026 as compared to the three months ended and six months ended June 30, 2025. For AEP’s Vertically Integrated Utilities and Transmission and Distribution Utilities segments and Registrant Subsidiaries within these segments, the results include revenues from rate rider mechanisms designed to recover fuel, purchased power and other recoverable expenses such that the revenues and expenses associated with these items generally offset and do not affect Earnings Attributable to AEP Common Shareholders. For additional information regarding the financial results for the three and six months ended June 30, 2026 and 2025, see the discussions of Results of Operations by Registrant Subsidiary.

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

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2026		2025		2026		2025
	(in millions)
Vertically Integrated Utilities	$	284	$	433	$	746	$	757
Transmission and Distribution Utilities	222		224		459		389
AEP Transmission Holdco	225		578		434		813
Generation & Marketing	97		62		172		164
Corporate and Other	(115)		(71)		(224)		(97)
Earnings Attributable to AEP Common Shareholders	$	713	$	1,226	$	1,587	$	2,026

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.

19

VERTICALLY INTEGRATED UTILITIES

Summary of KWh Energy Sales for Vertically Integrated Utilities

	Three Months Ended  June 30,		Six Months Ended  June 30,
	2026	2025	2026	2025
	(in millions of KWhs)
Retail:
Residential	6,443	6,372	15,316	15,776
Commercial	7,238	6,297	14,065	12,193
Industrial	8,584	8,595	16,582	16,696
Miscellaneous	567	569	1,101	1,102
Total Retail	22,832	21,833	47,064	45,767
Wholesale (a)	3,550	3,443	7,095	8,234
Total KWhs	26,382	25,276	54,159	54,001

(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  June 30,		Six Months Ended  June 30,
	2026	2025	2026	2025
	(in degree days)
Eastern Region
Actual – Heating	88	118	1,663	1,735
Normal – Heating	132	133	1,698	1,700
Actual – Cooling	362	374	381	382
Normal – Cooling	352	348	357	352
Western Region
Actual – Heating	2	21	632	966
Normal – Heating	34	34	911	903
Actual – Cooling	820	772	941	831
Normal – Cooling	742	738	777	771

20

Vertically Integrated Utilities
Reconciliation of 2025 to 2026 Earnings Attributable to AEP Common Shareholders
(in millions)
	Three Months Ended  June 30,		Six Months Ended  June 30,
2025 Earnings Attributable to AEP Common Shareholders	$	433	$	757
Changes in Revenues:
Retail Revenues	168		351
Off-system Sales	(35)		47
Transmission Revenues	(27)		12
Other Revenues	(1)		(3)
Total Change in Revenues	105		407
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	21		21
Other Operation and Maintenance	(74)		(207)
Asset Impairments and Other Related Charges	—		(31)
Depreciation and Amortization	(37)		(81)
Taxes Other Than Income Taxes	(21)		(31)
Other Income	(1)		(2)
Allowance for Equity Funds Used During Construction	5		12
Non-Service Cost Components of Net Periodic Benefit Cost	(12)		(12)
Interest Expense	(62)		(107)
Total Change in Expenses and Other	(181)		(438)
Income Tax Benefit	(73)		20
2026 Earnings Attributable to AEP Common Shareholders	$	284	$	746

Second Quarter of 2026 Compared to Second Quarter of 2025

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

•Retail Revenues increased $168 million primarily due to the following:

•A $179 million increase in base rates and rider revenues.

•A $60 million increase in weather-normalized revenues primarily in the commercial and industrial classes.

These increases were partially offset by:

•A $48 million decrease in fuel revenues primarily due to decreases at APCo and SWEPCo, partially offset by an increase at I&M.

•A $23 million decrease at SWEPCo due to a probable credit to certain existing wholesale generation customers.

•Off-system Sales decreased $35 million primarily due to Rockport Plant, Unit 2 merchant sales and economic hedging activity at I&M.

•Transmission Revenues decreased $27 million primarily due to the following:

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

This decrease was partially offset by:

• A $32 million increase due to continued transmission investment.

21

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $21 million primarily due to decreases at APCo and SWEPCo, partially offset by increases at I&M and PSO.

•Other Operation and Maintenance expenses increased $74 million primarily due to the following:

•A $41 million increase in generation expenses due to non-outage maintenance, nuclear and renewable energy.

•A $24 million increase in distribution-related expenses driven by system improvements, forestry, storms, customer driven third-party work and amortization of storm-related regulatory assets.

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

•Depreciation and Amortization expenses increased $37 million primarily due to the following:

•A $31 million increase due to a higher depreciable base at I&M, PSO and SWEPCo.

•A $10 million increase at KPCo primarily due to the amortization of securitized assets and PPA rider activity.

These increases were partially offset by:

•A $7 million decrease at APCo primarily due to a decrease in depreciation expense at Amos and Mountaineer plants due to the issuance of Virginia securitization bonds.

•Taxes Other Than Income Taxes increased $21 million primarily due to the following:

•A $10 million increase at SWEPCo and I&M primarily due to an increase in property taxes.

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

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

•Non-Service Cost Components of Net Periodic Benefit Cost increased $12 million primarily due to the continued recognition of unfavorable 2022 pension plan asset returns used to calculate the 2026 pension expense.

•Interest Expense increased $62 million primarily due to higher long-term debt balances.

•Income Tax Benefit decreased $73 million primarily due to the following:

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

•A $7 million decrease due to a decrease in flow-through cost of removal.

These decreases were partially offset by:

•A $39 million increase due to an increase in PTCs.

•A $15 million increase due to a decrease in pretax book income.

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025

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

•Retail Revenues increased $351 million primarily due to the following:

•A $371 million increase in base case and rider revenues.

•A $112 million increase in weather-normalized revenues primarily in the commercial and industrial classes, partially offset by a decrease in the residential class.

•A $15 million increase due to a decrease in regulatory provisions for refund at I&M.

These increases were partially offset by:

•A $104 million decrease in fuel revenues primarily due to decreases at APCo and SWEPCo, partially offset by an increase at I&M.

•A $27 million decrease in weather-related usage primarily in the residential class driven by a 15% decrease in heating degree days primarily in the western region.

•A $23 million decrease at SWEPCo due to a probable credit to certain existing wholesale generation customers.

•Off-system Sales increased $47 million primarily due to Rockport Plant, Unit 2 merchant sales during Winter Storm Fern in January 2026, partially offset by a decrease in merchant sales and economic hedging activity at I&M.

•Transmission Revenues increased $12 million primarily due to the following:

• A $60 million increase due to continued transmission investment.

This increase was partially offset by:

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

22

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $21 million primarily due to decreases at APCo and SWEPCo, partially offset by increases at I&M and PSO.

•Other Operation and Maintenance expenses increased $207 million primarily due to the following:

•A $74 million increase in generation expenses due to outage and non-outage maintenance, nuclear and renewable energy.

•A $34 million increase in vegetation management costs.

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

•A $25 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.

•A $21 million increase in storm expenses.

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

•Depreciation and Amortization expenses increased $81 million primarily due to the following:

•A $52 million increase primarily due to a higher depreciable base at I&M, PSO and SWEPCo.

•A $10 million increase at KPCo primarily due to the amortization of securitized assets.

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

•A $7 million increase at SWEPCo primarily due to higher over-recovery of costs and allowable return associated with the generation rider.

These increases were partially offset by:

•A $6 million decrease at I&M due to Michigan PTC deferral activity.

•Taxes Other Than Income Taxes increased $31 million primarily due to the following:

•A $19 million increase in property taxes at APCo, PSO and SWEPCo.

•An $8 million increase due to higher business and occupation taxes at APCo.

•Allowance for Equity Funds Used During Construction increased $12 million primarily due to a higher AFUDC base and an increase in equity return rates primarily at I&M, SWEPCo and KPCo.

•Non-Service Cost Components of Net Periodic Benefit Cost increased $12 million primarily due to the continued recognition of unfavorable 2022 pension plan asset returns used to calculate the 2026 pension expense.

•Interest Expense increased $107 million primarily due to the following:

•An $82 million increase primarily due to higher long-term debt balances.

•A $10 million increase at PSO and SWEPCo due to a prior year deferral of expenses as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking.

•A $5 million increase at SWEPCo related to the Texas tax normalization rider amortization.

•Income Tax Benefit increased $20 million primarily due to the following:

•A $112 million increase due to an increase in PTCs.

•A $24 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 $114 million decrease due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

23

TRANSMISSION AND DISTRIBUTION UTILITIES

Summary of KWh Energy Sales for Transmission and Distribution Utilities

	Three Months Ended  June 30,		Six Months Ended  June 30,
	2026	2025	2026	2025
	(in millions of KWhs)
Retail:
Residential	6,119	6,299	12,651	13,310
Commercial	12,961	11,042	25,738	20,630
Industrial	8,104	7,048	14,976	13,804
Miscellaneous	171	172	337	344
Total Retail (a)	27,355	24,561	53,702	48,088
Wholesale (b)	256	464	899	1,131
Total KWhs	27,611	25,025	54,601	49,219

(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  June 30,		Six Months Ended  June 30,
	2026	2025	2026	2025
	(in degree days)
Eastern Region
Actual – Heating	132	170	1,996	2,077
Normal – Heating	172	173	1,991	1,993
Actual – Cooling	309	336	321	342
Normal – Cooling	325	323	328	325
Western Region
Actual – Heating	1	4	144	296
Normal – Heating	4	4	215	208
Actual – Cooling	900	992	1,124	1,153
Normal – Cooling	919	909	1,035	1,021

24

Transmission and Distribution Utilities
Reconciliation of 2025 to 2026 Earnings Attributable to AEP Common Shareholders
(in millions)
	Three Months Ended  June 30,		Six Months Ended  June 30,
2025 Earnings Attributable to AEP Common Shareholders	$	224	$	389
Changes in Revenues:
Retail Revenues	102		135
Off-system Sales	(7)		18
Transmission Revenues	33		53
Other Revenues	6		10
Total Change in Revenues	134		216
Changes in Expenses and Other:
Purchased Electricity for Resale	17		13
Purchased Electricity from AEP Affiliates	(1)		(5)
Other Operation and Maintenance	(114)		(117)
Depreciation and Amortization	(9)		(23)
Taxes Other Than Income Taxes	(31)		(26)
Other Income	—		(1)
Allowance for Equity Funds Used During Construction	9		15
Non-Service Cost Components of Net Periodic Benefit Cost	(3)		2
Interest Expense	(18)		(11)
Total Change in Expenses and Other	(150)		(153)
Income Tax Expense	14		8
Equity Earnings of Unconsolidated Subsidiary	—		(1)
2026 Earnings Attributable to AEP Common Shareholders	$	222	$	459

Second Quarter of 2026 Compared to Second Quarter of 2025

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

•Retail Revenues increased $102 million primarily due to the following:

•A $94 million increase in rider revenues in Ohio and Texas.

•An $11 million increase in weather-normalized revenues primarily in the commercial class in Texas.

These increases were partially offset by:

•A $7 million decrease in weather-related usage primarily due to a 9% decrease in cooling degree days in Texas.

•Off-system Sales decreased $7 million primarily due to decreased sales of OVEC purchased power driven by lower market prices.

•Transmission Revenues increased $33 million primarily due to continued transmission investments in Ohio and Texas.

•Other Revenues increased $6 million primarily due to the taxable portion of payments received from customers for large interconnection projects in Texas.

25

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

•Purchased Electricity for Resale expenses decreased $17 million primarily due to the following:

•A $23 million decrease in OVEC purchased power costs in Ohio.

This decrease was partially offset by:

•A $7 million increase in recoverable auction purchases to serve SSO customers in Ohio.

•Other Operation and Maintenance expenses increased $114 million primarily due to the following:

•A $75 million increase primarily due to recoverable PJM transmission expenses in Ohio.

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

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

•A $6 million increase primarily due to recoverable distribution vegetation management expenses in Ohio.

•Depreciation and Amortization expenses increased $9 million primarily due to a higher depreciable base in Texas.

•Taxes Other Than Income Taxes increased $31 million primarily due to the following:

•A $23 million increase in property taxes in Ohio.

•A $5 million increase in state excise taxes due to increased billed KWhs in Ohio.

•Allowance for Equity Funds Used During Construction increased $9 million primarily due to a higher AFUDC base in Texas.

•Interest Expense increased $18 million primarily due to higher long-term debt balances in Texas.

•Income Tax Expense decreased $14 million primarily due to Excess ADIT credits refunded to customers as approved in the 2025 Ohio base rate case.

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025

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

•Retail Revenues increased $135 million primarily due to the following:

•An $82 million increase in rider revenues in Ohio and Texas.

•A $60 million increase due to higher prices for purchased power to serve OPCo’s SSO customers.

•A $24 million increase in weather-normalized revenues primarily in the residential class in Ohio and commercial class in Texas.

These increases were partially offset by:

•A $40 million decrease in weather-related usage primarily driven by a 6% decrease in cooling degree days in Ohio and a 3% decrease in cooling degree days in Texas.

•Off-system Sales increased $18 million primarily due to increased sales of OVEC purchased power driven by higher market prices and volume in Ohio.

•Transmission Revenues increased $53 million primarily due to continued transmission investment in Ohio and Texas.

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

•A $15 million increase primarily due to the taxable portion of payments received from customers for large interconnection projects in Texas.

This increase was partially offset by:

•A $6 million decrease primarily due to lower third-party Legacy Generation Resource Rider revenues related to the recovery of OVEC costs in Ohio.

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

•Purchased Electricity for Resale expenses decreased $13 million primarily due to the following:

•A $44 million decrease as a result of legislation approved in Ohio in 2025 related to the elimination of OPCo’s ability to recover from, or refund to, customers the difference between purchased power expenses from OVEC.

•A $30 million decrease in OVEC purchased power costs in Ohio.

These decreases were partially offset by:

•A $58 million increase in recoverable auction purchases to serve SSO customers in Ohio.

•Purchased Electricity from AEP Affiliates expenses increased $5 million primarily due to an increase in recoverable purchases to serve SSO customers in Ohio.

•Other Operation and Maintenance expenses increased $117 million primarily due to the following:

•A $50 million increase in recoverable PJM transmission expenses in Ohio.

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

•A $15 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.

•A $14 million increase primarily due to recoverable distribution vegetation management expenses in Ohio.

26

•An $11 million increase in recoverable transmission storm restoration costs and vegetation management expenses in Ohio.

•Depreciation and Amortization expenses increased $23 million due to the following:

•An $18 million increase due to a higher depreciable base in Texas.

•A $13 million increase 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.

These increases were partially offset by:

•A $7 million decrease primarily due to the amortization of regulatory liabilities related to Transition Funding customer refunds in Texas.

•Taxes Other Than Income Taxes increased $26 million due to the following:

•An $18 million increase in property taxes in Ohio.

•A $7 million increase in state excise taxes due to increased billed KWhs in Ohio.

•Allowance for Equity Funds Used During Construction increased $15 million primarily due to a higher AFUDC base in Texas.

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

•A $24 million increase due to higher long-term debt balances in Texas.

This increase was partially offset by:

•An $8 million decrease due to an increase in the debt component of AFUDC in Texas.

•A $6 million decrease due to the deferral of eligible costs related to the UTM in Texas.

•Income Tax Expense decreased $8 million primarily due to the following:

•An $18 million decrease primarily due to Excess ADIT credits refunded to customers as approved in the 2025 Ohio base rate case.

This decrease was partially offset by:

•A $13 million increase due to an increase in pretax book income.

27

AEP TRANSMISSION HOLDCO

Summary of Investment in Transmission Assets for AEP Transmission Holdco

	June 30,
	2026		2025
	(in millions)
Plant in Service	$	18,223	$	16,496
Construction Work in Progress	2,833		2,371
Accumulated Depreciation and Amortization	2,132		1,810
Total Transmission Property, Net	$	18,924	$	17,057

AEP Transmission Holdco
Reconciliation of 2025 to 2026
Earnings Attributable to AEP Members from AEP Transmission Holdco
(in millions)
	Three Months Ended  June 30,		Six Months Ended  June 30,
2025 Earnings Attributable to AEP Members from AEP Transmission Holdco	$	578	$	813
Changes in Transmission Revenues:
Transmission Revenues	(147)		(91)
Total Change in Transmission Revenues	(147)		(91)
Changes in Expenses and Other:
Other Operation and Maintenance	(11)		(27)
Depreciation and Amortization	(9)		(24)
Taxes Other Than Income Taxes	(9)		(24)
Interest and Investment Income	—		2
Allowance for Equity Funds Used During Construction	4		4
Non-Service Cost Components of Net Periodic Pension Cost	(1)		(1)
Interest Expense	(9)		(21)
Total Change in Expenses and Other	(35)		(91)
Income Tax Expense	(202)		(202)
Equity Earnings of Unconsolidated Subsidiaries	2		3
Net Income Attributable to Noncontrolling Interests	29		2
2026 Earnings Attributable to AEP Members from AEP Transmission Holdco	$	225	$	434

Second Quarter of 2026 Compared to Second Quarter of 2025

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

•Transmission Revenues decreased $147 million primarily due to the following:

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

This decrease was partially offset by:

•A $67 million increase due to continued transmission investment.

28

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

•Other Operation and Maintenance expenses increased $11 million primarily due to an increase in employee-related costs, vegetation management expenses, affiliated rent expense and other miscellaneous expenses.

•Depreciation and Amortization expenses increased $9 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $9 million due to higher property taxes driven by higher transmission investment.

•Interest Expense increased $9 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $202 million primarily due to the following:

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

This increase was partially offset by:

•A $38 million decrease due to a decrease in pretax book income.

•Net Income Attributable to Noncontrolling Interests decreased $29 million primarily due to the following:

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

This decrease was partially offset by:

•A $25 million increase primarily due to the Midwest Transmission Holdings noncontrolling interest transaction that closed in June 2025.

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025

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

•Transmission Revenues decreased $91 million primarily due to the following:

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

This decrease was partially offset by:

•A $123 million increase due to continued transmission investment.

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

•Other Operation and Maintenance expenses increased $27 million primarily due to an increase in employee-related costs, vegetation management expenses, affiliated rent expense and other miscellaneous expenses.

•Depreciation and Amortization expenses increased $24 million due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $24 million primarily due to higher property taxes driven by increased investment.

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

•Income Tax Expense increased $202 million primarily due to the following:

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

This increase was partially offset by:

•A $38 million decrease due to a decrease in pretax book income.

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

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

This decrease was partially offset by:

•A $52 million increase primarily due to the Midwest Transmission Holdings noncontrolling interest transaction that closed in June 2025.

29

GENERATION & MARKETING

Reconciliation of 2025 to 2026 Earnings Attributable to AEP Common Shareholders
(in millions)
	Three Months Ended  June 30,		Six Months Ended  June 30,
2025 Earnings Attributable to AEP Common Shareholders	$	62	$	164
Changes in Revenues:
Retail, Trading and Marketing	94		268
Merchant Generation	35		44
Other Revenues	14		36
Total Change in Revenues	143		348
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(95)		(366)
Other Operation and Maintenance	(6)		15
Depreciation and Amortization	—		(1)
Interest and Investment Income	4		9
Non-Service Cost Components of Net Periodic Benefit Cost	—		(1)
Interest Expense	—		1
Total Change in Expenses and Other	(97)		(343)
Income Tax Expense	(11)		3
2026 Earnings Attributable to AEP Common Shareholders	$	97	$	172

Second Quarter of 2026 Compared to Second Quarter of 2025

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

•Retail, Trading and Marketing increased $94 million primarily due to higher market prices in 2026 and MTM hedging gains.

•Merchant Generation increased $35 million primarily due to higher realized prices in 2026.

•Other Revenues increased $14 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 $95 million primarily due to an increase in energy costs in 2026.

•Other Operation and Maintenance expenses increased $6 million primarily due to lower renewable contract restructuring and termination proceeds in 2026.

•Income Tax Expense increased $11 million primarily due to an increase in pretax book income.

30

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025

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

•Retail, Trading and Marketing increased $268 million primarily due to higher market prices in 2026, partially offset by reduced MTM hedging gains.

•Merchant Generation increased $44 million primarily due to higher realized prices in 2026.

•Other Revenues increased $36 million primarily due to continued progress on projects in 2026.

Expenses and Other changed between years as follows:

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $366 million primarily due to an increase in energy costs in 2026.

•Other Operation and Maintenance expenses decreased $15 million primarily due to renewable contract restructuring and termination proceeds in 2026.

•Interest and Investment Income increased $9 million primarily due to an increase in interest income due to higher advances to affiliates.

31

CORPORATE AND OTHER

Second Quarter of 2026 Compared to Second Quarter of 2025

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $71 million in 2025 to a loss of $115 million in 2026 primarily due to:

•A $31 million decrease in Income Tax Benefit primarily due to the following:

•A $25 million decrease due to an increase in state taxes.

•A $5 million decrease due to a decrease in PTCs.

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

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $97 million in 2025 to a loss of $224 million in 2026 primarily due to:

•A $51 million decrease in Income Tax Benefit primarily due to the following:

•A $37 million decrease due to a decrease in PTCs.

•A $26 million decrease due to an increase in state taxes.

These decreases were partially offset by:

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

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

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

AEP CONSOLIDATED INCOME TAXES

Second Quarter of 2026 Compared to Second Quarter of 2025

Income Tax Expense increased $303 million primarily due to:

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

•A $21 million increase due to an increase in state taxes.

These increases were partially offset by:

•A $50 million decrease due to a decrease in pretax book income.

•A $34 million decrease due to an increase in PTCs.

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025

Income Tax Expense increased $222 million primarily due to the following:

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

•A $20 million increase due to an increase in state taxes.

These increases were partially offset by:

•A $75 million decrease due to an increase in PTCs.

•A $46 million decrease due to a decrease in pretax book income.

•A $24 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 $14 million decrease due to an increase in amortization of Excess ADIT.

32

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

	June 30, 2026				December 31, 2025
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	50,808	59.0	%	$	47,322	58.4	%
Short-term Debt	2,028		2.4		1,508		1.9
Total Debt	52,836		61.4		48,830		60.3
AEP Common Equity	32,079		37.2		31,138		38.4
Noncontrolling Interests	1,210		1.4		1,080		1.3
Total Debt and Equity Capitalization	$	86,125	100.0	%	$	81,048	100.0	%

AEP’s ratio of debt-to-total capital increased from 60.3% to 61.4% as of December 31, 2025 and June 30, 2026, respectively, primarily due to an increase in long-term debt to support AEP’s capital investment plan in addition to working capital needs.

Liquidity

Liquidity, or access to cash, is an important factor in determining AEP’s financial stability.  Management believes AEP has adequate liquidity for the next twelve months and for the foreseeable future.  As of June 30, 2026, AEP had $8 billion of revolving credit facilities to support its commercial paper program.  Additional liquidity is available from cash from operations and a receivables securitization agreement.  Management is committed to maintaining adequate liquidity.  AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of long-term debt, long-term asset securitizations, leasing agreements, hybrid securities or common stock. AEP and its utilities finance its operations with commercial paper and other variable rate instruments that are subject to fluctuations in interest rates. To the extent that there is an increase in interest rates, it could reduce future net income and cash flows and impact financial condition. In addition, market volatility and reduced liquidity in the financial markets could affect AEP’s ability to raise capital on reasonable terms to fund capital needs, including construction costs and refinancing maturing indebtedness.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments.  As of June 30, 2026, available liquidity was approximately $7.3 billion as illustrated in the table below:

		Amount		Maturity
Commercial Paper:		(in millions)
	Revolving Credit Facility	$	6,500	April 2031
	Revolving Credit Facility	1,500		April 2029
Cash and Cash Equivalents		375
Total Liquidity Sources		8,375
Less:	AEP Commercial Paper Outstanding	1,125
Net Available Liquidity		$	7,250

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 six months of 2026 was $2.1 billion.  The weighted-average interest rate for AEP’s commercial paper for the six months ended June 30, 2026 was 3.93%.

33

Other Credit Facilities

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under seven uncommitted facilities totaling $850 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of June 30, 2026 was $535 million with maturities ranging from July 2026 to June 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 June 30, 2026, the affiliated utility subsidiaries were in compliance with all requirements under the agreement.

Debt Covenants and Borrowing Limitations

AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%.  The method for calculating outstanding debt and capitalization is contractually defined in AEP’s credit agreements.  Debt as defined in the revolving credit agreement excludes securitization bonds and debt of AEP Credit. As of June 30, 2026, this contractually defined percentage was 52.4%. 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 July 2026. Future dividends may vary depending upon AEP’s profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. Management does not believe these restrictions will have any significant impact on its ability to access cash to meet the payment of dividends on its common stock. See “Dividend Restrictions” section of Note 12 for additional information.

Credit Ratings

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

34

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.

	Six Months Ended  June 30,
	2026		2025
	(in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	$	268	$	246
Net Cash Flows from Operating Activities	3,421		2,671
Net Cash Flows Used for Investing Activities	(6,602)		(5,347)
Net Cash Flows from Financing Activities	3,360		2,709
Net Increase in Cash, Cash Equivalents and Restricted Cash	179		33
Cash, Cash Equivalents and Restricted Cash at End of Period	$	447	$	279

Operating Activities

	Six Months Ended  June 30,
	2026		2025
	(in millions)
Net Income	$	1,650	$	2,091
Non-Cash Adjustments to Net Income (a)	2,035		1,519
Mark-to-Market of Risk Management Contracts	(123)		(241)
Pension Contributions to Qualified Plan Trust	—		(95)
Property Taxes	238		241
Deferred Fuel Over/Under-Recovery, Net	31		(41)
Change in Other Noncurrent Assets	(628)		(440)
Change in Other Noncurrent Liabilities	581		41
Change in Certain Components of Working Capital	(363)		(404)
Net Cash Flows from Operating Activities	$	3,421	$	2,671

(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 $750 million primarily due to the following:

•A $540 million increase in cash from Change in Other Noncurrent Liabilities. This increase is primarily due to an increase in security deposits held for customers and changes in regulatory liabilities driven by timing differences in refunds to customers under rate rider mechanisms.

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

•A $75 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.

•A $24 million increase in cash due to changes in risk management contract collateral positions.

35

Investing Activities

	Six Months Ended  June 30,
	2026		2025
	(in millions)
Construction Expenditures	$	(5,606)	$	(4,020)
Acquisitions of Generation Facilities	(1,315)		(1,359)
Acquisitions of Nuclear Fuel	(51)		(45)
Contribution in Aid of Construction Advances	425		106
Other	(55)		(29)
Net Cash Flows Used for Investing Activities	$	(6,602)	$	(5,347)

Net Cash Flows Used for Investing Activities increased by $1.3 billion primarily due to the following:

•A $1.6 billion increase in Construction Expenditures primarily due to increases in Transmission and Distribution Utilities of $698 million and Vertically Integrated Utilities of $506 million.

This increase was partially offset by:

•A $319 million decrease due to higher contributions in aid of construction primarily due to increases in Transmission and Distribution Utilities of $208 million and AEP Transmission Holdco of $115 million.

Financing Activities

	Six Months Ended  June 30,
	2026		2025
	(in millions)
Issuance of Common Stock	$	405	$	132
Issuance/Retirement of Debt, Net	3,987		817
Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs	—		2,783
Dividends Paid on Common Stock	(1,039)		(999)
Other	7		(24)
Net Cash Flows from Financing Activities	$	3,360	$	2,709

Net Cash Flows from Financing Activities increased by $651 million primarily due to the following:

•A $1.9 billion increase in issuances of long-term debt. See Note 12 - Financing Activities for additional information.

•A $1.5 billion increase due to changes in short-term debt.

•A $273 million increase in issuances of common stock primarily under AEP’s ATM Program. See Note 12 - Financing Activities for additional information.

These increases in cash were partially offset by:

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

•A $254 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 June 30, 2026 through July 30, 2026, the date that the second quarter Form 10-Q was filed.

36

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.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

37

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2026 and 2025

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

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2026		2025		2026		2025
REVENUES
Vertically Integrated Utilities	$	3,050	$	2,934	$	6,415	$	6,020
Transmission and Distribution Utilities	1,568		1,443		3,162		2,958
Generation & Marketing	693		552		1,624		1,282
Other Revenues	134		158		264		290
TOTAL REVENUES	5,445		5,087		11,465		10,550
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	1,603		1,541		3,721		3,394
Other Operation	814		538		1,564		1,290
Maintenance	444		390		855		709
Asset Impairments and Other Related Charges	—		—		31		—
Depreciation and Amortization	910		854		1,817		1,687
Taxes Other Than Income Taxes	427		365		870		787
TOTAL EXPENSES	4,198		3,688		8,858		7,867
OPERATING INCOME	1,247		1,399		2,607		2,683
Other Income (Expense):
Other Income	14		15		20		23
Allowance for Equity Funds Used During Construction	75		57		145		114
Non-Service Cost Components of Net Periodic Benefit Cost	19		35		57		70
Interest Expense	(585)		(489)		(1,137)		(984)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS	770		1,017		1,692		1,906
Income Tax Expense (Benefit)	52		(251)		96		(126)
Equity Earnings of Unconsolidated Subsidiaries	29		21		54		59
NET INCOME	747		1,289		1,650		2,091
Net Income Attributable to Noncontrolling Interests	34		63		63		65
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	713	$	1,226	$	1,587	$	2,026
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	544,163,341		534,283,554		543,127,062		533,839,985
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1.31	$	2.29	$	2.92	$	3.80
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	550,628,111		536,425,635		548,846,865		535,547,029
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1.30	$	2.29	$	2.89	$	3.78
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

38

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2026		2025		2026		2025
Net Income	$	747	$	1,289	$	1,650	$	2,091
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $6 and $(9) for the Three Months Ended June 30, 2026 and 2025, Respectively, and $2 and $(3) for the Six Months Ended June 30, 2026 and 2025, Respectively	22		(33)		7		(10)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1 and $0 for the Three Months Ended June 30, 2026 and 2025, Respectively, and $1 and $0 for the Six Months Ended June 30, 2026 and 2025, Respectively	1		—		2		1
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	23		(33)		9		(9)
TOTAL COMPREHENSIVE INCOME	770		1,256		1,659		2,082
Total Comprehensive Income Attributable To Noncontrolling Interests	34		63		63		65
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	736	$	1,193	$	1,596	$	2,017
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

39

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	AEP Common Shareholders
	Common Stock								Accumulated Other Comprehensive Income (Loss)
	Shares	Amount		Paid-in Capital		Retained Earnings					Noncontrolling Interests		Total
TOTAL EQUITY – DECEMBER 31, 2024	534	$	3,472	$	9,606	$	13,869		$	(3)	$	42	$	26,986
Issuance of Common Stock	1	7		68									75
Common Stock Dividends						(500)		(a)			(1)		(501)
Other Changes in Equity				(22)									(22)
Net Income						800					2		802
Other Comprehensive Income									24				24
TOTAL EQUITY – MARCH 31, 2025	535	3,479		9,652		14,169			21		43		27,364
Issuance of Common Stock	1	4		53									57
Common Stock Dividends						(499)		(a)			(1)		(500)
Other Changes in Equity				8									8
Midwest Transmission Holdings Noncontrolling Interest Transaction				1,791							992		2,783
Net Income						1,226					63		1,289
Other Comprehensive Loss									(33)				(33)
TOTAL EQUITY – JUNE 30, 2025	536	$	3,483	$	11,504	$	14,896		$	(12)	$	1,097	$	30,968
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
Issuance of Common Stock	1	2		45									47
Capital Contributions from Noncontrolling Interest											60		60
Common Stock Dividends						(519)		(b)					(519)
Dividends Paid to Noncontrolling Interest											(54)		(54)
Other Changes in Equity				7									7
Net Income						713					34		747
Other Comprehensive Income									23				23
TOTAL EQUITY – JUNE 30, 2026	546	$	3,546	$	12,499	$	15,989		$	45	$	1,210	$	33,289

(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 106.

40

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2026 and December 31, 2025

(in millions)

(Unaudited)

	June 30,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	375	$	197
Restricted Cash (June 30, 2026 and December 31, 2025 Amounts Include $72 and $71, Respectively, Related to Restoration Funding, Appalachian Consumer Rate Relief Funding, Appalachian Recovery Funding, Storm Recovery Funding and Cost Recovery Funding)	72		71
Other Temporary Investments (June 30, 2026 and December 31, 2025 Amounts Include $220 and $209, Respectively, Related to EIS)	228		220
Accounts Receivable:
Customers	1,266		1,166
Accrued Unbilled Revenues	360		421
Pledged Accounts Receivable – AEP Credit	1,396		1,272
Miscellaneous	70		60
Allowance for Credit Losses	(57)		(52)
Total Accounts Receivable	3,035		2,867
Fuel	606		576
Materials and Supplies	1,183		1,046
Risk Management Assets	533		352
Accrued Tax Benefits	278		85
Regulatory Asset for Under-Recovered Fuel Costs	525		426
Prepayments and Other Current Assets	299		212
TOTAL CURRENT ASSETS	7,134		6,052
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	26,707		28,388
Transmission	43,764		42,557
Distribution	34,626		33,364
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	9,406		8,635
Construction Work in Progress	9,696		7,635
Total Property, Plant and Equipment	124,199		120,579
Accumulated Depreciation and Amortization	27,526		28,205
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	96,673		92,374
OTHER NONCURRENT ASSETS
Regulatory Assets	5,021		4,804
Securitized Assets	2,252		933
Spent Nuclear Fuel and Decommissioning Trusts	5,241		4,916
Goodwill	53		53
Long-term Risk Management Assets	235		265
Operating Lease Assets	642		661
Deferred Charges and Other Noncurrent Assets	4,319		4,402
TOTAL OTHER NONCURRENT ASSETS	17,763		16,034
TOTAL ASSETS	$	121,570	$	114,460
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

41

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

June 30, 2026 and December 31, 2025

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

(Unaudited)

			June 30,		December 31,
			2026		2025
CURRENT LIABILITIES
Accounts Payable			$	3,969	$	3,429
Short-term Debt:
Securitized Debt for Receivables – AEP Credit			900		900
Other Short-term Debt			1,128		608
Total Short-term Debt			2,028		1,508
Long-term Debt Due Within One Year (June 30, 2026 and December 31, 2025 Amounts Include $215 and $207, Respectively, Related to DCC Fuel, Restoration Funding, Appalachian Consumer Rate Relief Funding, Appalachian Recovery Funding, Storm Recovery Funding, Transource Energy and Cost Recovery Funding)			2,821		3,194
Risk Management Liabilities			152		132
Customer Deposits			515		507
Accrued Taxes			1,799		2,002
Accrued Interest			590		544
Obligations Under Operating Leases			94		100
Other Current Liabilities			2,187		1,898
TOTAL CURRENT LIABILITIES			14,155		13,314
NONCURRENT LIABILITIES
Long-term Debt (June 30, 2026 and December 31, 2025 Amounts Include $2,566 and $1,294, Respectively, Related to DCC Fuel, Restoration Funding, Appalachian Consumer Rate Relief Funding, Appalachian Recovery Funding, Storm Recovery Funding, Transource Energy and Cost Recovery Funding)			47,987		44,128
Long-term Risk Management Liabilities			175		178
Deferred Income Taxes			11,485		10,951
Regulatory Liabilities and Deferred Investment Tax Credits			8,622		8,362
Asset Retirement Obligations			3,645		3,556
Employee Benefits and Pension Obligations			267		232
Obligations Under Operating Leases			568		578
Deferred Credits and Other Noncurrent Liabilities			1,313		905
TOTAL NONCURRENT LIABILITIES			74,062		68,890
TOTAL LIABILITIES			88,217		82,204
Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)
Contingently Redeemable Performance Share Awards			64		38
EQUITY
Common Stock – Par Value – $6.50 Per Share:
	2026	2025
Shares Authorized	900,000,000	600,000,000
Shares Issued	545,549,444	542,048,288
(1,186,815 Shares were Held in Treasury as of June 30, 2026 and December 31, 2025, Respectively)			3,546		3,523
Paid-in Capital			12,499		12,138
Retained Earnings			15,989		15,441
Accumulated Other Comprehensive Income (Loss)			45		36
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY			32,079		31,138
Noncontrolling Interests			1,210		1,080
TOTAL EQUITY			33,289		32,218
TOTAL LIABILITIES AND EQUITY			$	121,570	$	114,460
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

42

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	Six Months Ended June 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	1,650	$	2,091
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	1,817		1,687
Deferred Income Taxes	332		(54)
Asset Impairments and Other Related Charges	31		—
Allowance for Equity Funds Used During Construction	(145)		(114)
Mark-to-Market of Risk Management Contracts	(123)		(241)
Pension Contributions to Qualified Plan Trust	—		(95)
Property Taxes	238		241
Deferred Fuel Over/Under-Recovery, Net	31		(41)
Change in Other Noncurrent Assets	(628)		(440)
Change in Other Noncurrent Liabilities	581		41
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(62)		(176)
Fuel, Materials and Supplies	(162)		114
Accounts Payable	408		287
Accrued Taxes, Net	(397)		(469)
Other Current Assets	(27)		11
Other Current Liabilities	(123)		(171)
Net Cash Flows from Operating Activities	3,421		2,671
INVESTING ACTIVITIES
Construction Expenditures	(5,606)		(4,020)
Purchases of Investment Securities	(1,264)		(1,337)
Sales of Investment Securities	1,216		1,311
Acquisitions of Generation Facilities	(1,315)		(1,359)
Acquisitions of Nuclear Fuel	(51)		(45)
Contribution in Aid of Construction Advances	425		106
Other Investing Activities	(7)		(3)
Net Cash Flows Used for Investing Activities	(6,602)		(5,347)
FINANCING ACTIVITIES
Capital Contribution from Noncontrolling Interest	156		—
Issuance of Common Stock	405		132
Issuance of Long-term Debt	5,045		3,163
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	520		(764)
Retirement of Long-term Debt	(1,578)		(1,324)
Redemption of Short-term Debt with Original Maturities Greater than 90 Days	—		(578)
Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs	—		2,783
Dividends Paid on Common Stock	(1,039)		(999)
Dividends Paid to Noncontrolling Interest	(89)		(2)
Other Financing Activities	(60)		(22)
Net Cash Flows from Financing Activities	3,360		2,709
Net Increase in Cash, Cash Equivalents and Restricted Cash	179		33
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	268		246
Cash, Cash Equivalents and Restricted Cash at End of Period	$	447	$	279
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

43

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  June 30,		Six Months Ended  June 30,
	2026	2025	2026	2025
	(in millions of KWhs)
Retail:
Residential	3,167	3,275	5,698	6,191
Commercial	4,710	4,719	9,768	8,818
Industrial	4,377	3,300	7,871	6,670
Miscellaneous	148	147	286	291
Total Retail	12,402	11,441	23,623	21,970

Summary of Heating and Cooling Degree Days

	Three Months Ended  June 30,		Six Months Ended  June 30,
	2026	2025	2026	2025
	(in degree days)
Actual – Heating	1	4	144	296
Normal – Heating	4	4	215	208
Actual – Cooling	900	992	1,124	1,153
Normal – Cooling	919	909	1,035	1,021

44

AEP Texas Inc. and Subsidiaries
Reconciliation of 2025 to 2026
Net Income
(in millions)
	Three Months Ended  June 30,		Six Months Ended  June 30,
2025 Net Income	$	121	$	223
Changes in Revenues:
Retail Revenues	14		(7)
Transmission Revenues	20		33
Other Revenues	6		15
Total Change in Revenues	40		41
Changes in Expenses and Other:
Other Operation and Maintenance	(26)		(22)
Depreciation and Amortization	(13)		(9)
Taxes Other Than Income Taxes	(2)		—
Allowance for Equity Funds Used During Construction	8		15
Non-Service Cost Components of Net Periodic Benefit Cost	1		1
Interest Expense	(17)		(10)
Total Change in Expenses and Other	(49)		(25)
Income Tax Expense	1		(6)
2026 Net Income	$	113	$	233

Second Quarter of 2026 Compared to Second Quarter of 2025

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

•Retail Revenues increased $14 million primarily due to the following:

•A $16 million increase in rider revenues.

•An $11 million increase in weather-normalized revenues primarily in the commercial class.

These increases were partially offset by:

•A $7 million decrease in weather-related usage primarily due to a 9% decrease in cooling degree days.

•A $4 million regulatory refund provision established due to the probable, partial disallowance of UTM deferrals.

•Transmission Revenues increased $20 million primarily due to the following:

•A $21 million increase in transmission investments.

This increase was partially offset by:

•A $4 million regulatory refund provision established due to the probable, partial disallowance of UTM deferrals.

•Other Revenues increased $6 million primarily due to the taxable portion of payments received from customers for large interconnection projects.

Expenses and Other changed between years as follows:

•Other Operation and Maintenance expenses increased $26 million primarily due to the following:

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

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

•Depreciation and Amortization expenses increased $13 million primarily due to a higher depreciable base.

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

•Interest Expense increased $17 million primarily due to higher long-term debt balances.

45

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025

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

•Retail Revenues decreased $7 million primarily due to the following:

•A $20 million decrease in weather-related usage primarily due to a 3% decrease in cooling degree days.

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

•A $4 million regulatory refund provision established due to the probable, partial disallowance of UTM deferrals.

These decreases were partially offset by:

•A $14 million increase in weather-normalized revenues primarily in the residential and commercial classes.

•A $7 million increase in rider revenues.

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

•A $34 million increase in transmission investments.

This increase was partially offset by:

•A $4 million regulatory refund provision established due to the probable, partial disallowance of UTM deferrals.

•Other Revenues increased $15 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:

•Other Operation and Maintenance expenses increased $22 million primarily due to an $18 million increase due to the probable, partial disallowance of regulatory assets associated with the UTM deferrals.

•Depreciation and Amortization expenses increased $9 million primarily due to the following:

•An $18 million increase due to a higher depreciable base.

This increase was partially offset by:

•A $7 million decrease primarily due to the amortization of regulatory liabilities related to Transition Funding customer refunds.

•A $3 million decrease due to the deferral of eligible costs related to the UTM.

•Allowance for Equity Funds Used During Construction increased $15 million primarily due to a higher AFUDC base.

•Interest Expense increased $10 million primarily due to the following:

•A $24 million increase due to higher long-term debt balances.

This increase was partially offset by:

•An $8 million decrease due to an increase in the debt component of AFUDC.

•A $6 million decrease due to the deferral of eligible costs related to the UTM.

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

•A $4 million increase due to a decrease in amortization of Excess ADIT.

•A $3 million increase due to an increase in pretax book income.

46

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2026		2025		2026		2025
REVENUES
Electric Transmission and Distribution	$	560	$	528	$	1,073	$	1,048
Sales to AEP Affiliates	1		2		3		3
Other Revenues	10		1		19		3
TOTAL REVENUES	571		531		1,095		1,054
EXPENSES
Other Operation	194		164		356		330
Maintenance	27		31		51		55
Depreciation and Amortization	120		107		225		216
Taxes Other Than Income Taxes	40		38		85		85
TOTAL EXPENSES	381		340		717		686
OPERATING INCOME	190		191		378		368
Other Income (Expense):
Interest Income	1		1		1		1
Allowance for Equity Funds Used During Construction	20		12		39		24
Non-Service Cost Components of Net Periodic Benefit Cost	6		5		12		11
Interest Expense	(78)		(61)		(144)		(134)
INCOME BEFORE INCOME TAX EXPENSE	139		148		286		270
Income Tax Expense	26		27		53		47
NET INCOME	$	113	$	121	$	233	$	223
The common stock of AEP Texas is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

47

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2026		2025		2026		2025
Net Income	$	113	$	121	$	233	$	223
OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 for Three Months Ended June 30, 2026 and 2025, Respectively, and $0 and $0 for the Six Months Ended June 30, 2026 and 2025, Respectively	—		—		—		(1)
TOTAL COMPREHENSIVE INCOME	$	113	$	121	$	233	$	222
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

48

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2024	$	2,093	$	2,795	$	(3)	$	4,885
Net Income			102				102
Other Comprehensive Loss					(1)		(1)
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2025	2,093		2,897		(4)		4,986
Capital Contribution from Parent	250						250
Net Income			121				121
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2025	$	2,343	$	3,018	$	(4)	$	5,357
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2025	$	2,546	$	3,283	$	(3)	$	5,826
Net Income			120				120
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2026	2,546		3,403		(3)		5,946
Capital Contribution from Parent	1						1
Net Income			113				113
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2026	$	2,547	$	3,516	$	(3)	$	6,060
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

49

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2026 and December 31, 2025

(in millions)

(Unaudited)

	June 30,		December 31,
	2026		2025
CURRENT ASSETS
Restricted Cash (June 30, 2026 and December 31, 2025 Amounts Include $13 and $14, Respectively, Related to Restoration Funding)	$	13	$	14
Advances to Affiliates	7		7
Accounts Receivable:
Customers	244		189
Affiliated Companies	11		15
Accrued Unbilled Revenues	118		101
Total Accounts Receivable	373		305
Materials and Supplies	225		168
Prepayments and Other Current Assets	31		15
TOTAL CURRENT ASSETS	649		509
PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission	8,458		8,229
Distribution	7,200		6,835
Other Property, Plant and Equipment	1,282		1,239
Construction Work in Progress	2,233		1,766
Total Property, Plant and Equipment	19,173		18,069
Accumulated Depreciation and Amortization	2,260		2,205
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	16,913		15,864
OTHER NONCURRENT ASSETS
Regulatory Assets	444		402
Securitized Assets (June 30, 2026 and December 31, 2025 Amounts Include $82 and $94, Respectively, Related to Restoration Funding)	82		94
Operating Lease Assets	49		52
Deferred Charges and Other Noncurrent Assets	222		154
TOTAL OTHER NONCURRENT ASSETS	797		702
TOTAL ASSETS	$	18,359	$	17,075
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

50

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

June 30, 2026 and December 31, 2025

(in millions)

(Unaudited)

	June 30,		December 31,
	2026		2025
CURRENT LIABILITIES
Advances from Affiliates	$	354	$	188
Accounts Payable:
General	595		652
Affiliated Companies	43		60
Long-term Debt Due Within One Year – Nonaffiliated (June 30, 2026 and December 31, 2025 Amounts Include $25 and $25, Respectively, Related to Restoration Funding)	25		75
Accrued Taxes	151		118
Accrued Interest	73		64
Security Deposits	79		87
Contribution in Aid of Construction Advances	223		67
Obligations Under Operating Leases	13		14
Other Current Liabilities	72		93
TOTAL CURRENT LIABILITIES	1,628		1,418
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated (June 30, 2026 and December 31, 2025 Amounts Include $65 and $78, Respectively, Related to Restoration Funding)	7,671		6,941
Deferred Income Taxes	1,522		1,430
Regulatory Liabilities and Deferred Investment Tax Credits	1,253		1,286
Obligations Under Operating Leases	38		40
Deferred Credits and Other Noncurrent Liabilities	187		134
TOTAL NONCURRENT LIABILITIES	10,671		9,831
TOTAL LIABILITIES	12,299		11,249
Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY
Paid-in Capital	2,547		2,546
Retained Earnings	3,516		3,283
Accumulated Other Comprehensive Income (Loss)	(3)		(3)
TOTAL COMMON SHAREHOLDER’S EQUITY	6,060		5,826
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	18,359	$	17,075
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

51

AEP TEXAS INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	Six Months Ended June 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	233	$	223
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	225		216
Deferred Income Taxes	75		36
Allowance for Equity Funds Used During Construction	(39)		(24)
Pension Contributions to Qualified Plan Trust	—		(12)
Property Taxes	(61)		(58)
Change in Other Noncurrent Assets	(93)		(50)
Change in Other Noncurrent Liabilities	70		35
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(45)		(31)
Materials and Supplies	(57)		21
Accounts Payable	72		3
Accrued Taxes, Net	33		15
Other Current Assets	(16)		8
Other Current Liabilities	(37)		(23)
Net Cash Flows from Operating Activities	360		359
INVESTING ACTIVITIES
Construction Expenditures	(1,449)		(863)
Contribution in Aid of Construction Advances	247		35
Other Investing Activities	(2)		(3)
Net Cash Flows Used for Investing Activities	(1,204)		(831)
FINANCING ACTIVITIES
Capital Contribution from Parent	1		250
Issuance of Long-term Debt – Nonaffiliated	741		400
Change in Advances from Affiliates, Net	166		(175)
Retirement of Long-term Debt – Nonaffiliated	(62)		(12)
Other Financing Activities	(3)		(1)
Net Cash Flows from Financing Activities	843		462
Net Decrease in Cash, Cash Equivalents and Restricted Cash	(1)		(10)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	14		24
Cash, Cash Equivalents and Restricted Cash at End of Period	$	13	$	14
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	149	$	125
Construction Expenditures Included in Current Liabilities as of June 30,	357		207
Contributions in Aid of Construction Advances Included in Current Assets as of June 30,	23		—
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

52

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 June 30,
	2026		2025
	(in millions)
Plant In Service	$	17,671	$	16,090
Construction Work in Progress	2,636		2,105
Accumulated Depreciation and Amortization	2,075		1,760
Total Transmission Property, Net	$	18,232	$	16,435

AEP Transmission Company, LLC and Subsidiaries
Reconciliation of 2025 to 2026
Earnings Attributable to AEP Member
(in millions)
	Three Months Ended  June 30,		Six Months Ended  June 30,
2025 Earnings Attributable to AEP Member	$	556	$	767
Changes in Transmission Revenues:
Transmission Revenues	(154)		(103)
Total Change in Transmission Revenues	(154)		(103)
Changes in Expenses and Other:
Other Operation and Maintenance	(11)		(28)
Depreciation and Amortization	(9)		(23)
Taxes Other Than Income Taxes	(10)		(24)
Interest Income	—		2
Allowance for Equity Funds Used During Construction	5		5
Interest Expense	(7)		(17)
Total Change in Expenses and Other	(32)		(85)
Income Tax Expense	(208)		(207)
Net Income Attributable to Noncontrolling Interest	30		3
2026 Earnings Attributable to AEP Member	$	192	$	375

Second Quarter of 2026 Compared to Second Quarter of 2025

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

•Transmission Revenues decreased $154 million primarily due to the following:

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

This decrease was partially offset by:

•A $60 million increase due to continued transmission investment.

53

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

•Other Operation and Maintenance expenses increased $11 million primarily due to an increase in employee-related costs, vegetation management expenses, affiliated rent expense and other miscellaneous expenses.

•Depreciation and Amortization expenses increased $9 million primarily due to a higher depreciable base.

•Taxes Other than Income Taxes increased $10 million primarily due to higher property taxes driven by higher transmission investments.

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

•Interest Expense increased $7 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $208 million primarily due to the following:

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

This increase was partially offset by:

•A $39 million decrease due to a decrease in pretax book income.

•Net Income Attributable to Noncontrolling Interest decreased $30 million primarily due to following:

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

This decrease was partially offset by:

•A $24 million increase due to the Midwest Transmission Holdings noncontrolling interest transaction that closed in June 2025.

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025

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

•Transmission Revenues decreased $103 million primarily due to the following:

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

This decrease was partially offset by:

•A $111 million increase due to continued transmission investment.

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

•Operation and Maintenance expenses increased $28 million primarily due to an increase in employee-related costs, vegetation management expenses, affiliated rent expense and other miscellaneous expenses.

•Depreciation and Amortization expenses increased $23 million due to a higher depreciable base.

•Taxes Other than Income Taxes increased $24 million primarily due to higher property taxes driven by increased transmission investment.

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

•Interest Expense increased $17 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $207 million primarily due to the following:

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

This increase was partially offset by:

•A $40 million decrease due to a decrease in pretax book income.

•Net Income Attributable to Noncontrolling Interest decreased $3 million primarily due to following:

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

This decrease was partially offset by:

•A $52 million increase due to the Midwest Transmission Holdings noncontrolling interest transaction that closed in June 2025.

54

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2026		2025		2026		2025
REVENUES
Transmission Revenues	$	110	$	111	$	220	$	217
Sales to AEP Affiliates	477		470		947		900
(Provision for)/Reversal of - Revenue Refund – Affiliated	(3)		127		(5)		120
(Provision for)/Reversal of - Revenue Refund – Nonaffiliated	(3)		34		(3)		32
Other Revenues	7		—		7		—
TOTAL REVENUES	588		742		1,166		1,269
EXPENSES
Other Operation	45		36		86		65
Maintenance	8		6		18		11
Depreciation and Amortization	128		119		256		233
Taxes Other Than Income Taxes	86		76		174		150
TOTAL EXPENSES	267		237		534		459
OPERATING INCOME	321		505		632		810
Other Income (Expense):
Interest Income – Affiliated	2		2		4		2
Allowance for Equity Funds Used During Construction	26		21		48		43
Interest Expense	(64)		(57)		(129)		(112)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	285		471		555		743
Income Tax Expense (Benefit)	62		(146)		122		(85)
NET INCOME	223		617		433		828
Net Income Attributable to Noncontrolling Interest	31		61		58		61
EARNINGS ATTRIBUTABLE TO AEP MEMBER	$	192	$	556	$	375	$	767
AEPTCo is wholly-owned by AEP Transmission Holdco.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

55

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY

For the Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	Paid-in Capital		Retained Earnings		Noncontrolling Interest		Total
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2024	$	3,101	$	3,850	$	—	$	6,951
Capital Contribution from AEP Member	32						32
Dividends Paid to AEP Member			(42)				(42)
Net Income			211				211
TOTAL MEMBER'S EQUITY – MARCH 31, 2025	3,133		4,019		—		7,152
Capital Contribution from AEP Member	8						8
Dividends Paid to AEP Member			(2,836)				(2,836)
Midwest Transmission Holdings Noncontrolling Interest Transaction	1,791				992		2,783
Net Income			556		61		617
TOTAL MEMBER'S EQUITY – JUNE 30, 2025	$	4,932	$	1,739	$	1,053	$	7,724
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2025	$	4,962	$	1,651	$	1,030	$	7,643
Capital Contribution from AEP Member	233						233
Capital Contribution from Noncontrolling Interest					96		96
Dividends Paid to Noncontrolling Interest					(33)		(33)
Net Income			183		27		210
TOTAL MEMBER'S EQUITY – MARCH 31, 2026	5,195		1,834		1,120		8,149
Capital Contribution from AEP Member	16						16
Capital Contribution from Noncontrolling Interest					31		31
Dividends Paid to AEP Member			(141)				(141)
Dividends Paid to Noncontrolling Interest					(54)		(54)
Net Income			192		31		223
TOTAL MEMBER'S EQUITY – JUNE 30, 2026	$	5,211	$	1,885	$	1,128	$	8,224
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

56

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2026 and December 31, 2025

(in millions)

(Unaudited)

	June 30,		December 31,
	2026		2025
CURRENT ASSETS
Advances to Affiliates	$	222	$	71
Accounts Receivable:
Customers	66		94
Affiliated Companies	177		153
Total Accounts Receivable	243		247
Prepayments and Other Current Assets	31		4
TOTAL CURRENT ASSETS	496		322
TRANSMISSION PROPERTY
Transmission Property	17,085		16,542
Other Property, Plant and Equipment	586		571
Construction Work in Progress	2,636		2,005
Total Transmission Property	20,307		19,118
Accumulated Depreciation and Amortization	2,075		1,915
TOTAL TRANSMISSION PROPERTY – NET	18,232		17,203
OTHER NONCURRENT ASSETS
Regulatory Assets	84		73
Deferred Property Taxes	187		326
Deferred Charges and Other Noncurrent Assets	77		75
TOTAL OTHER NONCURRENT ASSETS	348		474
TOTAL ASSETS	$	19,076	$	17,999
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

57

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND MEMBER’S EQUITY

June 30, 2026 and December 31, 2025

(in millions)

(Unaudited)

	June 30,		December 31,
	2026		2025
CURRENT LIABILITIES
Advances from Affiliates	$	58	$	143
Accounts Payable:
General	805		477
Affiliated Companies	113		164
Long-term Debt Due Within One Year – Nonaffiliated	425		425
Accrued Taxes	536		650
Accrued Interest	48		46
Contribution in Aid of Construction Advances	170		32
Obligations Under Operating Leases	1		1
Other Current Liabilities	15		9
TOTAL CURRENT LIABILITIES	2,171		1,947
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	6,331		6,174
Deferred Income Taxes	1,542		1,481
Regulatory Liabilities	779		708
Obligations Under Operating Leases	1		2
Deferred Credits and Other Noncurrent Liabilities	28		44
TOTAL NONCURRENT LIABILITIES	8,681		8,409
TOTAL LIABILITIES	10,852		10,356
Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)
MEMBER’S EQUITY
Paid-in Capital	5,211		4,962
Retained Earnings	1,885		1,651
TOTAL MEMBER’S EQUITY	7,096		6,613
Noncontrolling Interest	1,128		1,030
TOTAL EQUITY	8,224		7,643
TOTAL LIABILITIES AND EQUITY	$	19,076	$	17,999
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

58

AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	Six Months Ended June 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	433	$	828
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	256		233
Deferred Income Taxes	51		(137)
Allowance for Equity Funds Used During Construction	(48)		(43)
Property Taxes	139		131
Change in Other Noncurrent Assets	(23)		(46)
Change in Other Noncurrent Liabilities	(14)		(152)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	53		(45)
Accounts Payable	(46)		5
Accrued Taxes, Net	(132)		(202)
Other Current Assets	(9)		8
Other Current Liabilities	7		(15)
Net Cash Flows from Operating Activities	667		565
INVESTING ACTIVITIES
Construction Expenditures	(865)		(787)
Change in Advances to Affiliates, Net	(151)		(38)
Contribution in Aid of Construction Advances	135		18
Other Investing Activities	(4)		5
Net Cash Flows Used for Investing Activities	(885)		(802)
FINANCING ACTIVITIES
Capital Contribution from AEP Member	249		40
Capital Contribution from Noncontrolling Interest	127		—
Issuance of Long-term Debt – Nonaffiliated	768		419
Retirement of Long-term Debt – Nonaffiliated	(613)		(90)
Change in Advances from Affiliates, Net	(85)		(37)
Proceeds from the Midwest Transmission Holdings Noncontrolling Interest Transaction, Net of Transaction Costs	—		2,783
Dividends Paid to AEP Member	(141)		(2,878)
Dividends Paid to Noncontrolling Interest	(87)		—
Net Cash Flows from Financing Activities	218		237
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	$	124	$	107
Construction Expenditures Included in Current Liabilities as of June 30,	667		219
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

59

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  June 30,		Six Months Ended  June 30,
	2026	2025	2026	2025
	(in millions of KWhs)
Retail:
Residential	1,976	2,032	5,597	5,686
Commercial	1,443	1,465	2,941	2,965
Industrial	2,173	2,204	4,173	4,280
Miscellaneous	202	208	410	419
Total Retail	5,794	5,909	13,121	13,350
Wholesale (a)	534	576	985	1,303
Total KWhs	6,328	6,485	14,106	14,653

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

Summary of Heating and Cooling Degree Days

	Three Months Ended  June 30,		Six Months Ended  June 30,
	2026	2025	2026	2025
	(in degree days)
Actual – Heating	48	69	1,382	1,433
Normal – Heating	79	80	1,360	1,359
Actual – Cooling	429	417	454	428
Normal – Cooling	394	387	400	393

60

Appalachian Power Company and Subsidiaries
Reconciliation of 2025 to 2026
Net Income
(in millions)
	Three Months Ended  June 30,		Six Months Ended  June 30,
2025 Net Income	$	107	$	272
Changes in Revenues:
Retail Revenues	(40)		(56)
Off-system Sales	2		2
Transmission Revenues	8		22
Other Revenues	(1)		(5)
Total Change in Revenues	(31)		(37)
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	14		57
Other Operation and Maintenance	(12)		(28)
Depreciation and Amortization	7		2
Taxes Other Than Income Taxes	(7)		(13)
Interest Income	(1)		(1)
Allowance for Equity Funds Used During Construction	(2)		(2)
Non-Service Cost Components of Net Periodic Benefit Cost	(2)		(3)
Interest Expense	(9)		(17)
Total Change in Expenses and Other	(12)		(5)
Income Tax Expense	(14)		15
2026 Net Income	$	50	$	245

Second Quarter of 2026 Compared to Second Quarter of 2025

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

•Retail Revenues decreased $40 million primarily due to the following:

•A $46 million decrease in fuel revenues.

•A $14 million decrease in weather-normalized revenues primarily in the residential and commercial classes.

•A $3 million decrease in weather-related usage due to a 30% decrease in heating degree days.

These decreases were partially offset by:

•A $32 million increase in base rate and rider revenues.

•Transmission Revenues increased $8 million primarily due to the following:

•A $13 million increase due to continued transmission investment.

This increase was partially offset by:

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

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $14 million primarily due to the following:

•A $32 million increase in under-recovered deferred fuel regulatory assets primarily driven by lower authorized fuel rates in Virginia.

This decrease was partially offset by:

•A $14 million prior year impact to the West Virginia ENEC as a result of the June 2025 FERC NOLC order.

61

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

•A $13 million increase in distribution expenses primarily due to storm-related expenses.

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

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

•A $3 million increase in administrative and general expenses primarily due to employee-related costs.

These increases were partially offset by:

•A $15 million decrease in transmission expenses due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•Depreciation and Amortization expenses decreased $7 million primarily due to a decrease in depreciation expense at Amos and Mountaineer plants due to the issuance of Virginia securitization bonds.

•Taxes Other Than Income Taxes increased $7 million primarily due to higher business and occupation taxes.

•Interest Expense increased $9 million primarily due to higher long-term debt balances.

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

•A $23 million increase due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

This increase was partially offset by:

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

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025

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

•Retail Revenues decreased $56 million primarily due to the following:

•A $101 million decrease in fuel revenues.

•A $5 million decrease in weather-related usage primarily due to a 4% decrease in heating degree days.

•A $3 million decrease in weather-normalized revenues primarily in the residential and commercial classes.

These decreases were partially offset by:

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

•Transmission Revenues increased $22 million primarily due to the following:

•A $27 million increase due to continued transmission investment.

This increase was partially offset by:

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

•Other Revenues decreased $5 million primarily due to a decrease in sales of renewable energy credits.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $57 million primarily due to the following:

•A $73 million increase in the under-recovered deferred fuel regulatory assets primarily driven by lower authorized fuel rates in Virginia.

This decrease was partially offset by:

•A $14 million prior year impact to the West Virginia ENEC as a result of the June 2025 FERC NOLC order.

•Other Operation and Maintenance expenses increased $28 million primarily due to the following:

•A $27 million increase in distribution expenses primarily due to storm-related expenses.

•A $9 million increase in steam generation expenses primarily due to increased plant maintenance.

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

•A $5 million increase in accretion expense related to AROs and the 2024 Legacy CCR Rule.

These increases were partially offset by:

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

•Depreciation and Amortization expenses decreased $2 million primarily due to the following:

•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.

This decrease was partially offset by:

•A $23 million increase due to the cumulative regulatory deferral true-up for the impact of CAMT expense incurred related to IRS Notice 2026-07 allowing tax repair deductions in the calculation of CAMT.

•Taxes Other Than Income Taxes increased $13 million primarily due to the following:

•An $8 million increase due to higher business and occupation taxes.

•A $4 million increase in property taxes.

62

•Interest Expense increased $17 million primarily due to higher long-term debt balances.

•Income Tax Expense decreased $15 million primarily due to the following:

•An $18 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 $14 million decrease due to an increase in PTCs.

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

These decreases were partially offset by:

•A $23 million increase due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

63

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2026		2025		2026		2025
REVENUES
Electric Generation, Transmission and Distribution	$	833	$	876	$	1,904	$	1,974
Sales to AEP Affiliates	81		66		173		138
Other Revenues	2		5		6		8
TOTAL REVENUES	916		947		2,083		2,120
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	277		291		641		698
Other Operation	203		211		420		433
Maintenance	104		84		203		162
Depreciation and Amortization	164		171		332		334
Taxes Other Than Income Taxes	45		38		92		79
TOTAL EXPENSES	793		795		1,688		1,706
OPERATING INCOME	123		152		395		414
Other Income (Expense):
Interest Income	1		2		2		3
Allowance for Equity Funds Used During Construction	3		5		7		9
Non-Service Cost Components of Net Periodic Benefit Cost	4		6		8		11
Interest Expense	(80)		(71)		(155)		(138)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	51		94		257		299
Income Tax Expense (Benefit)	1		(13)		12		27
NET INCOME	$	50	$	107	$	245	$	272
The common stock of APCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

64

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2026		2025		2026		2025
Net Income	$	50	$	107	$	245	$	272
OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2026 and 2025, Respectively, and $0 and $0 for the Six Months Ended June 30, 2026 and 2025, Respectively	(1)		(1)		(1)		(1)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2026 and 2025, Respectively, and $0 and $0 for the Six Months Ended June 30, 2026 and 2025, Respectively	—		—		—		—
TOTAL OTHER COMPREHENSIVE LOSS	(1)		(1)		(1)		(1)
TOTAL COMPREHENSIVE INCOME	$	49	$	106	$	244	$	271
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

65

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2024	$	260	$	1,945	$	3,532	$	11	$	5,748
Common Stock Dividends					(50)				(50)
Net Income					165				165
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2025	260		1,945		3,647		11		5,863
Capital Contribution from Parent			7						7
Net Income					107				107
Other Comprehensive Loss							(1)		(1)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2025	$	260	$	1,952	$	3,754	$	10	$	5,976
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2025	$	260	$	1,957	$	3,939	$	24	$	6,180
Capital Contribution from Parent			81						81
Net Income					195				195
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2026	260		2,038		4,134		24		6,456
Common Stock Dividends					(700)				(700)
Net Income					50				50
Other Comprehensive Loss							(1)		(1)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2026	$	260	$	2,038	$	3,484	$	23	$	5,805
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

66

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2026 and December 31, 2025

(in millions)

(Unaudited)

	June 30,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	4	$	5
Restricted Cash for Securitized Funding (June 30, 2026 and December 31, 2025 Amounts Include $25 and $18, Respectively, Related to Appalachian Consumer Rate Relief Funding and Appalachian Recovery Funding)	25		18
Advances to Affiliates	17		17
Accounts Receivable:
Customers	223		171
Affiliated Companies	165		142
Accrued Unbilled Revenues	61		112
Allowance for Credit Losses	(2)		(2)
Total Accounts Receivable	447		423
Fuel	245		229
Materials and Supplies	157		139
Risk Management Assets	171		81
Regulatory Asset for Under-Recovered Fuel Costs	163		83
Prepayments and Other Current Assets	58		38
TOTAL CURRENT ASSETS	1,287		1,033
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	5,688		7,886
Transmission	5,339		5,277
Distribution	6,074		5,938
Other Property, Plant and Equipment	1,218		1,175
Construction Work in Progress	878		802
Total Property, Plant and Equipment	19,197		21,078
Accumulated Depreciation and Amortization	5,135		6,365
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	14,062		14,713
OTHER NONCURRENT ASSETS
Regulatory Assets	1,407		1,439
Securitized Assets (June 30, 2026 and December 31, 2025 Amounts Include $1,424 and $78, Respectively, Related to Appalachian Consumer Rate Relief Funding and Appalachian Recovery Funding)	1,424		78
Employee Benefits and Pension Assets	257		251
Operating Lease Assets	97		95
Deferred Charges and Other Noncurrent Assets	175		183
TOTAL OTHER NONCURRENT ASSETS	3,360		2,046
TOTAL ASSETS	$	18,709	$	17,792
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

67

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

June 30, 2026 and December 31, 2025

(Unaudited)

	June 30,		December 31,
	2026		2025
	(in millions)
CURRENT LIABILITIES
Advances from Affiliates	$	126	$	209
Accounts Payable:
General	492		375
Affiliated Companies	122		173
Long-term Debt Due Within One Year – Nonaffiliated (June 30, 2026 and December 31, 2025 Amounts Include $65 and $30, Respectively, Related to Appalachian Consumer Rate Relief Funding and Appalachian Recovery Funding)	1,315		1,131
Customer Deposits	99		94
Accrued Taxes	121		116
Obligations Under Operating Leases	14		15
Other Current Liabilities	297		271
TOTAL CURRENT LIABILITIES	2,586		2,384
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated (June 30, 2026 and December 31, 2025 Amounts Include $1,376 and $62, Respectively, Related to Appalachian Consumer Rate Relief Funding and Appalachian Recovery Funding)	6,120		5,128
Deferred Income Taxes	2,236		2,130
Regulatory Liabilities and Deferred Investment Tax Credits	1,064		1,111
Asset Retirement Obligations	741		707
Employee Benefits and Pension Obligations	26		26
Obligations Under Operating Leases	84		81
Deferred Credits and Other Noncurrent Liabilities	47		45
TOTAL NONCURRENT LIABILITIES	10,318		9,228
TOTAL LIABILITIES	12,904		11,612
Rate Matters (Note 4)
Commitments, Guarantees and Contingencies (Note 5)
COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 30,000,000 Shares
Outstanding – 13,499,500 Shares	260		260
Paid-in Capital	2,038		1,957
Retained Earnings	3,484		3,939
Accumulated Other Comprehensive Income (Loss)	23		24
TOTAL COMMON SHAREHOLDER’S EQUITY	5,805		6,180
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	18,709	$	17,792
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

68

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	Six Months Ended June 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	245	$	272
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	332		334
Deferred Income Taxes	60		(5)
Allowance for Equity Funds Used During Construction	(7)		(9)
Mark-to-Market of Risk Management Contracts	(80)		(73)
Deferred Fuel Over/Under-Recovery, Net	(72)		6
Change in Regulatory Assets	(96)		(117)
Change in Other Noncurrent Assets	(40)		29
Change in Other Noncurrent Liabilities	(19)		6
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(20)		6
Fuel, Materials and Supplies	(34)		38
Accounts Payable	73		(61)
Accrued Taxes, Net	1		(39)
Other Current Assets	(11)		18
Other Current Liabilities	17		(19)
Net Cash Flows from Operating Activities	349		386
INVESTING ACTIVITIES
Construction Expenditures	(497)		(528)
Acquisitions of Assets	(352)		—
Other Investing Activities	36		4
Net Cash Flows Used for Investing Activities	(813)		(524)
FINANCING ACTIVITIES
Capital Contribution from Parent	81		7
Issuance of Long-term Debt – Nonaffiliated	1,364		528
Change in Advances from Affiliates, Net	(83)		78
Retirement of Long-term Debt – Nonaffiliated	(191)		(418)
Principal Payments for Finance Lease Obligations	(2)		(4)
Dividends Paid on Common Stock	(700)		(50)
Other Financing Activities	1		1
Net Cash Flows from Financing Activities	470		142
Net Increase in Cash, Cash Equivalents and Restricted Cash for Securitized Funding	6		4
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	$	29	$	24
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	150	$	134
Noncash Acquisitions Under Finance Leases	3		2
Construction Expenditures Included in Current Liabilities as of June 30,	126		115
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

69

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  June 30,		Six Months Ended  June 30,
	2026	2025	2026	2025
	(in millions of KWhs)
Retail:
Residential	1,102	1,097	2,610	2,650
Commercial	2,341	1,414	4,522	2,686
Industrial	1,812	1,856	3,539	3,604
Miscellaneous	10	9	22	22
Total Retail	5,265	4,376	10,693	8,962
Wholesale (a)	1,884	1,507	3,551	3,943
Total KWhs	7,149	5,883	14,244	12,905

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

Summary of Heating and Cooling Degree Days

	Three Months Ended  June 30,		Six Months Ended  June 30,
	2026	2025	2026	2025
	(in degree days)
Actual – Heating	174	217	2,233	2,335
Normal – Heating	236	237	2,357	2,365
Actual – Cooling	222	280	223	280
Normal – Cooling	284	284	285	285

70

Indiana Michigan Power Company and Subsidiaries
Reconciliation of 2025 to 2026
Net Income
(in millions)
	Three Months Ended  June 30,		Six Months Ended  June 30,
2025 Net Income	$	124	$	182
Changes in Revenues:
Retail Revenues	121		249
Off-system Sales	(38)		44
Transmission Revenues	(16)		(13)
Other Revenues	(4)		(7)
Total Change in Revenues	63		273
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(20)		(76)
Purchased Electricity from AEP Affiliates	8		7
Other Operation and Maintenance	(17)		(50)
Depreciation and Amortization	(9)		(16)
Taxes Other Than Income Taxes	(4)		(2)
Other Income	4		7
Non-Service Cost Components of Net Periodic Benefit Cost	(2)		(3)
Interest Expense	(10)		(18)
Total Change in Expenses and Other	(50)		(151)
Income Tax Expense	(40)		(59)
2026 Net Income	$	97	$	245

Second Quarter of 2026 Compared to Second Quarter of 2025

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

•Retail Revenues increased $121 million primarily due to the following:

•A $79 million increase in weather-normalized revenues primarily in the commercial class.

•A $47 million increase in fuel revenues.

•An $8 million increase in rider revenues.

•A $6 million increase due to a decrease in regulatory provisions for refund.

These increases were partially offset by:

•An $8 million decrease in weather-related usage primarily due to a 21% decrease in cooling degree days.

•Off-system Sales decreased $38 million primarily due to Rockport Plant, Unit 2 merchant sales and economic hedging activity.

•Transmission Revenues decreased $16 million primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $20 million primarily due to an increase in recoverable fuel and purchased power costs, partially offset by a decrease in Rockport Plant, Unit 2, merchant generation fuel costs.

•Purchased Electricity from AEP Affiliates expenses decreased $8 million primarily due to a decrease in purchased electricity from AEGCo.

•Other Operation and Maintenance expenses increased $17 million primarily due to a $14 million increase in transmission expenses primarily due to an $8 million increase in recoverable PJM expenses and a $6 million increase due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

71

•Depreciation and Amortization increased $9 million primarily due to a higher depreciable base.

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

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

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

•A $3 million increase due to an increase in pretax book income.

•A $3 million increase due to an increase in state taxes.

•A $3 million increase due to a decrease in PTCs.

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025

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

•Retail Revenues increased $249 million primarily due to the following:

•A $134 million increase in weather-normalized margins primarily in the commercial class.

•A $65 million increase in fuel revenues.

•A $55 million increase in rider revenues.

•A $15 million increase due to a decrease in regulatory provisions for refund.

These increases were partially offset by:

•A $10 million decrease in weather-related usage primarily due to a 20% decrease in cooling degree days.

•Off-system Sales increased $44 million primarily due to Rockport Plant, Unit 2 merchant sales during Winter Storm Fern in January 2026, partially offset by a decrease in merchant sales and economic hedging activity.

•Transmission Revenues decreased $13 million primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•Other Revenues decreased $7 million primarily due to a decrease in River Transportation Division (RTD) barging revenues.

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

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $76 million primarily due to an increase in recoverable fuel and purchased power costs, partially offset by a decrease in Rockport Plant, Unit 2, merchant generation fuel costs.

•Purchased Electricity from AEP Affiliates decreased $7 million primarily due to a decrease in purchased electricity from AEGCo.

•Other Operation and Maintenance expenses increased $50 million primarily due to the following:

•A $26 million increase in transmission expenses primarily due to a $17 million increase in recoverable PJM expenses and a $6 million increase due to the June 2025 FERC order related to the treatment of stand-alone NOLCs in transmission formula rates.

•A $7 million increase in distribution expenses primarily due to an increase in vegetation management costs and other distribution-related expenses.

•A $7 million increase in administrative and general expenses.

•A $6 million increase in demand side management expenses.

•A $5 million increase in steam generation expenses primarily due to the acquisition of the Oregon Clean Energy Center in March 2026.

These increases were partially offset by:

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

•A $5 million decrease in non-utility operation expenses due to a decrease in RTD barging expenses.

•Depreciation and Amortization expenses increased $16 million primarily due to the following:

•An $11 million increase due to a higher depreciable base.

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

These increases were partially offset by:

•A $6 million decrease due to Michigan PTC deferral activity.

•Other Income increased $7 million primarily due to an increase in AFUDC due to a higher AFUDC base and an increase in equity return rates.

•Interest Expense increased $18 million primarily due to higher long-term debt balances.

•Income Tax Expense increased $59 million primarily due to the following:

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

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

72

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2026		2025		2026		2025
REVENUES
Electric Generation, Transmission and Distribution	$	811	$	736	$	1,772	$	1,495
Sales to AEP Affiliates	2		2		7		6
(Provision for)/Reversal of - Revenue Refund – Affiliated	(4)		9		(4)		8
Provision for Refund – Nonaffiliated	(23)		(26)		(71)		(84)
Other Revenues – Affiliated	13		14		27		30
Other Revenues – Nonaffiliated	1		2		2		5
TOTAL REVENUES	800		737		1,733		1,460
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	152		132		384		308
Purchased Electricity from AEP Affiliates	58		66		135		142
Other Operation	202		177		390		348
Maintenance	80		88		156		148
Depreciation and Amortization	138		129		269		253
Taxes Other Than Income Taxes	26		22		50		48
TOTAL EXPENSES	656		614		1,384		1,247
OPERATING INCOME	144		123		349		213
Other Income (Expense):
Other Income	8		4		16		9
Non-Service Cost Components of Net Periodic Benefit Cost	3		5		7		10
Interest Expense	(49)		(39)		(92)		(74)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	106		93		280		158
Income Tax Expense (Benefit)	9		(31)		35		(24)
NET INCOME	$	97	$	124	$	245	$	182
The common stock of I&M is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

73

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Three and Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2026		2025		2026		2025
Net Income	$	97	$	124	$	245	$	182
OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2026 and 2025, Respectively, and $0 and $0 for the Six Months Ended June 30, 2026 and 2025, Respectively	—		—		—		—
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2026 and 2025, Respectively, and $0 and $0 for the Six Months Ended June 30, 2026 and 2025, Respectively	—		—		—		—
TOTAL OTHER COMPREHENSIVE INCOME	—		—		—		—
TOTAL COMPREHENSIVE INCOME	$	97	$	124	$	245	$	182
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

74

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2024	$	57	$	1,012	$	2,328	$	—	$	3,397
Common Stock Dividends					(50)				(50)
Net Income					58				58
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2025	57		1,012		2,336		—		3,405
Capital Contribution from Parent			7						7
Net Income					124				124
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2025	$	57	$	1,019	$	2,460	$	—	$	3,536
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2025	$	57	$	1,033	$	2,692	$	2	$	3,784
Net Income					148				148
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2026	57		1,033		2,840		2		3,932
Capital Contribution from Parent			25						25
Common Stock Dividends					(50)				(50)
Net Income					97				97
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2026	$	57	$	1,058	$	2,887	$	2	$	4,004
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

75

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2026 and December 31, 2025

(in millions)

(Unaudited)

	June 30,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	2	$	2
Advances to Affiliates	63		192
Accounts Receivable:
Customers	110		103
Affiliated Companies	87		90
Accrued Unbilled Revenues	—		17
Miscellaneous	14		2
Total Accounts Receivable	211		212
Fuel	65		61
Materials and Supplies	241		222
Risk Management Assets	22		10
Accrued Tax Benefits	31		32
Prepayments and Other Current Assets	82		53
TOTAL CURRENT ASSETS	717		784
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation	6,212		5,483
Transmission	2,155		2,055
Distribution	3,950		3,823
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel)	1,389		1,058
Construction Work in Progress	541		403
Total Property, Plant and Equipment	14,247		12,822
Accumulated Depreciation, Depletion and Amortization	5,207		4,878
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	9,040		7,944
OTHER NONCURRENT ASSETS
Regulatory Assets	553		585
Spent Nuclear Fuel and Decommissioning Trusts	5,241		4,916
Operating Lease Assets	46		52
Deferred Charges and Other Noncurrent Assets	344		344
TOTAL OTHER NONCURRENT ASSETS	6,184		5,897
TOTAL ASSETS	$	15,941	$	14,625
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

76

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

June 30, 2026 and December 31, 2025

(dollars in millions)

(Unaudited)

	June 30,		December 31,
	2026		2025
CURRENT LIABILITIES
Accounts Payable:
General	$	304	$	232
Affiliated Companies	110		125
Long-term Debt Due Within One Year – Nonaffiliated    (June 30, 2026 and December 31, 2025 Amounts Include $91 and $117,    Respectively, Related to DCC Fuel)	91		117
Customer Deposits	56		55
Accrued Taxes	98		112
Accrued Interest	55		42
Obligations Under Operating Leases	15		17
Regulatory Liability for Over-Recovered Fuel Costs	97		19
Other Current Liabilities	217		230
TOTAL CURRENT LIABILITIES	1,043		949
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	4,055		3,444
Deferred Income Taxes	1,216		1,219
Regulatory Liabilities and Deferred Investment Tax Credits	3,317		2,938
Asset Retirement Obligations	2,208		2,165
Obligations Under Operating Leases	32		37
Deferred Credits and Other Noncurrent Liabilities	66		89
TOTAL NONCURRENT LIABILITIES	10,894		9,892
TOTAL LIABILITIES	11,937		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	1,058		1,033
Retained Earnings	2,887		2,692
Accumulated Other Comprehensive Income (Loss)	2		2
TOTAL COMMON SHAREHOLDER’S EQUITY	4,004		3,784
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	15,941	$	14,625
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

77

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	Six Months Ended June 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	245	$	182
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	269		253
Deferred Income Taxes	(10)		(46)
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net	37		(23)
Allowance for Equity Funds Used During Construction	(12)		(8)
Mark-to-Market of Risk Management Contracts	(12)		7
Amortization of Nuclear Fuel	64		52
Deferred Fuel Over/Under-Recovery, Net	78		9
Change in Other Noncurrent Assets	(26)		(14)
Change in Other Noncurrent Liabilities	94		55
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	10		(10)
Fuel, Materials and Supplies	(18)		26
Accounts Payable	22		28
Accrued Taxes, Net	(13)		(1)
Other Current Assets	11		3
Other Current Liabilities	(5)		(14)
Net Cash Flows from Operating Activities	734		499
INVESTING ACTIVITIES
Construction Expenditures	(367)		(306)
Change in Advances to Affiliates, Net	129		—
Purchases of Investment Securities	(1,249)		(1,330)
Sales of Investment Securities	1,209		1,294
Acquisitions of Generation Facilities	(965)		—
Acquisitions of Nuclear Fuel	(51)		(45)
Other Investing Activities	9		27
Net Cash Flows Used for Investing Activities	(1,285)		(360)
FINANCING ACTIVITIES
Capital Contribution from Parent	25		7
Issuance of Long-term Debt – Nonaffiliated	640		249
Change in Advances from Affiliates, Net	—		(101)
Retirement of Long-term Debt – Nonaffiliated	(63)		(240)
Principal Payments for Finance Lease Obligations	(2)		(3)
Dividends Paid on Common Stock	(50)		(50)
Other Financing Activities	1		1
Net Cash Flows from (Used for) Financing Activities	551		(137)
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	$	70	$	72
Noncash Acquisitions Under Finance Leases	1		1
Construction Expenditures Included in Current Liabilities as of June 30,	99		82
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30,	33		33
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

78

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  June 30,		Six Months Ended  June 30,
	2026	2025	2026	2025
	(in millions of KWhs)
Retail:
Residential	2,952	3,024	6,953	7,119
Commercial	8,251	6,323	15,970	11,812
Industrial	3,727	3,748	7,105	7,134
Miscellaneous	23	25	51	53
Total Retail (a)	14,953	13,120	30,079	26,118
Wholesale (b)	256	464	899	1,131
Total KWhs	15,209	13,584	30,978	27,249

(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  June 30,		Six Months Ended  June 30,
	2026	2025	2026	2025
	(in degree days)
Actual – Heating	132	170	1,996	2,077
Normal – Heating	172	173	1,991	1,993
Actual – Cooling	309	336	321	342
Normal – Cooling	325	323	328	325

79

Ohio Power Company and Subsidiaries
Reconciliation of 2025 to 2026
Net Income
(in millions)
	Three Months Ended  June 30,		Six Months Ended  June 30,
2025 Net Income	$	103	$	166
Changes in Revenues:
Retail Revenues	90		142
Off-system Sales	(7)		18
Transmission Revenues	13		20
Other Revenues	(3)		(6)
Total Change in Revenues	93		174
Changes in Expenses and Other:
Purchased Electricity for Resale	17		13
Purchased Electricity from AEP Affiliates	(1)		(5)
Other Operation and Maintenance	(90)		(98)
Depreciation and Amortization	4		(13)
Taxes Other Than Income Taxes	(28)		(25)
Other Income	—		(1)
Allowance for Equity Funds Used During Construction	(1)		(1)
Non-Service Cost Components of Net Periodic Benefit Cost	(2)		3
Interest Expense	3		1
Total Change in Expenses and Other	(98)		(126)
Income Tax Expense	11		13
Equity Earnings of Unconsolidated Subsidiaries	—		(1)
2026 Net Income	$	109	$	226

Second Quarter of 2026 Compared to Second Quarter of 2025

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

•Retail Revenues increased $90 million primarily due to the following:

•A $79 million increase in rider revenues.

•A $9 million increase due to higher prices for purchased power to serve OPCo’s SSO customers.

•Off-system Sales decreased $7 million primarily due to decreased sales of OVEC purchased power driven by lower market prices.

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

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

•Purchased Electricity for Resale expenses decreased $17 million primarily due to the following:

•A $23 million decrease in OVEC purchased power costs.

This decrease was partially offset by:

•A $7 million increase in recoverable auction purchases to serve SSO customers.

•Other Operation and Maintenance expenses increased $90 million primarily due to the following:

•A $75 million increase primarily due to recoverable PJM transmission expenses.

•A $6 million increase primarily due to recoverable distribution vegetation management expenses.

80

•Taxes Other Than Income Taxes increased $28 million primarily due to the following:

•A $23 million increase in property taxes.

•A $5 million increase in state excise taxes due to increased billed KWhs.

•Income Tax Expense decreased $11 million primarily due to Excess ADIT credits refunded to customers as approved in the 2025 base rate case.

Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025

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

•Retail Revenues increased $142 million primarily due to the following:

•A $75 million increase in rider revenues.

•A $60 million increase due to higher prices for purchased power to serve OPCo’s SSO customers.

•A $10 million increase in weather-normalized revenues primarily in the residential class.

These increases were partially offset by:

•A $20 million decrease in weather-related usage driven by a 6% decrease in cooling degree days.

•Off-system Sales increased $18 million primarily due to increased sales of OVEC purchased power driven by higher market prices and volume.

•Transmission Revenues increased $20 million primarily due to continued transmission investment.

•Other Revenues decreased $6 million primarily due to lower third-party Legacy Generation Resource Rider revenues related to the recovery of OVEC costs.

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

•Purchased Electricity for Resale expenses decreased $13 million primarily due to the following:

•A $44 million decrease as a result of legislation approved in Ohio in 2025 related to the elimination of OPCo’s ability to recover from customers, or refund to, the difference between purchased power expenses from OVEC.

•A $30 million decrease in OVEC purchased power costs.

These decreases were partially offset by:

•A $58 million increase in recoverable auction purchases to serve SSO customers.

•Purchased Electricity from AEP Affiliates expenses increased $5 million primarily due to an increase in recoverable purchases to serve SSO customers.

•Other Operation and Maintenance expenses increased $98 million primarily due to the following:

•A $65 million increase primarily due to a $50 million increase in recoverable PJM transmission expenses and an $11 million increase in recoverable transmission storm restoration costs and vegetation management expenses.

•A $15 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.

•A $14 million increase primarily due to recoverable distribution vegetation management expenses.

•Depreciation and Amortization expenses increased $13 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.

•Taxes Other Than Income Taxes increased $25 million primarily due to the following:

•An $18 million increase in property taxes.

•A $7 million increase in state excise taxes due to increased billed KWhs.

•Income Tax Expense decreased $13 million primarily due to the following:

•A $22 million decrease due to an increase in Excess ADIT credits refunded to customers as approved in the 2025 base rate case.

This decrease was partially offset by:

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

81

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

For the Three and Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2026		2025		2026		2025
REVENUES
Electricity, Transmission and Distribution	$	994	$	910	$	2,063	$	1,900
Sales to AEP Affiliates	14		6		27		16
Other Revenues	4		3		7		7
TOTAL REVENUES	1,012		919		2,097		1,923
EXPENSES
Purchased Electricity for Resale	172		189		423		436
Purchased Electricity from AEP Affiliates	16		15		36		31
Other Operation	360		283		683		617
Maintenance	76		63		147		115
Depreciation and Amortization	91		95		202		189
Taxes Other Than Income Taxes	148		120		304		279
TOTAL EXPENSES	863		765		1,795		1,667
OPERATING INCOME	149		154		302		256
Other Income (Expense):
Other Income	—		—		—		1
Allowance for Equity Funds Used During Construction	6		7		13		14
Non-Service Cost Components of Net Periodic Benefit Cost	3		5		12		9
Interest Expense	(37)		(40)		(77)		(78)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	121		126		250		202
Income Tax Expense	12		23		24		37
Equity Earnings of Unconsolidated Subsidiaries	—		—		—		1
NET INCOME	$	109	$	103	$	226	$	166
The common stock of OPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

82

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

COMMON SHAREHOLDER’S EQUITY

For the Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	Common Stock		Paid-in Capital		Retained Earnings		Total
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2024	$	321	$	1,020	$	2,543	$	3,884
Common Stock Dividends					(46)		(46)
Net Income					63		63
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2025	321		1,020		2,560		3,901
Capital Contribution from Parent			2				2
Common Stock Dividends					(25)		(25)
Net Income					103		103
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2025	$	321	$	1,022	$	2,638	$	3,981
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2025	$	321	$	1,030	$	2,800	$	4,151
Capital Contribution from Parent			39				39
Net Income					117		117
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2026	321		1,069		2,917		4,307
Capital Contribution from Parent			65				65
Net Income					109		109
Noncash Distribution to Parent					(2)		(2)
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2026	$	321	$	1,134	$	3,024	$	4,479
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

83

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

June 30, 2026 and December 31, 2025

(in millions)

(Unaudited)

	June 30,		December 31,
	2026		2025
CURRENT ASSETS
Cash and Cash Equivalents	$	5	$	5
Accounts Receivable:
Customers	153		109
Affiliated Companies	134		132
Accrued Unbilled Revenues	7		29
Total Accounts Receivable	294		270
Materials and Supplies	203		191
Prepayments and Other Current Assets	15		25
TOTAL CURRENT ASSETS	517		491
PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission	4,009		3,916
Distribution	8,057		7,661
Other Property, Plant and Equipment	1,307		1,289
Construction Work in Progress	808		811
Total Property, Plant and Equipment	14,181		13,677
Accumulated Depreciation and Amortization	3,048		2,993
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET	11,133		10,684
OTHER NONCURRENT ASSETS
Regulatory Assets	389		326
Operating Lease Assets	46		50
Deferred Charges and Other Noncurrent Assets	446		659
TOTAL OTHER NONCURRENT ASSETS	881		1,035
TOTAL ASSETS	$	12,531	$	12,210
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

84

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

June 30, 2026 and December 31, 2025

(dollars in millions)

(Unaudited)

	June 30,		December 31,
	2026		2025
CURRENT LIABILITIES
Advances from Affiliates	$	64	$	79
Accounts Payable:
General	426		391
Affiliated Companies	194		197
Risk Management Liabilities	4		5
Customer Deposits	107		108
Accrued Taxes	663		858
Obligations Under Operating Leases	13		13
Other Current Liabilities	222		239
TOTAL CURRENT LIABILITIES	1,693		1,890
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated	3,720		3,718
Long-term Risk Management Liabilities	24		28
Deferred Income Taxes	1,359		1,268
Regulatory Liabilities and Deferred Investment Tax Credits	878		893
Obligations Under Operating Leases	33		37
Deferred Credits and Other Noncurrent Liabilities	345		225
TOTAL NONCURRENT LIABILITIES	6,359		6,169
TOTAL LIABILITIES	8,052		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	1,134		1,030
Retained Earnings	3,024		2,800
TOTAL COMMON SHAREHOLDER’S EQUITY	4,479		4,151
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY	$	12,531	$	12,210
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

85

OHIO POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2026 and 2025

(in millions)

(Unaudited)

	Six Months Ended June 30,
	2026		2025
OPERATING ACTIVITIES
Net Income	$	226	$	166
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	202		189
Deferred Income Taxes	55		14
Allowance for Equity Funds Used During Construction	(13)		(14)
Mark-to-Market of Risk Management Contracts	(5)		—
Property Taxes	213		206
Security Deposits	114		49
Change in Regulatory Assets	(50)		13
Change in Other Noncurrent Assets	(40)		28
Change in Other Noncurrent Liabilities	10		(58)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(9)		2
Materials and Supplies	(12)		(19)
Accounts Payable	30		(5)
Customer Deposits	(1)		(15)
Accrued Taxes, Net	(186)		(306)
Other Current Assets	3		7
Other Current Liabilities	(32)		(23)
Net Cash Flows from Operating Activities	505		234
INVESTING ACTIVITIES
Construction Expenditures	(617)		(505)
Change in Advances to Affiliates, Net	—		115
Other Investing Activities	25		27
Net Cash Flows Used for Investing Activities	(592)		(363)
FINANCING ACTIVITIES
Capital Contribution from Parent	104		2
Change in Advances from Affiliates, Net	(15)		203
Principal Payments for Finance Lease Obligations	(2)		(2)
Dividends Paid on Common Stock	—		(71)
Other Financing Activities	—		1
Net Cash Flows from Financing Activities	87		133
Net Increase in Cash and Cash Equivalents	—		4
Cash and Cash Equivalents at Beginning of Period	5		4
Cash and Cash Equivalents at End of Period	$	5	$	8
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	72	$	72
Noncash Acquisitions Under Finance Leases	1		1
Construction Expenditures Included in Current Liabilities as of June 30,	140		121
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 106.

86

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  June 30,		Six Months Ended  June 30,
	2026	2025	2026	2025
	(in millions of KWhs)
Retail:
Residential	1,406	1,319	2,770	2,911
Commercial	1,513	1,485	2,860	2,806
Industrial	1,502	1,483	2,913	2,860
Miscellaneous	329	325	613	604
Total Retail	4,750	4,612	9,156	9,181
Wholesale (a)	17	28	54	85
Total KWhs	4,767	4,640	9,210	9,266

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

Summary of Heating and Cooling Degree Days

	Three Months Ended  June 30,		Six Months Ended  June 30,
	2026	2025	2026	2025
	(in degree days)
Actual – Heating	1	31	761	1,193
Normal – Heating	43	43	1,092	1,081
Actual – Cooling	756	605	850	629
Normal – Cooling	705	709	726	729

87

Public Service Company of Oklahoma
Reconciliation of 2025 to 2026
Net Income
(in millions)
	Three Months Ended  June 30,		Six Months Ended  June 30,
2025 Net Income	$	63	$	91
Changes in Revenues:
Retail Revenues (a)	59		103
Transmission Revenues	(4)		(4)
Other Revenues	(3)		(2)
Total Change in Revenues	52		97
Changes in Expenses and Other:
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation	(8)		(43)
Other Operation and Maintenance	(26)		(63)
Depreciation and Amortization	(7)		(11)
Taxes Other Than Income Taxes	(2)		(7)
Interest Income	—		(2)
Allowance for Equity Funds Used During Construction	(1)		(1)
Non-Service Cost Components of Net Periodic Benefit Cost (Credit)	(5)		(5)
Interest Expense	(14)		(27)
Total Change in Expenses and Other	(63)		(159)
Income Tax Benefit	2		40
2026 Net Income	$	54	$	69

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

Second Quarter of 2026 Compared to Second Quarter of 2025

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

•Retail Revenues increased $59 million primarily due to the following:

•A $64 million increase in rider revenues.

•A $12 million increase in weather-related usage primarily due to a 25% increase in cooling degree days.

These increases were partially offset by:

•A $9 million decrease in weather-normalized revenues primarily in the residential class.

Expenses and Other changed between years as follows:

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $8 million primarily due to a $17 million increase in recoverable PTCs partially offset by a $10 million decrease related to the impact on deferred fuel costs from decreased fuel revenues.

•Other Operation and Maintenance expenses increased $26 million primarily due to the following:

•A $15 million increase in generation expenses primarily due to acquisitions of generation facilities.

•A $9 million increase in employee-related costs.

•A $6 million increase in distribution expenses primarily due to overhead line maintenance.

These increases were partially offset by:

•A $5 million decrease in transmission expenses primarily due to a $19 million decrease related to the June 2025 FERC NOLC order partially offset by a $13 million increase in SPP expenses.

•Depreciation and Amortization expenses increased $7 million primarily due to a higher depreciable base.